|Entered date||Site||Region||Reactor type||Event description|
|ENS 54880||4 September 2020 01:40:00||River Bend||NRC Region 4||River Bend Station experienced an inadvertent initiation and injection of High Pressure Core Spray (HPCS) at 2048 (CDT) on 9/3/2020 while operating at 92% power. Initial investigation indicates a power supply failure in the Division III trip units which feeds HPCS and Division III Diesel Initiation signals. The Control Room Operator responded to the event by taking manual control of Feedwater Level Control to maintain Reactor Water Level nominal values. The HPCS injection valve was open for approximately 25 seconds before operators manually closed the valve. 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 52 minutes after the event. The HPCS system has remained inoperable. The event is being reported in accordance with 10 CFR 50.72(b)(3)(v)(D) as a condition that caused loss of function of the HPCS System. No radiological releases have occurred due to this event. The Senior NRC Resident Inspector has been notified. These conditions put the unit in a 14-day LCO (3.5.1) for HPCS Inoperability and a 30-day LCO (3.7.1) for one Standby Service Water Pump Inoperable (2C).|
|ENS 54849||21 August 2020 12:53:00||River Bend||NRC Region 4||On August 21, 2020 at 0908 CDT, River Bend Station was operating at 100% reactor power when reactor recirculation pump 'B' tripped. At 0918 CDT, a manual reactor scram was inserted at 67% reactor power after receiving indications of thermal hydraulic instability as indicated by flux oscillations on the period based detection system (PBDS) and average power range monitors (APRMs). All control rods fully inserted and there were no complications. All systems responded as designed. Currently River Bend Station Unit 1 is stable and pressure is being maintained using turbine bypass valves. This event is being reported under 10 CFR 50.72(b)(2)(iv)(B), as any event or condition that results in actuation of the reactor protection system (RPS) when the reactor is critical and 10 CFR 50.72 (b)(3)(iv)(A) Specified System Actuation as result of Group 3 isolations. NRC Resident Inspector has been briefed on this event. No radiological releases have occurred due to this event from the unit.|
|ENS 54470||9 January 2020 19:25:00||River Bend||NRC Region 4||The Division I Control Building Chiller 'A' failed to start during post maintenance testing. By design, the Division II Control Building Chiller 'B' should have started automatically but did not. Operators then manually placed the Division I Control Building Chiller 'C' in service. This condition rendered both Divisions of the Control Building Air Conditioning System Inoperable. The applicable LCO was entered and exited 10 minutes later with all required actions and completion times met. The cause of the failure is not known at this time. The plant was at 100% power at the time of the event and is currently stable at 100% power. The NRC Resident Inspector has been notified.|
|ENS 54348||24 October 2019 16:25:00||River Bend||NRC Region 4||At 1035 CDT the Automatic Depressurization System (ADS) was rendered inoperable due to the failure of the 'A' Safety Vent Valve (SVV) Compressor (SVV-C4A) to manually start with SVV-C4B tagged out. System pressure slowly dropped below 131 psig (normal pressure is 165 psig). This caused the ADS safety relief valves to be declared inoperable. The station entered Technical Specification 3.5.1 Condition G. The Required Action was to be in Mode 3 in 12 hours. As a result, the station was in a condition that could have prevented the fulfillment of a safety function. The breaker for SVV-C4B was reset and the clearance for SVV-V4B was released. System pressure was restored to greater than 131 psig at 1116 CDT which allowed exit of the action statement to be in Mode 3 in 12 hours. System parameters are currently stable in the normal pressure range. Investigation for the cause of the system failure is ongoing. No radiological releases have occurred due to this event from the unit. The licensee notified the NRC Resident Inspector.|
|ENS 54338||18 October 2019 10:45:00||River Bend||NRC Region 4|
EN Revision Text: INADVERTENT OPENING OF MAIN TURBINE BYPASS VALVES POTENTIONALLY AFFECTED SAFE SHUTDOWN CAPABILITY At 0207 (CDT), the Bypass Electro-Hydraulic Control (EHC) system was secured for planned maintenance. When the Bypass EHC pumps were secured, both of the Main Turbine Bypass Valves unexpectedly opened to approximately 4.5 percent. Plant parameters indicated no impact to Turbine Control Valve position, Reactor Pressure, Turbine First Stage Pressure, or Main Steam Line flows. There were no other abnormal indications noted. With the Turbine Bypass Valves partially open, there is a potential to affect instrumentation that trips on high Turbine First Stage Pressure. Therefore, this event is being reported as a potential loss of Safety Function. At 0256, the Bypass EHC system pumps were restored and the Turbine Bypass Valves Closed. No radiological releases have occurred due to this event from the unit. The licensee has notified the NRC Resident Inspector.
This Event Notification was contingent on the Main Turbine Bypass Valves opening which resulted in the inoperability of Turbine First Stage Pressure monitoring instrumentation. A detailed review of system design and plant parameter trends has confirmed that the Main Turbine Bypass Valves remained closed for the duration of the event, permitting the instrumentation systems dependent on accurate Turbine First Stage Pressure to perform their respective design and licensing basis functions. Valve drift in the open direction was observed by position indication when hydraulic control pressure was removed. However, the valves were at an over-travel closed position prior to the event allowing the valves to settle at a position where an internal spring could provide closing force to the valve disc. Multiple plant parameter trends including Turbine First Stage Pressure, Reactor Pressure, Main Steam Line flows, and Main Turbine Bypass Valve discharge line temperatures indicate that the Main Turbine Bypass Valves remained closed for the duration of the event. The licensee has notified the NRC Resident Inspector. Notified R4DO (O'Keefe).
|ENS 54121||17 June 2019 12:56:00||River Bend||NRC Region 4||This 60-day telephone notification is being made in accordance with the reporting requirements specified by 10 CFR 50.73(a)(1) and 10 CFR 50.73(a)(2)(iv)(A) to describe an invalid actuation of a general containment isolation signal affecting multiple systems. On April 30, 2019, at approximately 0650 CDT, a level 2 containment isolation signal was introduced when a fuse for the Nuclear Steam Supply Shutoff System was removed for a maintenance clearance. The level 2 containment isolation signal caused a trip of the Division I DC bus back-up charger, leaving only the Division I battery to carry the DC bus. At 0707 CDT the bus was de-energized when another unrelated clearance opened the battery supply breaker to the DC bus causing another containment isolation signal. This event did not affect Shutdown Cooling or any other protected Safety Related Equipment. The containment isolation signals caused an isolation of the systems listed below. All components that were not removed from service, gagged in position, already in the expected position due to plant conditions, or de-energized due to plant condition performed as designed. Containment Isolation valves for the following systems isolated as expected: Drywell and Containment Floor Drains, Drywell and Containment Equipment Drains, Condensate Makeup, Fire Protection Water, Service Air, Instrument Air, Reactor Water Cleanup, Spent Fuel Cooling and Cleanup, Reactor Plant Component Cooling Water, Chilled Water, Reactor Recirculation, Main Steam Drains, Reactor Building Ventilation, and Fuel Building Ventilation. The licensee notified the NRC Resident Inspector.|
|ENS 54096||1 June 2019 03:15:00||River Bend||NRC Region 4|
At 2345 CDT at River Bend Station (RBS) Unit 1, a manual Reactor scram was inserted in anticipation of receiving an automatic Reactor Water Level 3 (9.7") scram due to the isolation of the 'B' Heater String with the 'A' Heater String already isolated. The 'B' heater string isolation caused loss of suction and subsequent trip of the running Feed Water Pumps 'A' and 'C'. All control rods fully inserted with no issues. Subsequently Reactor level was controlled by the Reactor Core Isolation Cooling (RCIC) system. Feed Water Pump 'C' was restored 4 minutes after the initial trip and the RCIC system secured. Currently RBS-1 is stable and is being cooled down using Turbine Bypass Valves. No radiological releases have occurred due to this event from the unit. The plant is currently under a normal shutdown electrical lineup. The licensee notified the NRC Resident Inspector.
