Semantic search
| Start date | Reporting criterion | Title | Event description | System | LER | |
|---|---|---|---|---|---|---|
| ENS 56116 | 19 September 2022 06:32:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | Safety System Inoperability | The following information was provided by the licensee via email: At 0132 CDT on September 19, 2022, River Bend Station (RBS) was operating at 100% power when the high pressure core spray (HPCS) system was declared inoperable in accordance with technical specification 3.8.9, condition E (declare HPCS and standby service water system pump 2C inoperable immediately) due to a E22-S003, HPCS transformer feeder malfunction. The HPCS is a single train system at RBS, therefore this event is being reported in accordance with 10 CFR 50.72(b)(3)(v)(D) as an event or condition that could have prevented the fulfilment of a safety function. The reactor core isolation cooling system has been verified to be operable. The NRC Resident Inspector has been notified. The following additional information was obtained from the licensee in accordance with Headquarters Operations Officers Report Guidance: RBS has entered a 14-day limiting condition for operation due to the loss of HPCS and they have upgraded their on-line plant risk model to "yellow". | Service water Reactor Core Isolation Cooling High Pressure Core Spray | |
| ENS 54880 | 4 September 2020 01:48:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | High Pressure Core Spray Inoperable | 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). | Feedwater Service water High Pressure Core Spray | |
| ENS 54348 | 24 October 2019 15:35:00 | 10 CFR 50.72(b)(3)(v)(A), Loss of Safety Function - Shutdown the Reactor 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | Automatic Depressurization System Inoperable | 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. | Automatic Depressurization System Safety Relief Valve | |
| ENS 54338 | 18 October 2019 07:07:00 | 10 CFR 50.72(b)(3)(v)(A), Loss of Safety Function - Shutdown the Reactor 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | En Revision Imported Date 11/20/2019 | 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). | Main Steam Line | |
| ENS 53622 | 25 September 2018 05:00:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident 10 CFR 50.72(b)(3)(ii)(B), Unanalyzed Condition | Control Building Chillers in Unanalyzed Condition | 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 16:29:00 | 10 CFR 50.72(b)(3)(v)(A), Loss of Safety Function - Shutdown the Reactor 10 CFR 50.72(b)(3)(v)(B), Loss of Safety Function - Remove Residual Heat 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident 10 CFR 50.72(b)(3)(ii)(B), Unanalyzed Condition | Unanalyzed Condition Associated with Damaging Effects of Tornados | 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 20:31:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge | Inadvertent Injection of High Pressure Core Spray | 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. | Feedwater High Pressure Core Spray | |
| ENS 53324 | 11 April 2018 06:50:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident 10 CFR 50.72(b)(3)(ii)(B), Unanalyzed Condition | Condition That Could Impair Function of Control Building Ac System | 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 52995 | 27 September 2017 15:00:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | Accident Mitigation - Loss of Secondary Containment | 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 3.6.4.1 'Secondary Containment-Operating,' not being met because surveillance requirement SR 3.6.4.1.3 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. | Secondary containment | |
| ENS 52631 | 23 March 2017 07:56:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | High Pressure Core Spray Declared Inoperable | 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) 3.6.1.3 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 3.6.1.3 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. | Primary containment High Pressure Core Spray | |
| ENS 52568 | 20 February 2017 18:40:00 | 10 CFR 50.72(b)(3)(ii)(B), Unanalyzed Condition | Unanalyzed Condition Due to Potential Failure of Control Room and Control Building Air Handling Units | 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). | Shutdown Cooling | |
| ENS 51899 | 3 May 2016 03:29:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | High Pressure Core Spray System Inoperable Due to a Control Room Chiller Trip | 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). | Service water High Pressure Core Spray | |
| ENS 51600 | 11 December 2015 10:16:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | High Pressure Core Spray Declared Inoperable | 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. | Service water High Pressure Core Spray | |
| ENS 51552 | 19 November 2015 13:24:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | High Pressure Core Spray Declared Inoperable | 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. | Service water High Pressure Core Spray | |
| ENS 51545 | 18 November 2015 05:55:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | High Pressure Core Spray Declared Inoperable | 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. | Service water High Pressure Core Spray | |
| ENS 51028 | 1 May 2015 04:44:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | High Pressure Core Spray System Inoperable | 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). | High Pressure Core Spray | |
| ENS 50337 | 2 August 2014 02:42:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | High Pressure Core Spray Declared Inoperable Due to Test Return Valve Leakage | 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. | High Pressure Core Spray | |
