Semantic search
| Start date | Reporting criterion | Title | Event description | System | LER | |
|---|---|---|---|---|---|---|
| ENS 40652 | 6 April 2004 19:00:00 | 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 | Air Valve Misalignment Reduces Standby Liquid Control Capability | On April 6, 2004, at 1400 CDT, Clinton Power Station discovered an air valve open for the Standby Liquid Control tank sparger. The open air sparger valve caused both Standby Liquid Control pumps to be inoperable due to the potential of air binding the pumps. The valve was closed, and the Standby Liquid Control is now operable. A Prompt Investigation is being commenced to determine circumstances of this open air sparger. The condition existed for approximately five weeks." The system was restored at approximately 1500 on 4/6/04. The Licensee notified the NRC Resident Inspector.
This report is retracted based on the following: During further investigation, a calculation was performed to detail the air entrainment into the SLC pumps and the results show that air entrainment from the air sparger would not reduce system flow below that required by Technical Specifications. Therefore, it was determined that the system design is such that whenever the air sparge valve to the Standby Liquid Control (SLC) tank is open, the pumps remain operable and capable of performing their safety function. Thus, this occurrence (EN #40652 dated 4/6/04) was not reportable under 10CFR50.72(B)(3)(V)(A) and 10CFR50.72(B)(3)(V)(D). The Licensee notified the NRC Resident Inspector. Notified R3DO (Lanksbury). | Standby Liquid Control | |
| ENS 40983 | 24 August 2004 14:17:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | High Pressure Core Spray (Hpcs) Declared Inoperable | At 1128 hours on 8/23/04, the Division 3 Essential Switchgear Heat Removal System (VX) was removed from service and declared inoperable for performance of system flow verification and balance. The test includes an as found flow check on the Division 3 Essential Switchgear Heat Removal System Condensing Unit, rendering the Division 3 VX safety-related chiller 1VX06CC INOPERABLE. The non-safety VX subsystem remained OPERABLE during the test. At 0917 hours on 8/24/04, the non-safety Division 3 VX Heat Removal Supply Fan 1VX04CC, tripped due to the breaker for the safety-related fan being removed for replacement. The Main Control Room received alarm 5042-6A, Auto Trip Pump/Fan. Since both the safety and non-safety subsystems of VX were unavailable Operators declared the High Pressure Core Spray (HPCS) System inoperable per Technical Specification 3.7.2, Action A.1. At 1153 hours, the breaker replacement was complete, 1VX04CC was restored to service, and the HPCS System was declared OPERABLE. The VX System maintains safety-related switchgear, battery and inverter room, and cable spread areas within the design temperature limits of the equipment. The VX system is support system for the HPCS System. With both subsystems of the VX System out of service, the HPCS System may not have been capable of performing its safety function to provide Emergency Core Cooling, aid in depressurization and maintain reactor vessel water level following a loss of coolant accident. An engineering evaluation is currently in progress to determine if the HPCS System would have been capable of performing its safety function with both safety and non-safety subsystems of VX out of service. This issue is being reported in accordance with 10CFR50.72(b)(3)(v)(D), as an event or condition that at the time of discovery could have prevented the fulfillment of the safety function needed to mitigate the consequences of an accident. The NRC Resident Inspector was notified of this event by the licensee.
Upon further review of this event, additional analysis has been performed which bounds the design bases heatup of the associated rooms cooled by the Division III Essential Switchgear Heat Removal System (VX). This analysis concludes that the areas cooled by the Division 3 VX subsystem would not have exceeded design temperatures while the cooling was secured, prior to cooling recovery, and that the supported systems remained operable. Based upon this additional analysis, it can be reasonably concluded that the safety function of High Pressure Core Spray, as a single train safety system, was fulfilled. Therefore this event is not reportable and Event #40983 is being retracted. The NRC Resident Inspector was notified of this retraction by the licensee. R3DO (Clayton) has been notified. | High Pressure Core Spray | |
| ENS 42782 | 17 August 2006 15:44:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | Main Turbine Bypass Valves Inoperable | At 1044 on August 17, 2006, operators received main control room annunciator alarm 'CONDENSER VACUUM LOW' and status lights 'COND VACUUM TRIP' and 'COND VACUUM LOW.' All other indications for main condenser vacuum indicated normal ~ 26.6 (inches Hg). In response to the alarm, initial troubleshooting determined that the main turbine bypass system was inoperable. This was due to concluding that with the low condenser signal present, the bypass valves were prohibited from opening upon demand. Therefore at 1110, Technical Specifications 3.7.6, 'Main Turbine Bypass System,' Condition 'A' was entered. This is reportable as an 8 hour report in accordance with 10 CFR 50.72 (b)(3)(v)(D) as 'Any event or condition that at the time of discovery could have prevented the fulfillment of the safety function of structures or systems that are needed to: (D) Mitigate the consequences of an accident.' The devices that cause the annunciator are 1PY-ES063 and 1PY-ES066. A visual inspection of the device cards revealed that on the 1PY-ES066 card the 'DC CURRENT ALARM' upper and lower lights were lit. These same lights were not lit on the 1PY-ES063. At 1212 on August 17,2006, a lead was lifted to remove the low vacuum inhibit input from 1PY-ES066 for the bypass valves. The main control room alarm cleared and the low vacuum light went out as expected. At 1215 the low vacuum inhibit was reset restoring the bypass valves to operable. The licensee will notify the NRC Resident Inspector. | Main Turbine Main Condenser | |
| ENS 42929 | 24 October 2006 06:42:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | High Pressure Core Spray (Hpcs) Declared Inoperable for Approx. 3.4 Hours | At 0142 on October 24, 2006, while aligning the High Pressure Core Spray system for surveillance testing of the Reactor Core Isolation Cooling System Storage Tank Level instrumentation, 1E22-F015, the Suppression Pool suction valve for the High Pressure Core Spray pump, failed to stroke fully open. High Pressure Core Spray was declared inoperable as a result. This event is considered a loss of a single train system needed to mitigate the consequences of an accident. The High Pressure Core Spray system was restored to an operable condition at 0506 on October 24, 2006 after the suction valve was successfully stroked open and the HPCS suction source was aligned to the Suppression Pool in accordance with Technical Specification Limiting Condition for Operation 3.5.1. The cause of the event is currently under investigation. All other Emergency Core Cooling systems were fully operable during the time period HPCS was inoperable. The Senior Resident Inspector has been notified by the licensee.