This amended event notification is being made to provide additional information that was not included in the original notification made on 6/1/19 at 0315 EDT. This event was reportable under 10 CFR 50.72(b)(3)(iv)(A) which was not annotated or described in the original report. Forty-two minutes after the Feed Water Pump 'C' was started, the pump tripped causing a Reactor Water Level 3 (9.7") RPS actuation. Feed Water was restored five minutes later using the Feed Water Pump 'A'. The NRC Resident Inspector has been notified. Notified the R4DO (Warnick).
|ENS 54031||26 April 2019 20:19:00||River Bend||NRC Region 4||At 1147 (CDT) on 4/26/19, a through wall leak (reported as 1 drop every 1 to 2 minutes) was identified and confirmed by operation and NDE (Non-Destructive Examination) personnel on the Standby Liquid Control injection line during pressure testing activities. The line is 1.5 inch in diameter and classified as an ASME Section Ill, Class 1 line. The leak is currently isolated from the reactor vessel by a danger tagged manual valve. The licensee notified the NRC Resident Inspector.|
|ENS 53756||28 November 2018 05:40:00||River Bend||NRC Region 4|
EN Revision Text: INOPERABILITY OF EQUIPMENT FOR CONTROL OF RADIOLOGICAL RELEASE At 2130 CST on 11/27/2018, Division 1 Main Steam Positive Leakage Control System (MS-PLCS) was declared inoperable because of a leaking check valve that caused excessive cycling of the associated air compressor. Division 2 MS-PLCS had been declared inoperable on 11/27/2018 at 1400 CST when a pressure control valve in the system exceeded the maximum allowable stroke time. Because MS-PLCS supplements the isolation function of the main steam isolation valves (MSIVs) by processing fission products that could leak through the closed MSIVs, both divisions of MS-PLCS inoperable at the same time represents a condition that could prevent the fulfillment of a safety function of an SSC (Structures, Systems and Components) that is needed to control the release of radioactive material. The station diesel air compressor is available to supply backup air to the safety relief valves as required by the Technical Requirements Manual." (This is associated with operability of the safety relief valves, due to the inoperable MS-PLCS air compressor.) The unit is in a 7 day shutdown Limiting Condition for Operation (LCO), 1-TS1-18-Div 1 & 2 MSPLCS-685, for the two divisions of MS-PLCS being inoperable. The licensee notified the NRC Resident Inspector.
This event was initially reported under 10 CFR 50.72(b)(3)(v)(C) as a condition that could have prevented the Main Steam Positive Leakage Control System (MS-PLCS) from fulfilling its safety function to control the release of radioactive material. Division I was declared inoperable due to a failed component. Division II was declared inoperable due to a pressure control valve in the system exceeding the maximum allowable time to close by 0.50 seconds. An engineering evaluation has since been performed and concluded that the 2 second maximum allowable time to close was based on the pressure control valve being classified as a rapid closure valve and was established from the original baseline data of 0.50 seconds. This baseline data is an administrative target value per the In-Service Testing Program. There are no technical specification requirements associated with the 2 second closure time. The engineering evaluation also determined that the volume of air supplied through the pressure control valve during the extra 0.50 seconds of valve closure would have an inconsequential effect on the pressure within the volume of leakage barrier between the Main Steam Isolation Valves associated with the MS-PLCS pressure control valve or have any effect on containment over-pressurization. Based on the information provided by the engineering evaluation, the Division II MS-PLCS has been declared operable-degraded non-conforming since time of initial discovery. Consequently, this event is not reportable as a condition that could have prevented the Main Steam Positive Leakage Control System (MS-PLCS) from fulfilling its safety function. The (NRC) Resident Inspector has been notified via e-mail. Notified the R4DO (Gaddy).
|ENS 53732||10 November 2018 04:35:00||River Bend||NRC Region 4|
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 53622||25 September 2018 20:25:00||River Bend||NRC Region 4||At 1200 CDT on September 25, 2018, while the plant was in MODE 1 at 90 percent power, it was identified that an additional condition existed which had not previously been considered in developing the compensatory measures implemented for design flaws and single point vulnerabilities associated with the Control Building Chilled Water System. Specifically, a 20 minute 'quick restart timer' on Control Building Chillers that have analog control systems (HVK-CHL1A & 1B) would prevent the chillers from starting in specific scenarios. The recommended compensatory actions to address the new condition were implemented at 1235 CDT on September 25, 2018. Currently the Chilled Water System is otherwise operating as designed. Operator actions are in place to ensure the plant meets all required design safety system functions. Work is currently underway to identify and correct all design vulnerabilities. The (NRC) Senior Resident Inspector has been notified. This was identified by engineering during an extended condition search.|
|ENS 53382||4 May 2018 13:50:00||River Bend||NRC Region 4||GE-6||During performance of an extent of condition evaluation of protection for Technical Specification (TS) equipment from the damaging effects of tornados, River Bend Station identified non-conforming conditions in the plant design such that specific TS equipment is considered to not be adequately protected from tornado missiles. The reportable condition is postulated by tornado missiles entering the Diesel Generator Building through conduit and pipe penetrations. A tornado could generate multiple missiles capable of striking Division 1, Division 2, and Division 3 Diesel Generator support equipment rendering all Safety Related Diesel Generators inoperable. This condition is reportable per 10 CFR 50.72(b)(3)(ii)(B) for any event or condition that results in the nuclear power plant being in an unanalyzed condition that significantly degrades plant safety, and per 10 CFR 50.72(b)(3)(v) for 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, or (D) Mitigate the consequences of an accident. This condition was identified as part of an on-going extent of condition review of potential tornado missile related site impacts. Enforcement discretion per Enforcement Guidance Memorandum EGM 15-002 has been implemented and required actions taken. Corrective actions will be documented in a follow-on licensee event report. The licensee has notified the NRC Resident Inspector.|
|ENS 53365||26 April 2018 18:50:00||River Bend||NRC Region 4||GE-6||River 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 53324||11 April 2018 10:14:00||River Bend||NRC Region 4||GE-6||At time 0150 CDT on April 11, 2018, a condition was identified that could impair the ability of the Control Building Air Conditioning System to perform its design function. Engineering determined that the time delay relays HVKA11-80YB or HVKA11-80YD (Division II chilled water LOW FLOW relays) could fail in a manner that challenges the design safety function of the Control Building Chilled Water System during a Loss of Offsite Power (LOP) Event. A failure of the time delay relay HVKA11-80YB or HVKA11-80YD (Division II chilled water LOW FLOW relays) to provide the time delay function would cause both the Division I and Division II HVK chilled water pumps to start after a LOP, which in turn could hinder the auto start of either Division I or Division II chillers. Currently the Chilled Water System is otherwise operating as designed. All operator actions are in place to ensure the plant meets all required designed safety system functions. Work is currently underway to correct this design vulnerability. The NRC Resident Inspector has been notified of this condition.|
|ENS 53192||1 February 2018 14:23:00||River Bend||NRC Region 4||GE-6|
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.