| ENS 50324 | 30 July 2014 14:40:00 | 10 CFR 50.72(b)(3)(ii)(B), Unanalyzed Condition | Ultimate Heat Sink in an Unanalyzed Condition | 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 49705 | 9 January 2014 06:00:00 | 10 CFR 50.72(b)(3)(ii)(B), Unanalyzed Condition | Unanalyzed Condition Identified from Operating Experience Review | A review of industry operating experience regarding the impact of unfused (safety-related) direct current ammeter circuits in the main control room has determined the described condition (having the ammeters installed) to be applicable to River Bend Station, resulting in a potentially unanalyzed condition with respect to 10 CFR 50 Appendix R analysis requirements. River Bend Station does have unfused ammeter leads. This normally is not a concern, since two failures are required to cause the problem described in the document referenced above; an ammeter lead must short to ground, and another lead of the opposite polarity must also short to ground. Either of these events by itself will set an alarm, but not cause equipment damage. This allows for locating and repairing the problem before the second failure occurs. However, during a fire, there is a greater chance that these two failures could happen simultaneously, or before a single failure can be repaired. This condition is being reported in accordance with 10 CFR 50.72(b)(3)(ii)(B). Interim compensatory measures have been implemented. The NRC Resident Inspector has been notified. | ||
| ENS 49362 | 19 September 2013 19:37:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | Secondary Containment Inoperable Due to an Unattended Open Door | Security personnel reported to the Main Control Room that at time 1437 CDT, 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 1441 CDT. No deficiencies were found with the door. The fact that the door was open and unattended beyond the time allowed for normal entry and exit violates Technical Specification 3.6.4.1, 'Secondary Containment- Operating,' because surveillance requirement SR 3.6.4.1.3 was not met. This surveillance requires that doors be closed except during normal entry and exit. In summary, an SSC was inoperable in a required mode as a result of a personnel error and no redundant equipment in the same system was operable. Thus, the condition is reportable under 10CFR50.72(b)(3)(v)(D). The licensee notified the NRC Resident Inspector. | Secondary containment | |
| ENS 46399 | 7 November 2010 15:23:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | High Pressure Core Spray Pump Oil Leak | At 1023 CST on 11/07/2010, the HPCS System was declared inoperable due to a steady stream oil leak issuing from the lower motor bearing drain plug. The oil was being collected by an absorbent pad installed around the oil drain plug below the lower bearing sight glass. When the rag was removed from the drain plug, oil issued from the installed plug in a stream with the diameter of a number two pencil lead. River Bend personnel are currently making plans to repair the oil leak. The licensee notified the NRC Resident Inspector. | High Pressure Core Spray | |
| ENS 46048 | 26 June 2010 01:24:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | Hpcs Inoperable | At 2024 CDT on 6/25/2010, HVR-UC5, HPCS (High Pressure Core Spray) Pump Room Cooler was secured due to high vibration reported (by the) field operator (which was caused by) rubbing on the fan motor shroud. The HPCS system remains available for auto initiation but inoperable due to securing the support equipment. The licensee will notify the NRC Resident Inspector. | ||
| ENS 45119 | 9 June 2009 23:52:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | Door for Secondary Containment Boundary Left Open | This notification is being made pursuant to NRC regulation 10 CFR 50.72(b)(3)(v)(D), 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 mitigate the consequences of an accident. At 1852 (CDT) on June 9, 2009, River Bend Station personnel discovered that a normally closed auxiliary building door was open. This door serves as part of the secondary containment boundary. At discovery, immediate action was taken to close the door. This action restored the secondary containment to the design configuration. Investigation determined that the door was last accessed at 1242 on June 9 and was most probably left open at that time. Further action is being taken to investigate the cause of the event. Secondary containment leak tightness is required to ensure that the release of radioactive materials from the primary containment is restricted to those leakage paths and associated leakage rates assumed in the accident analysis, and that fission products entrapped within the secondary containment structures will be treated by the Standby Gas Treatment System prior to discharge to the environment. With the subject door being open, the function of secondary containment would be impacted. A second door is located in the same exterior passage way as the secondary containment door found open. This door was closed during the period of time the secondary containment door was open. This second door serves a security function. However, it potentially could serve to perform the secondary containment function. An evaluation is being performed to determine the actual impact of the condition on the secondary containment function. However, based on the identified condition, this report is being made as a condition that could have prevented fulfillment of a safety function. The licensee has notified the NRC Resident Inspector.