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 52995||27 September 2017 14:26:00||River Bend||NRC Region 4||GE-6||Security personnel reported to the Main Control Room that at time 1000 CDT (on 9/27/2017), an alarm indicated that a secondary containment door was open beyond the normal delay time allowed for entry and exit. Security personnel responded and found the door open and unattended with the dogs extended meaning that the door was unable to be closed. Security personnel secured the door at time 1004 CDT. No deficiencies were found with the door. The fact the door was open and unattended beyond the time allowed for normal entry and exit results in Technical Specification 126.96.36.199 'Secondary Containment-Operating,' not being met because surveillance requirement SR 188.8.131.52.3 is not met. This surveillance requires that doors be closed except during normal entry and exit. By definition in NUREG-1022, when Secondary Containment is inoperable, it is not capable of performing its specified safety function which in turn makes this condition reportable in accordance with 10 CFR 50.72(b)(3)(v)(D). The NRC Resident Inspector has been notified.|
|ENS 52915||18 August 2017 23:41:00||River Bend||NRC Region 4||GE-6||At 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 52908||15 August 2017 20:21:00||River Bend||NRC Region 4||GE-6||A blind sample provided from an independent laboratory to fleet testing facility was returned with inaccurate results. This is in violation of 10 CFR 26.719(c)(3) and requires a 24-hour report. The licensee has notified the NRC Resident Inspector.|
|ENS 52897||10 August 2017 17:14:00||River Bend||NRC Region 4||GE-6||A non licensed supervisor confirmed positive for alcohol during a fitness for duty test. The employee's access has been terminated. The NRC Resident Inspector has been notified.|
|ENS 52825||23 June 2017 23:58:00||River Bend||NRC Region 4||GE-6||While 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.|
|ENS 52631||23 March 2017 07:24:00||River Bend||NRC Region 4||GE-6|
River Bend Station personnel declared the High Pressure Core Spray (HPCS) system inoperable at 0256 on 3/23/2017. During performance of the HPCS Pump and Valve Operability Test, the operators observed an unusual system response after E22-MOVF023 (HPCS Test Return to the Suppression Pool) was stroked closed. A field check showed that the key that connects the E22-MOVF023 valve stem to the anti-rotation device had become dislodged. E22-MOVF023 is a Primary Containment Isolation Valve (PCIV) and is designed to close automatically on an ECCS (Emergency Core Cooling System) initiation signal to ensure that injection flow is directed to the reactor vessel. Technical Specification (TS) 184.108.40.206 requires that containment penetrations associated with an inoperable PCIV be isolated. E22-MOVF023 was declared inoperable at 0028. Operators were unable to close or demonstrate that E22-MOVF023 was fully closed as required by TS 220.127.116.11 and proceeded to isolate the associated containment penetration by closing other system valves. This action was completed at 0320. The net effect of the actions taken to isolate the containment penetration is that HPCS is inoperable as of 0256. This results in 14 day LCO. The licensee has notified the NRC Resident Inspector.
The Event Time was 0028 CDT rather than 0256 CDT. "The scheduled surveillance test of the high pressure core spray system was initiated at 2355 CDT on March 22, and the pump was secured at 0028 CDT on March 23. The inspection of the HPCS test return valve to the suppression pool occurred at 0050 CDT, and it was at that point that an apparent malfunction of the valve had occurred to the extent that it did not appear to be able to perform its safety function to close upon receipt of a design basis system initiation signal. Thus, the event time for this condition would be more accurately defined as 0028 CDT. Notified R4DO (James Drake) via e-mail.
|ENS 52602||10 March 2017 11:41:00||River Bend||NRC Region 4||GE-6||At 0714 CST on March 10, 2017, with the unit in Mode 1 at approximately 17% power, a manual actuation of the reactor protection system (RPS) was initiated due to rising reactor pressure caused by the closure of the Main Turbine Control Valves (MTCV's). The cause of the closure of the MTCV's is under investigation. The unit is currently stable in Mode 3. All control rods inserted as expected; water level control is stable in the normal control band and reactor pressure is being maintained with steam line drains (aligned to the main condenser). The NRC Senior Resident Inspector has been notified.|
|ENS 52568||20 February 2017 17:24:00||River Bend||NRC Region 4||GE-6|
During the investigation associated with Event Notification 52566 that was reported on 2/18/17, it has been determined that an unanalyzed condition (new potential single failure concerns) exists. This condition exists only during periods of manually alternating divisions of Control Building Chilled Water systems; in that potential failures of Control Room Air Handling Units (HVC-ACU1A or B) or Control Building Air Handling Units (HVC-ACU2A or B) could fail in a manner that challenges the operability of the alternate division.
As reported in Event Notification 52566, the impact of this event was a loss of safety function cooling to both Division 1 and 2 AC/DC power distribution systems and Divisions 1 and 2 Control Room Fresh Air systems. Contingency actions are in development to address the impact of the potential failure mode. The plant remains in a planned refueling outage, Mode 5 with water level greater than 23' above the vessel flange. Shutdown cooling remains in service and is not affected by this issue. Investigation is ongoing. The NRC Resident Inspector has been briefed on this issue.
The licensee updated information in the first paragraph of the original above with the following: During the investigation associated with Event Notification 52566 that was reported on 2/18/17, it has been determined that an unanalyzed condition (new potential single failure concerns) exists. During periods of alternating divisions of Control Building Chilled Water systems, the potential exists for failures of Control Room Air Handling Units (HVC-ACU1A or B) or Control Building Air Handling Units (HVC-ACU2A or B) that could challenge the operability of the alternate division. The licensee notified the NRC Resident Inspector of this update. Notified R4DO (Gepford)
After further investigation it has been determined that an unanalyzed condition (new single failure concerns) exists with the dampers associated with the Control Room Fresh Air system. The potential exists for damper failures for HVC-FN1A Control Room Booster Fan 1A motor and HVC-FN1B Control Room Booster Fan 1B motor that could challenge the operability of the alternate division. Contingency actions are in development to address the impact of the potential failure mode. The plant remains in a planned refueling outage, Mode 5, with water level greater than 23 feet above the vessel flange. Shutdown cooling remains in service and is not affected by this issue. Investigation is ongoing. The NRC Resident Inspector has been briefed on this issue. Notified R4DO (Pick).
|ENS 52566||19 February 2017 00:21:00||River Bend||NRC Region 4||GE-6||At 1537 CST on February 18th, 2017, while the plant was in MODE 5 for a scheduled refueling outage, the main control room experienced a loss of Control Building chilled water and the associated ventilation systems while attempting to alternate divisions for testing. An equipment malfunction in a breaker supplying a Main Control Room air handling unit caused a loss of both divisions of Control Room and Control Building chilled water systems and associated ventilation systems until 1737 CST. During the period between 1537 and 1737, neither division of Control Building chilled water was able to perform the support function for cooling Division 1 and 2 AC and DC power distribution systems or the support function for the Division 1 and 2 Control Room Fresh Air systems. Shutdown Cooling remained in service throughout this event. There were no apparent effects on any plant equipment from the loss of chill water and ventilation. The Division 1 Control Building chill water and ventilation system was returned to service at 1737 on February 18, 2017. Actions were initiated to terminate the OPDRV (operations with potential to drain the reactor vessel) that was in progress at the time of the event by installing the reactor recirculation pump seal. As a conservative measure, actions were initiated to set containment and containment was set at 2145. Troubleshooting and analysis is ongoing to confirm and correct the problem which caused the loss of the Control Building chill water and ventilation system. This condition is being reported in accordance with 10 CFR 50.72(b)(3)(v)(B). The NRC Senior Resident Inspector has been notified.|
|ENS 52517||29 January 2017 16:30:00||River Bend||NRC Region 4||GE-6||At 0209 CST, on January 29, 2017, while the plant was in MODE 4 for a refueling outage, the main control room crew removed the AC/DC inverter in the Division 1, 120 VAC electrical distribution system from service due to an equipment malfunction. Removing the inverter from service caused a loss of the associated 120 VAC instrument buss. This instrument buss loss caused a trip of the Division 1 Control Building Chill Water and Ventilation system. The Division 2 Control Building Chill Water and Ventilation System was locked out for surveillance testing at the time of the equipment failure. This condition rendered both divisions of Control Building Chill Water and Ventilation Systems unable to perform the support function for cooling Division 1 and 2 AC and DC power distribution systems. These systems are required to support the operability of two required divisions of shutdown cooling. Division 2 Shutdown Cooling System was in service and remained in service through out the event. The Division 2 Control Building Chill Water and Ventilation System was returned to service at 0220 CST on January 29, 2017. Division 1 Control Building Chill Water remains inoperable pending restoration with the installed backup Division 1 DC/AC inverter. Actions are ongoing to place this component in service and restore the associated 120 VAC instrument buss. The equipment malfunction was limited to the Division 1 inverter. The investigation of the inverter failure is ongoing. This condition is being reported in accordance with 10 CFR 50.72(b)(3)(v)(B). The NRC Senior Resident Inspector has been notified.|
|ENS 52293||10 October 2016 14:07:00||River Bend||NRC Region 4||GE-6||At 1032 (CDT) on October 10, 2016, it was determined that a spill of hydraulic oil that occurred earlier in the morning on the site was of sufficient quantity (approximately 60 gallons) to warrant a notification to the Louisiana Department of Environmental Quality. This report will be made within 24 hours of the determination. The spill was the result of a hydraulic system failure on a truck that was on site to pick up non-radioactive trash. The truck was on company property but outside the Security Owner Controlled Area (SOCA). There are no radiological or off-site impacts arising from this event. The spill did not reach surface water and is now contained. This event is being reported in accordance with 10 CFR 50.72(b)(2)(xi) as a condition requiring the notification to State environmental authorities. The NRC Resident Inspector has been notified.|
|ENS 51928||13 May 2016 20:02:00||River Bend||NRC Region 4||GE-6|
At 1200 (CDT) May 13, 2016, while the plant was operating at 100% power, it was brought to the attention of the River Bend Station Main Control Room staff that an existing design inadequacy could prevent both trains of the Standby Gas Treatment System (GTS) from performing its design function. Under certain specific conditions, the installed Masterpact breakers may not close to allow energization of the filter train exhaust fans. A start signal (reactor level 2, drywell pressure 1.68 psid, annulus high radiation, annulus low flow) combined with a trip signal within a certain time differential, could result in a failure of the breakers to close. As a result of this condition, both Standby Gas Trains were declared inoperable, which required entry into LCO 18.104.22.168 Condition C (requires entering Mode 3 in 12 hours). Declaring both trains of Standby Gas Treatment System inoperable resulted in loss of the safety function since a system that has been declared inoperable is one in which the capability has degraded to the point where it cannot perform with reasonable expectation or reliability. The Standby Gas Treatment System (GTS) limits release to the environment of radioisotopes, which may leak from the primary containment, ECCS systems, and other potential radioactive sources to the secondary containment under accident conditions. At 1240 (CDT) May 13, 2016, one division of GTS, GTS 'A', was manually started from the Main Control Room. This action prevents the breaker failure mode, restored the operability of one train and restored the safety function of the GTS system. LCO 22.214.171.124 Condition A (restore Operability in 7 days) is currently entered for Standby Gas Train 'B'. During the 40 minutes of inoperability, both trains of Standby Gas remained available. At no time was the health or safety of the public impacted. This condition is being reported in accordance with 10CFR50.72(b)(3)(v)(C) as an event that could have caused a loss of safety function to control the release of radioactive material. The Senior NRC Resident was notified.
Further review has determined that the design inadequacy discussed in EN #51928 could adversely effect the ability of the main control building heating, ventilation, and air conditioning (HVAC) system to perform its design safety function, based upon a particular sequence of events occurring within a short window of time (approximately 75 milliseconds). River Bend has implemented compensatory actions to ensure operability of the main control building HVAC system. The Resident Inspector has been notified by the licensee. Notified the R4DO (Miller).
|ENS 51899||3 May 2016 01:50:00||River Bend||NRC Region 4||GE-6|
At 2229 (CDT) on 05-02-2016, River Bend Station declared the High Pressure Core Spray system INOPERABLE in accordance with Technical Specification 3.8.9, Condition E (Declare High Pressure Core Spray System and Standby Service Water System Pump 2C inoperable immediately) due to Division 1 Control Room Air Conditioning System HVK-CHL1C being INOPERABLE due to a trip of the chiller on high inboard bearing temperature. Actions taken to exit the LCO: Alternated divisions of Control Room Air Conditioning System to Division 2 HVK-CHL1D in service and Division 1 HVK-CHL1A in standby. The licensee notified the NRC Resident Inspector.
Supplement: An operability evaluation has been performed based on system operating procedures in place at the time of this event, and on calculations regarding heat-up rates of the spaces served by the main control room air conditioning system. Operating procedures already in place on May 2 specified the operator actions required to restore the air conditioning system to service following the unanticipated trip of a chiller. The normal shift complement was on duty at the time of the event, and could have provided an adequate number of operators to accomplish this task. The operability evaluation made no new assumptions regarding availability of operators. The manual actions to be performed for the start of an alternate chiller following a trip of an in-service chiller system have been determined to require 2.15 hours, based on ANSI 58.8 guidance. (ANSI/ANS 58.8, Time Response Design Criteria for Nuclear Safety Related Operator Actions, provides the industry guidance In this regard.) Calculations of building heat-up rates have demonstrated that the loss of the air conditioning system can be sustained for 19 hours before temperatures in the rooms containing the Division 3 electrical equipment that support operability of the HPCS system exceed their maximum allowable ambient value. Based on the conclusions of the operability evaluation, the trip of the 'C' HVK chiller on May 2 had no actual adverse effect on the ability of the electrical distribution systems in the main control building to support the safety function of the HPCS system. Event Notification No. 51899 is hereby withdrawn. The licensee has notified the NRC Resident Inspector. Notified R4DO (Rollins).