(This event was reported by River Bend Station on 6/10/09 at 0102 (EDT). This update is being provided for the purpose of retracting that notification.) Subsequent investigation determined that the secondary containment door was left open for unknown reasons some time after 0800 on the morning of June 9. At the 1242 observation by the persons exiting the building, the door was open and it was left in that condition. However, a separate exterior door in that same passageway serves the security function, and it has been confirmed that, other than for routine access, the security door remained closed and locked during the time that the interior pressure boundary door was open. An engineering analysis has determined that the as-found condition did not defeat the function of secondary containment. While the security door is not air-tight, the maximum potential leakage past it under postulated accident conditions has been evaluated. An existing engineering calculation provides a means to determine the maximum size of a breach in the auxiliary building boundary such that the draw-down requirement prescribed by Technical Specifications is maintained. That calculation uses the additional flow area of an identified breach, in addition to the most recent test results of the standby gas treatment system (that system establishes and maintains a negative pressure in the building as part of the its design). Measurements taken on the door found that the potential flow area around it totaled 35 square inches. The current test results indicate that the standby gas treatment system can support the safety function of the auxiliary building with an analytical breach size of 230 square inches. As there is significant margin between the measured gap around the security door and the analytical value, this event was well bounded by the assumptions of the design basis of the building. As such, this event did not constitute a loss of the safety function of secondary containment. The licensee notified the NRC Resident Inspector. Notified the R4DO (D.Powers). | Secondary containment Primary containment Standby Gas Treatment System | |
| ENS 43379 | 21 May 2007 17:31:00 | 10 CFR 50.72(b)(3)(ii)(B), Unanalyzed Condition | Potential Division 1 Edg Damage Due to Loss of Service Water Cooling During Control Room Fire | During a review of an Operating Experience issue (LO-GLO-2006-0090 CA5), a condition was found which is not consistent with the assumptions of the River Bend post-fire safe shutdown analysis. 10CFR50 Appendix R states that for alternate shutdown capability (i.e shutdown from outside the main control room) support systems (service water cooling) for critical post-fire safe shutdown components must remain free from fire damage. Generic Letter 86-10, 'Implementation of Fire Protection Requirements' state that the following assumptions are required for evaluation of a control room fire: 1) fire induced spurious operation of safe shutdown components has occurred; 2) offsite power is lost and; 3) loss of automatic starting of the onsite AC generators as well as the automatic function of valves and pumps whose circuits could be affected by a control room fire. In addition to loss of automatic start of the emergency diesel generators, the post-fire safe shutdown analysis must also evaluate the consequences if the diesel generators do start concurrent with fire induced multiple spurious actuations. Since control circuits for motor operated valves for the standby service water system are routed in the control room, fire induced shorts could place these valves in a position that would prevent service water from cooling the Division 1 emergency diesel generator. In the time required for Operations personnel to evacuate the control room and re-establish control of the standby service water system at the Division 1 Remote Shutdown panel, thermal damage to the diesel generators could render the Division 1 generator incapable from performing its post-fire function. The RBS (River Bend Station) post-fire safe shutdown analysis is based on the assumption that the diesel generator high temperature trip function would remain functional based on the fact that the trip logic is located outside of the main control room and therefore would remain free from fire damage. The investigation performed during the OE review uncovered the fact that at RBS when the emergency diesel generator is started in the emergency mode the non-safety trips (such as high temperature) are by-passed. The loss of off-site power starts the diesel generator in the emergency mode; therefore the high temperature trip is by-passed. With the non-safety trips by-passed, the diesel generator will continue to run even without sufficient cooling. This condition involves compliance with 10CFR50, Appendix R. Plant equipment remains capable of performing the remaining design functions. The scope of this analysis deficiency is limited to the Main Control room fire scenario, with multiple concurrent failures. The Control Room is continuously manned. The affected cables in the MCR under-floor area are protected by automatic fire detection and automatic suppression systems, which would rapidly detect and smother a fire. Introduction of ignition sources, such as work involving welding or grinding is strictly controlled by station procedures. Furthermore Standing Order #193 Revision 3 limits hot work in the main control room during Modes 1,2 and 3. The licensee notified the NRC Resident Inspector. | Service water Emergency Diesel Generator Remote shutdown | |
| ENS 42921 | 19 October 2006 22:56:00 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge | Automatic Scram Following Spontaneous Feedwater Valve Closure | At 1756 CDT with the plant operating at 100% power, a reactor scram occurred in response to a reactor water level 3 signal from an apparent loss of feedwater. Both feedwater injection lines isolated when isolation valves were inadvertently closed, The cause of the isolation valve closure is under investigation. When reactor water level lowered to level 2, high pressure core spray (HPCS) initiated automatically and recovered water level. The reactor core isolation cooling system (RCIC) was tagged out for maintenance at the time of the event. Following the scram, main steam isolation valves isolated on low main steam header pressure. As a result, reactor pressure control was being controlled with the safety relief valves. SRV pressure control in turn led to EOP entry conditions on containment pressure and suppression pool level. Both feedwater lines were opened, and normal reactor level control was restored. The MSIV's were opened and pressure control was returned to the turbine bypass valves and the main condenser. Initial indications are that all plant equipment functioned as designed with the exception of the 'B' feed pump which experienced an apparent seal failure. The plant is stable in Mode 3. All plant conditions are understood. This event is being reported in accordance with 10CRF50.72(b)(2) as an RPS actuation and an injection of HPCS into the reactor vessel, and in accordance with 10CRF50.72(b)(3) as a loss of safety function of HPCS, as it was manually disabled during recovery from the event. The HPCS Injection valve was manually overridden closed for 76 minutes. In addition,' containment isolation valves in multiple systems actuated in response to the RPV level 2 signal. Reactor vessel water level lowered to below level 2. Decay heat is being removed by normal feedwater to the reactor vessel steaming to the main condenser. Offsite power is available and stable. Emergency Diesel Generators are available. The licensee notified the NRC Resident Inspector.