|ENS 51784||9 March 2016 16:53:00||River Bend||NRC Region 4||GE-6||On January 10, 2016, at 0243 CST, with the plant in cold shutdown, the primary containment isolation logic was actuated as the result of an invalid signal. This condition occurred while operators were installing electrical jumpers designed to bypass certain isolation signals for the suction valves in the residual heat removal (RHR) system that comprise the shutdown cooling flow path. These jumpers are installed under procedural guidance for the purposes of increasing the reliability of the shutdown cooling loop by disabling isolation signals that are not required to be operable in certain plant operating modes. Although it could not be proven, it appears that inadvertent contact with an energized circuit occurred during the jumper installation, causing a fuse to blow, de-energizing part of the primary isolation logic. This caused the automatic closure of Division 1 suction and return valves in the shutdown cooling loop, as well as valves connecting the reactor plant sampling systems to the RHR system. The main control room crew implemented recovery procedures to restore shutdown cooling to service at 0401 CST, prior to exceeding any temperature limits. This event resulted from the failure to maintain corrective actions in place that were develop after a similar event in 1994. Additionally, the operators were not using the type of jumpers required by the procedure, which likely contributed to the blown fuse. The RHR system operating procedure has been revised to require that the potentially affected valves in the shutdown cooling loop will be de-energized during jumper installation to eliminate the possibility of inadvertent isolation. This is being reported in accordance with 10 CFR 50.73(a)(1) as an invalid actuation of the primary containment isolation logic. During this event, the RCS temperature increased from approximately 130 to 190 degree F. The licensee will notify the NRC Resident Inspector.|
|ENS 51754||24 February 2016 18:16:00||River Bend||NRC Region 4||GE-6||At 1100 CST on February 24, 2016, with the plant in cold shutdown (Mode 4), the shift manager was notified of a condition that could potentially prevent the automatic closure of the circuit breakers powering the emergency ventilation fans in the both the Division 1 and 2 emergency diesel generator rooms. These fans are not in Technical Specifications, however, they provide a support function to the emergency diesel generators, requiring that both diesel generators to be declared inoperable. This inoperability constitutes a condition that could potentially prevent fulfillment of the safety function of onsite AC power sources, and is being reported pursuant to 10 CFR 50.72(b)(3)(v). Four additional breakers are affected by the same condition. These breakers supply power to Division 1 and 2 containment unit coolers and the Division 1 and 2 auxiliary building 141 ft. elevation general area unit coolers. The auxiliary building unit coolers are not in Technical Specifications, however, they provide a support function to the electrical distribution system. The Technical Specification required action is to declare both trains of the residual heat removal system (shutdown cooling mode) inoperable. This inoperability constitutes a condition that could potentially prevent the fulfillment of the decay heat removal safety function, and is being reported pursuant to 10 CFR 50.72(b)(3)(v). Division 2 residual heat removal is operating in shutdown cooling, satisfactorily maintaining reactor coolant temperature. The affected breakers can be manually operated to start/stop their associated equipment, if necessary for operation. This condition was identified during an Engineering review. The licensee has compensatory measures in place. Long term corrective actions are under review. The licensee informed the NRC Resident Inspector.|
|ENS 51701||29 January 2016 23:00:00||River Bend||NRC Region 4||GE-6||On January 29, 2016, at 1518 CST, with the plant in cold shutdown, power was lost on reserve station service (RSS) line no. 1. This is one of two sources of offsite power required by Technical Specifications. The power loss de-energized the Division 1 onsite AC safety-related switchgear, causing an automatic start of the Division 1 emergency diesel generator (EDG). The Division 1 reactor protection system (RPS) bus was also de-energized, causing a half-scram signal. Approximately 8 minutes later, a full actuation of the RPS occurred due to a high water level condition in the control rod drive hydraulic system scram discharge volume header. All reactor control rods were already fully inserted. The loss of Division 1 RPS also caused the actuation of the Division 1 primary containment isolation logic. The Division 1 isolation valves in the balance-of-plant systems closed as designed. Both trains of the standby gas treatment system actuated. The loss of RSS no. 1 occurred during post-modification testing on relays at the local 230kV switchyard. The exact cause of the event is under investigation. This event is being reported in accordance with 10 CFR 50.72(b)(3)(iv)(A). The unit remains in cold shutdown with 1 source of offsite power and all 3 (EDG) available. The (NRC) Resident Inspector has been notified.|
|ENS 51644||9 January 2016 07:04:00||River Bend||NRC Region 4||GE-6||On 1/9/16 at 0237 (CST), River Bend Station sustained a reactor scram during a lightning storm. An electrical transient occurred resulting in a full main steam isolation (MSIV) (Group 6) and a Division II Balance of Plant isolation signal. During the scram, level 8 occurred immediately which tripped the feed pumps. A level 3 signal occurred also during the scram. Subsequent level 3 was received three times due to isolated vessel level control. The plant was stabilized and all spurious isolation signals reset, then the MSIVs were restored. The plant is now stable in Mode 3 and plant walkdowns are occurring to assess the transient. During the scram, all rods inserted into the core. The plant was initially cooled down using safety relief valves. Offsite power is available and the plant is in its normal shutdown electrical lineup. The licensee has notified the NRC Resident Inspector.|
|ENS 51637||6 January 2016 09:38:00||River Bend||NRC Region 4||GE-6||At (2258) CST, on January 5, 2016, with the plant operating at 100 percent power, the main control room alarm indicating high pressure in the auxiliary building actuated. Operators confirmed that the building pressure, corrected for temperature, indicated slightly positive, whereas the building pressure limit in Technical Specifications is 0.0 - 3.0 inches of water negative pressure. Secondary containment was declared inoperable, and the Division 2 standby gas system was started. This action restored building pressure to the acceptable range, and the building was declared operable at (0027 CST) on January 6. This condition is being reported in accordance with 10 CFR 50.72(b)(3)(v)(C) as an event that caused the secondary containment to be potentially incapable of performing its safety function. The NRC Senior Resident Inspector was notified.|
|ENS 51600||11 December 2015 11:28:00||River Bend||NRC Region 4||GE-6||At 0416 (CST) on 12-11-2015, River Bend Station declared the High Pressure Core Spray system INOPERABLE in accordance with Technical Specification 3.8.9, Condition E (Declare High Pressure Core Spray System and Standby Service Water System Pump 2C inoperable immediately) due to Division 2 Control Room Air Conditioning System HVK-CHL1D tripping off because of high inboard bearing temperature of 180 deg F. Actions taken to exit LCO: Alternated divisions of Control Room Air Conditioning System to Division 1 HVK-CHL1C in service and Division 2 HVK-CHL1B in standby and exited LCO at 0439. The licensee has notified the NRC Resident Inspector.|
|ENS 51599||11 December 2015 02:30:00||River Bend||NRC Region 4||GE-6||On August 1, 2015, during tagging activities to support planned maintenance on a condensate demineralizer, operators incorrectly positioned certain air-operated components which, combined with apparent leakage past a solenoid valve, resulted in a drain opening on a demineralizer that was in service. Flow through the drain line caused a turbine building sump to overflow to the floor of the 67 foot elevation of the Turbine Building. Immediate actions were taken to stop the leak. The spill volume was approximately 60,000 gallons of condensate. The tritium activity of the water is estimated at 1.32E-2 microCi/ml. Gamma activity was from noble gases only in a concentration of approximately 2.30E-6 microCi/ml. The spill was confined to the Turbine Building. The affected area contains degraded floor seals which might allow the spill to reach groundwater. The reason for this notification is that industry and governmental officials were notified of this event on August 3, 2015. The NRC Senior Resident Inspector was notified and informal notification was made to the NRC Region IV office, the Louisiana Department of Environmental Quality, and West Feliciana Parish government authorities. The Nuclear Energy Institute was informed as specified in their ground water protection initiative. Plant cleanup activities arising from the spill are complete.|
|ENS 51568||27 November 2015 09:23:00||River Bend||NRC Region 4||GE-6||At 0431 CST on November 27, 2015, an automatic reactor scram occurred following the trip of the main generator. The generator trip was apparently caused by a partial loss of offsite power, which resulted from a differential ground on the north bus of the local 230 kV switchyard. The ground signal caused the reserve station service line no. 1 to de-energize, which tripped the Division 1 offsite power source to station, as well as the main generator. The plant responded as designed as follows: The Division 1 emergency diesel generator started and tied to the bus restoring Division 1 emergency power. The Division 3 emergency diesel generator started and tied to the bus, restoring power on the Division 3 switchgear. The reactor protection system tripped as designed. Reactor water level was controlled normally with condensate and feed water. A level 3 reactor water level scram signal occurred as expected, and RPV (Reactor Pressure Vessel) water level was restored to normal level band. Reactor pressure was controlled by the bypass valve system, and a normal cool down was initiated. The reactor is being taken to cold shutdown pending an investigation of the event. The loss of power also resulted in a partial loss of normal service water cooling to the plant, and emergency service water cooling automatically initiated per design. At the time of event, the reactor protection system was aligned to the backup power supply, which was momentarily lost. This resulted in multiple system isolations including reactor water clean up, and outboard balance of plant isolations. These isolations were initiated due to loss of offsite power, and all responded as designed. The isolation resulted in a loss of the running decay heat removal pump for the spent fuel pool. The standby pump is available for service and being aligned for service. The plant is currently stable in hot shutdown. Transmission and distribution personnel are currently investigating the ground in the 230 kV switchyard. All control rods inserted. The licensee has notified the NRC Resident Inspector.|
|ENS 51552||19 November 2015 11:51:00||River Bend||NRC Region 4||GE-6||At 0724 (CST) on 11-19-2015, River Bend Station declared the High Pressure Core Spray System inoperable in accordance with Technical Specification 3.8.9, Condition E (Declare High Pressure Core Spray System and Standby Service Water System Pump 2C inoperable immediately) due to Division 2 Control Room Air Conditioning System Chiller HVK-CHL1D being inoperable due to a significant lube oil leak. HVK-CHL1D tripped on Low Lube Oil Differential Pressure. Division 1 Control Building Air Conditioning System Standby Chiller HVK-CHL1A automatically started as expected. Actions taken to exit LCO (Limiting Condition of Operation): Operators alternated to HVK-CHL1B in standby. The licensee notified the NRC Resident Inspector.|
|ENS 51545||18 November 2015 08:45:00||River Bend||NRC Region 4||GE-6||At 2355 (CST) on 11/17/2015, River Bend Station declared the High Pressure Core Spray (HPCS) system inoperable in accordance with Technical Specification 3.8.9, Condition E (Declare HPCS system and Standby Service Water System Pump 2C inoperable immediately) due to Division 1 Control Room Air Conditioning System HVK-CHL1C being inoperable because of a significant Freon leak on SWP-PVY32C. Actions taken to exit LCO: Alternated divisions of Control Room Air Conditioning System to Division 2 HVK-CHL1D in service and Division 1 HVK-CHL1A in standby. The basis for declaring High Pressure Core Spray inoperable was that the control room chiller also chills the switchgear room that supplies power to the HPCS. HPCS was out of service for less than one hour while the chillers were swapped from Division 1 to Division 2. The licensee has notified the NRC Resident Inspector.|
|ENS 51112||2 June 2015 02:00:00||River Bend||NRC Region 4||GE-6|
At 2111 (CDT) River Bend Nuclear Station sustained an Automatic Reactor Scram due to low Reactor Water Level (Level 3). The plant is currently stable, with level being maintained in a normal band of 10 - 51 inches with Condensate and Feedwater. Reactor Pressure is in the prescribed band of 500-1090 psig. The plant is in Mode 3, Hot Shutdown, and will remain in Mode 3 until investigation of the scram is complete. The transient began with a trip of Reactor Feed Pump 'A', followed by a Reactor Scram and a trip of Reactor Feed Pump 'C'. Reactor water level was recovered with Reactor Feed Pump 'B' to a normal post scram level band. There was a problem noted with the Reactor Feedwater Master Level Controller; this was mitigated by the Operator placing the controller to manual. There was no subsequent Level transient. Reactor Pressure was stabilized in normal pressure band with Turbine bypass valves. During the transient, a Reactor Recirculating Flow Control Valve Runback was not received as expected. Reactor Recirculating Pump 'A' responded as expected to transient (switching to low pump speed), Reactor Recirculating Pump 'B' tripped during transient. A Level 3 isolation signal was received, all expected isolations occurred. The cause of the transient is currently under investigation. The reactor is stable in Mode 3 with decay heat being removed via turbine bypass valves, and a normal electrical line up. The NRC Resident Inspector has been notified.
At 2231 on 6/1/15, Reactor Water Cleanup System isolated on High Reactor Water Cleanup System Heat Exchanger room temperature due to loss of Turbine Building chill water during the initial transient. All Reactor Water Cleanup System Valves isolated as expected. Reactor Water Cleanup was the only system affected by this isolation signal. The licensee has notified the NRC Resident Inspector. Notified R4DO (Whitten).