The closure signal to the main feedwater header isolation valves occurred when part of a chart recorder above the isolation valve control switches was dropped by an operator. The operator was attempting to adjust the paper drive mechanism in the recorder, and accidentally dropped the paper cartridge, which struck the 'CLOSE' pushbuttons on the isolation valve control switches. Following the scram, there was a delay in placing the reactor mode switch in the 'SHUTDOWN' position, which is an immediate action required by procedure. Placing the mode switch to 'SHUTDOWN' bypasses the reactor low steam pressure MSIV Isolation. Reactor steam pressure began dropping after the scram, until it reached the MSIV automatic closure setpoint, and the MSIVs isolated, In addition the licensee corrected one of the 10 CFR Section entries from "50.72(b)(3)(v)(A) POT UNABLE TO SAFE SD" to "50.72(b)(3)(v)(D) ACCIDENT MITIGATION." The licensee notified the NRC Resident Inspector. Notified R4 DO (D. Powers) and NRR EO (N. Chokshi) | Feedwater Emergency Diesel Generator Main Steam Isolation Valve Reactor Core Isolation Cooling High Pressure Core Spray Safety Relief Valve Main Condenser Main Steam | |
| ENS 42285 | 25 January 2006 01:32:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | Invalid High Pressure Core Spray (Hpcs) Initiation Signal During Surveillance Testing | 50.72 (b) (3) (vi) Non-Emergency 8Hr Reportable When I&C was performing STP-051-4256, HPCS Drywell Pressure High Channel Calibration and Logic System Functional Test (B21-N067R, B21-N667R), a human performance error resulted in an invalid HPCS initiation signal. Division III diesel generator and the HPCS pump started. The HPCS injection valve stroked open and was manually overridden closed after full open indication, thus HPCS system injection was terminated. HPCS System was unavailable due to being overridden with an initiation signal present from 1932 until 2109 (CST) for a total of 1 Hr and 37 minutes. NUREG 1022 states that single-train systems that perform safety functions (i.e., HPCS), when lost, prevents the fulfillment of the safety function of that system. The licensee informed the NRC Resident Inspector. | High Pressure Core Spray | |
| ENS 42243 | 5 January 2006 15:30:00 | 10 CFR 50.72(b)(3)(ii)(B), Unanalyzed Condition | Unanalyzed Condition Involving Rcic Operation During Mcr Evacuation | During an engineering assessment, a condition was found which does not meet the assumptions of the River Bend post-fire safe shutdown analysis. 10CFR50 Appendix R states that for alternate shutdown capability (i.e. shutdown from outside the main control room), reactor coolant system process variables shall be maintained within those predicted for a loss of normal AC power, and the fission product boundary integrity shall not be affected. Generic Letter (GL) 86-10, 'Implementation of Fire Protection Requirements,' states that the following assumptions are required for evaluation of a control room fire: 1) fire-induced spurious operation of safe shutdown components has occurred; 2) offsite power is lost; and, 3) the emergency diesel generators (DGs) do not automatically start. Based on the conservative assumptions imposed by GL 86-10, the following control room fire scenario must be addressed. A fire is assumed to cause motor-operated valve E51-MOVF063, the inboard steam supply to Reactor Core Isolation Cooling (RCIC) turbine to close. The same fire requires the main control room (MCR) to be evacuated, and during relocation to the Division 1 Remote Shutdown panel, offsite power is lost. The post-fire safe shutdown analysis has evaluated RCIC to be available from the Remote Shutdown Panel in order to maintain reactor water level, and that the Division 1 and 3 DGs are started locally. The Division 2 DG is not analyzed to remain free of damage caused by the MCR fire. Since valve E51-MOVF063 is powered from Division 2, and there is no Division 2 power available to re-open the valve, steam would not be available to power the RCIC turbine. E51-MOVF063 is located in the drywell, making manual operation of the valve impractical. Therefore, RCIC is postulated to not be available to maintain reactor level. Establishing reactor level control is a time-critical function that is required to occur within ten minutes of MCR evacuation in order to meet one of the Appendix R safe shutdown performance goals. This condition involves compliance with 10CFR50, Appendix R. Plant equipment remains operable. The scope of this analysis deficiency is limited to the MCR fire scenario, with three concurrent failures. The MCR Is continuously manned. The affected cables in the MCR under-floor area are protected by fire detection and automatic suppression systems, which would rapidly detect and smother a fire. Introduction of ignition sources, such as work involving welding or grinding, is strictly controlled by station procedures. While the assumptions of the post-fire safe shutdown analysis are not met for this scenario, it has been verified that the components required to properly align the Division 1 Residual Heat Removal system in the low pressure coolant injection mode would be available at the Division 1 Remote Shutdown Panel. Control of three safety-relief valves is also available at the Division 1 Remote Shutdown Panel to depressurize the reactor vessel for low pressure injection. An analysis is under way to determine the response of reactor water level, given these conditions. The licensee notified the NRC Resident Inspector. | Reactor Coolant System Emergency Diesel Generator Reactor Core Isolation Cooling Residual Heat Removal Remote shutdown Low Pressure Coolant Injection |