|ENS 51083||21 May 2015 12:03:00||River Bend||NRC Region 4||GE-6||At 0309 CDT on May 21, 2015, with the plant operating at 100 percent power, the shift manager was notified of a condition that could potentially lead to the failure of safety-related inverters in the DC electrical distribution system. This condition was identified while reviewing completed probabilistic risk analysis (PRA) calculations. It was discovered that control building ventilation system heat load calculations were not updated when new AC/DC inverters, with significantly higher heat output, were installed in 2007. Since the heat load calculations were not updated, it was not realized at the time that, under post-accident conditions involving a specific single failure, the DC electrical equipment rooms (i.e., inverters and battery chargers) could exceed their design basis ambient temperature, potentially leading to the failure of the inverters or battery chargers, and the loss of DC power in both divisions of the distribution system. The postulated scenario is the loss of offsite power (LOP)/loss of coolant accident (LOCA), followed by the failure of a single emergency diesel generator. If within 20 minutes prior to the onset of the event, the control building ventilation system had been shifted to the division in which the emergency diesel generator successfully started, the chiller in that division would, by design, be prevented from re-starting for as much as 20 minutes by its anti-recycle feature. (That feature limits successive starts of a chiller to prevent over-heating the motor.) The other chiller in that same division must be manually aligned for service, so it is not assumed to be available for these purposes. During the period in which the anti-recycle timer is running, no chiller would be in service, and the actual heatup rate of the inverters/battery charger could lead to room temperatures in excess of their design basis assumptions. As stated above, this condition (no ventilation cooling) would only exist for a maximum of 20 minutes from the time the associated divisional chiller was started, concurrent with a LOP/LOCA and a single failure. After expiration of the 20 minute timer, the chiller would perform the required function and lower room temperatures as expected. For best estimate PRA purposes, River Bend assumes an equipment survivability criteria of exposure to temperatures above 122 degrees F, but below 150 degrees F, for up to four hours. This is based upon the industry Station Blackout guidance of NUMARC 87-00, which was endorsed by the NRC as the basis for industry response to the Station Blackout Rule. This condition exists only after planned chiller swap and can be mitigated by opening the door to the inverter room should a LOP/ LOCA occur prior to the expiration of the 20 minute timer. Measures are in place for a dedicated operator to perform this function pending a modification to resolve the issue. This condition is being reported in accordance with 10 CFR 50.72(b)(3)(v) as the potential loss of the safety function of the DC electrical distribution system. The licensee has notified the NRC Resident Inspector.|
|ENS 51028||1 May 2015 08:36:00||River Bend||NRC Region 4||GE-6|
River Bend Station personnel declared the High Pressure Core Spray (HPCS) system inoperable at 2344 CDT on 4/30/2015. The HPCS system at River Bend Station includes a test return line to the Condensate Storage Tank (CST). The test return line is isolated by two motor operated valves (E22-MOVF010 and E22-MOVF011), with both having a safety function to close on an ECCS initiation signal to ensure that injection flow is directed to the reactor vessel. There is currently a blind flange installed downstream of these two valves. While the HPCS pump is normally aligned to the CST, the credited source of water for the pump is the suppression pool. Accordingly, the pump suction is realigned to the suppression pool on low level in the CST or when suppression pool level rises to a certain point. While performing maintenance on the downstream test return valve (E22-MOVF011), station personnel identified leakage past the upstream test return valve (E22-MOVF010) which was being used as an isolation boundary. In evaluating this condition, engineering personnel noted that the observed leakage past the upstream isolation MOV might be sufficient to deplete suppression pool inventory such that it would not be capable of performing its specified function for the duration of the 30-day mission time. The issue of concern is that once HPCS is aligned to the suppression pool post-LOCA, pool inventory would be lost due to the leaking upstream isolation valve (E22-MOVF010) and out the disassembled downstream isolation valve (E22-MOVF011). Based on that concern, the HPCS pump suction valve from the suppression pool was disabled in the closed position to preserve pool inventory. This action caused the HPCS system to be declared inoperable at 2344 CDT. This action results in a 14 day shutdown LCO and is reportable to the NRC in accordance with 10CFR50.72(b)(3)(v)D. The HPCS pump remained available with its suction aligned to the CST. Message has been left with NRC Senior Resident Inspector.
The licensee is retracting the report for Event No. 51028. On April 28, the High Pressure Core Spray System (HPCS) was inoperable to support planned maintenance. During repairs on the HPCS pump test return valves, leakage through the upstream isolation valve was observed when the downstream valve was disassembled. At 2315 (CDT) on April 30, it was conservatively determined that the leakage represented a potential challenge to the 30-day inventory of the suppression pool, and the pool was declared inoperable. At 2344 (CDT) on April 30, the HPCS pump suction valve to the suppression pool was closed to isolate that potential leakage path until the maintenance could be completed. This action returned the suppression pool to an operable status. On June 24, a quantitative leak rate test was performed on the upstream isolation valve (E22-MOVF010). That test determined that the leakage through the valve was not of such magnitude to have had the potential to deplete the 30-day inventory of the suppression pool during post-accident operation of the HPCS system. Additionally, when the HPCS pump suction valve on the suppression pool was closed on April 30, the system was already in a planned outage that commenced on April 28. As such, this condition need not have been reported. The licensee notified the NRC Resident Inspector. Notified the R4DO (Campbell).
|ENS 51003||22 April 2015 14:18:00||River Bend||NRC Region 4||GE-6||On February 24, 2015, at approximately 1702 CDT, while the plant was in cold shutdown, power was lost on the Division 1 reactor protection system (RPS) bus. This event resulted in the automatic closure of the Division 1 primary containment isolation valves in the residual heat removal (RHR) and reactor water cleanup systems. Additionally, the primary containment atmospheric monitoring system automatically actuated, and ventilation systems in the fuel building, auxiliary building, and control building shifted to emergency mode. The closure of the isolation valves in the residual heat removal system caused an automatic trip of the 'A' RHR pump, which had been in the shutdown cooling alignment. The equipment response to the isolation signal was as expected. This event is being reported in accordance with 10 CFR 50.73(a)(1) as an invalid actuation of the Division 1 primary containment isolation system. The isolation was promptly diagnosed as having resulted from a trip of the output breaker of the RPS motor generator (MG) set 'A,' and not from a valid signal. Operators implemented the appropriate response procedures to align power to the bus via the alternate source, and began restoring the affected systems. The 'A' RHR pump was re-started within twelve minutes, during which time coolant temperature increased approximately seven degrees to a maximum of approximately 100F. Other affected systems were restored over the next few hours. The causal analysis concluded that the MG set output breaker tripped due to an overly conservative setpoint on the overvoltage trip relay. The low trip setpoint was a latent condition that had existed since the output voltage was raised in 1988 at the recommendation of the vendor, but at which time the trip setpoint was not changed. To correct this condition, the MG overvoltage trip setpoint was raised to restore adequate operating margin to the normal MG output voltage. At the time of the event, the plant was in MODE 5 with the reactor cavity flooded to greater than 23 feet above the vessel flange. The shutdown cooling system was promptly restored to service. This event was of minimal safety significance to the health and safety of employees and the public. The licensee has notified the NRC Resident Inspector.|
|ENS 50883||13 March 2015 11:17:00||River Bend||NRC Region 4||GE-6||A licensed employee had a confirmed positive for alcohol during a random fitness-for-duty test. The employee's access to the plant has been terminated. The licensee notified the NRC Resident Inspector.|
|ENS 50872||8 March 2015 05:21:00||River Bend||NRC Region 4||GE-6||On March 7, 2015, at 2140 CST, with the plant in Mode 5, Refueling, the RSS#2, one of two Reserve Station Service offsite power sources, de-energized. This loss of RSS#2 caused the de-energization of the Division 2 Safety Bus, which caused a valid start signal to the logic of the Division 2 Emergency Diesel Generator. No start occurred, however, due to the diesel being in the maintenance mode. Division 2 Standby Service Water, which was being run for system fill and vent as well as surveillance testing, also lost power. At the time RSS#2 was lost, the Division 2 Diesel generator and Division 2 Standby Service Water were inoperable for the Refuel Outage 18 Division 2 maintenance window. Division 1 systems and RSS#1 were not affected by the power loss and continued to operate normally. There were 5 control building dampers and 1 floor drain air operated valve that repositioned due to the loss of power. The cause of RSS#2 de-energization is still under investigation. The licensee notified the NRC Resident Inspector.|
|ENS 50774||28 January 2015 13:50:00||River Bend||NRC Region 4||GE-6||On December 6, 2014, at approximately 1012 CST, while the plant was operating at 100 percent power, the Division 2 reactor protection system (RPS) bus de-energized unexpectedly. This resulted in a half-scram and a Division 2 primary containment isolation signal. Operators executed the appropriate abnormal operating procedures to begin an orderly restoration of the affected systems. Atmospheric pressure in the primary containment momentarily reached the high-pressure alarm setpoint, necessitating entry into the emergency operating procedure for that condition. Automatic isolation valves in the following systems closed as designed: - reactor plant component cooling water - drywell unit cooler water supply - reactor building floor and equipment drains - reactor building HVAC chilled water supply - containment airlock seal air supply - reactor recirculation system flow control valve hydraulics - main steam line drains - reactor water cleanup - auxiliary building and annulus HVAC systems These engineered safety systems actuated as designed: - standby gas control filter trains - fuel building filter trains - control building filter trains The event occurred approximately 25 hours after the Division 2 RPS motor-generator (MG) was aligned to the bus following replacement of the voltage regulator. Following the event, the MG set was found running with its output breaker tripped. A failure analysis determined that the spike suppressor and the field flash card were potential sources of the MG breaker trip. The spike suppressor was replaced. Inspection of the field flash card found a strand of wire from one of the attached leads nearly touching a trace on the circuit board. Testing determined that the wire strand was the most likely cause for the breaker trip. With no spare card readily available, the wire strand was removed and the field flash card was re-installed. Other cards were inspected, and no similar conditions were found. The MG set was load tested for 30 hours, and was placed in service on December 17(, 2014). Additionally, it is suspected that there is an intermittent failure occurring in the field flash card. A design change will be developed to correct that condition. The licensee has notified the NRC Resident Inspector.|
|ENS 50704||25 December 2014 12:41:00||River Bend||NRC Region 4||GE-6||At 0837 (CST) on 12/25/14, a loss of Reactor Protection System (RPS) 'B' occurred which resulted in a Division 2 RPS half SCRAM. This occurred concurrent with a Division 1 RPS half SCRAM which had been inserted for LCO 126.96.36.199 Action 'A' due to issues with the #2 turbine control valve RPS logic on 12/23/14. This resulted in a full RPS actuation and Reactor SCRAM. During the SCRAM, a reactor water Level '8' occurred which tripped the running reactor feed pump. Reactor water level peaked at 56 inches. This Level '8' is under investigation. Once reactor water level lowered below 51 inches the Level '8' signal was reset, and the team attempted to start the 'C' reactor feed water pump. The 'C' reactor feed pump failed to start upon attempt. The 'A' reactor feed pump was then started successfully. The startup feed regulating valve failed to open in automatic or manual mode, resulting in an RPV Level '3' signal (lowering to 8.1 inches). The operators manually aligned the 'C' feed water regulating valve and restored reactor water level to normal band. The plant is stable in Mode 3 pending investigation. The licensee notified the NRC Resident Inspector.|
|ENS 50546||17 October 2014 07:46:00||River Bend||NRC Region 4||GE-6|
At 0303 (CDT), River Bend Nuclear Station sustained a reactor scram due to high Average Power Range Monitor (APRM) flux, suspected due to a malfunction of the Electrohydraulic Control System. Reactor recirculation pump 'B' tripped, reactor recirculation pump 'A' responded appropriately. All other systems responded appropriately except for loss of feed water due to low suction pressure trip from isolating the condensate demineralizers. Reactor water level did not get out of level band. Condensate demineralizers and feedwater were restored to service. Level 3 (isolation) was initiated due to scram. (One) system, Suppression Pool Cooling isolated accordingly due to level 3 signal. Currently the plant is in mode 3, hot shutdown. Plant will remain in mode 3 until investigation of scram is complete. During the scram, all rods inserted into the core. No relief valves lifted as a result of the transient. All safety equipment is available although reactor core isolation cooling is functional but inoperable due to an earlier issue discovered during a surveillance test. The reactor is at normal pressure and temperature for Mode 3. The cause of the high APRM flux and the identified anomalies are under investigation. The licensee has notified the NRC Resident Inspector.
The licensee is updating the notification to include an 8 hour notification for a specified system actuation due to the Level 3 isolation signal. Licensee is proceeding to cold shutdown to troubleshoot the EHC system. The licensee will notify the NRC Resident Inspector. Notified R4DO (Haire).
|ENS 50337||2 August 2014 03:39:00||River Bend||NRC Region 4||GE-6||River Bend Station personnel declared the High Pressure Core Spray system inoperable at 2142 (CDT) on 8/1/2014. The High Pressure Core Spray (HPCS) system at River Bend Station includes a test return line to the Condensate Storage Tank (CST). The test return line is isolated by two motor operated valves (MOVs) with both having a safety function to close on an ECCS (Emergency Core Cooling System) initiation signal to ensure that injection flow is directed to the reactor vessel. While the HPCS pump is normally aligned to the CST, the credited source of water for the pump is the suppression pool. Accordingly, the pump suction is realigned to the suppression pool on low level in the CST or when suppression pool level rises to a certain point. Station personnel identified leakage past the test return valves to the CST. In evaluating this condition, engineering personnel noted that the observed leakage past the two MOVs might be sufficient to deplete suppression pool inventory such that it would not be capable of performing its specified function for the duration of the 30 day mission time. The issue of concern is that once HPCS is aligned to the suppression pool post-LOCA, pool inventory would be lost to the CST through the leaking test return valves. Based on that concern, the HPCS pump suction valve from the suppression pool was disabled in the closed position to preserve pool inventory. This action caused the HPCS system to be declared inoperable at 2142 (CDT). This action results in a 14 day shutdown LCO and is reportable to the NRC in accordance with 10 CFR 50.72(b)(3)(v)(D). The HPCS pump remains available with its suction aligned to the CST. Assuming normal makeup water supplies are available, the HPCS system can be realigned to the suppression pool if necessary. This condition continues to be evaluated and rework options are being developed. The NRC Senior Resident Inspector has been notified.|
|ENS 50324||30 July 2014 13:27:00||River Bend||NRC Region 4||GE-6||On July 30, 2014, at (0940 CDT), with the plant operating at 100% power, a review of an engineering analysis of the ultimate heat sink (UHS) determined that the UHS had been in an unanalyzed condition that degraded plant safety. This condition was the result of a design basis deficiency for the UHS that did not account for the adverse effects of system leakage on compliance with the 30-day inventory required by Regulatory Guide 1.27. The system design basis requires that 30-day inventory be maintained, with the assumption that no replenishment of the UHS occurs for the entire duration of the postulated event. In support of the development of the engineering analysis, compensatory measures have been implemented which provide adequate assurance that the UHS will perform its design safety function. Corrective actions to restore full compliance with design basis requirements are in development. This event is being reported in accordance with 10 CFR 50.72 (b)(3)(ii) as an unanalyzed condition that degraded the safety function of the UHS. The licensee notified the NRC Resident Inspector.|
|ENS 50109||12 May 2014 16:57:00||River Bend||NRC Region 4||GE-6||On May 12, 2014, at 1458 CDT, River Bend Station management determined that tritium confirmed to be present in water samples taken from in-leakage into the below-ground elevation of the turbine building basement, through an underground pipe penetration, was reportable in accordance with NEI 07-07, Ground Water Protection Initiative. The leakage was tested for gamma and tritium activity. No gamma contamination was detected. Tritium was measured at 28,270 picocuries per liter. The source and volume of the radioactive in-leakage is unknown. The leakage into the plant is currently being contained, and actions are in progress to identify the source. The Louisiana Department of Environmental Quality was notified at 1500 CDT today (5/12/14). This event is being reported in accordance with 10 CFR 50.72(b)(2)(xi) as an event requiring notification of the state government. The NRC Resident Inspector has been notified.|