Upon further review of this event, the High Pressure Core Spray (HPCS) system remained operable. Based upon valve motor operator thrust verification testing data and troubleshooting, the cause of the suppression pool suction valve for the HPCS pump stopping in mid-position was determined to be tripping of the open-direction torque switch prior to the open limit switch setpoint. Normally, the condition of the open-direction torque switch has no safety-related consequence since the torque switch is bypassed during design basis events and the valve's motor gearing capability is sufficient to open the valve when the torque switch is bypassed. During this event, as directed by the surveillance test procedure, operators placed the HPCS Motor Operated Valve (MOV) test switch to the test position which resulted in the open-direction torque switch not being bypassed (i.e., was in the circuit) during repositioning of the HPCS suppression pool suction valve. Due to placing the HPCS MOV test switch to test, operators entered the action of Operational Requirements Manual section 2.5.2 (Motor Operated Valves Thermal Overload Protection). The action requires operators to return the MOV test switch to normal (removing the torque switch from the circuit) if an emergency condition occurs requiring valve repositioning. As operators were opening the HPCS suppression pool suction valve for testing, suction for the HPCS pump was aligned from the RCIC storage tank. When the HPCS suction valve from suppression pool stopped in mid-position, the HPCS suction valve from the RCIC storage tank was still fully open (per design, stays full open until the HPCS suppression pool suction valve is full open). Therefore, if an accident occurred requiring HPCS to initiate and inject water into the reactor pressure vessel during this event suction would have initiated from the RCIC storage tank. The HPCS system can take suction from either the RCIC storage tank or the suppression pool, and a HPCS initiation signal does not automatically swap HPCS pump suction from the RCIC storage tank to the suppression pool or vice versa. The operators immediately recognized the HPCS suppression pool suction valve did not fully open. If an accident condition occurred, operators would reposition the HPCS MOV test switch to Normal (to bypass the open torque switch). In the event a condition requiring a HPCS suction transfer to the suppression pool occurred, the suppression pool suction valve would fully open and the RCIC storage tank suction valve would fully close, completing the required suction shift. On this basis, the HPCS system was capable of performing its function to mitigate the consequences of an accident and this issue is not reportable under 10 CFR 50.72(b)(3)(v)(D). The NRC Resident was notified of this retraction. R3DO(Cameron) notified. | Reactor Core Isolation Cooling Reactor Pressure Vessel High Pressure Core Spray Emergency Core Cooling System | |
| ENS 42978 | 9 November 2006 12:44:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | High Pressure Core Spray System Valve Inadvertently De-Energized | At 0644 hours (CST), the Main Control Room (MCR) received an alarm that the Division 3 Shutdown Service Water (SX) system was not available. The MCR also received an indication that a Division 3 SX motor operated valve for the plant service water to the SX header isolation valve, 1SX014C, was not available and discovered that there was no light indication for this valve. This valve is required to reposition following a High Pressure Core Spray (HPCS) system initiation. With the loss of power to the valve, this resulted in the Division 3 SX and the HPCS systems being inoperable. Since the HPCS system is a single train safety system, this event is reportable under 10CFR50.72(b)(3)(v)(D). An investigation is underway to determine the cause of the loss of power to the 1SX014C valve, however, preliminary indications are that an individual may have inadvertently bumped the breaker to the 'off' position. At 0742 hours, the investigation of the 1SX014C breaker indicated that the breaker was in the 'off' position (i.e., not tripped). The cubicle door for the 1SX014C breaker was opened. There were no abnormal or unusual indications in the cubicle. The 1SX014C valve was verified open; then the 1SX014C breaker was closed. The breaker was taken directly to the close position and not reset first. The 1SX014C breaker closed, indication returned to the MCR, and the alarm cleared. The breaker remained closed and HPCS system was returned to an available status. At 1047 hours, the Division 3 SX pump was started to confirm that operability of Division 3 SX and HPCS were restored by the actions taken to reclose the breaker at 0742 hours. The 1SX014C valve operated normally and Division 3 SX and HPCS were declared operable. The NRC Resident has been notified. | Service water High Pressure Core Spray | |
| ENS 43416 | 11 June 2007 01:03:00 | 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 Failed Inverter | At 2003 on 6/10/07, the division 3 Nuclear System Protection System (NSPS) inverter power supply failed for unknown reasons. As a result of this failure, the High Pressure Core Spray (HPCS) system has been declared inoperable. This is a failure of a single train safety system and is reportable under 10 CFR 50.72(b)(3)(v)(D). Troubleshooting has been initiated to determine the cause of this failure. The licensee notified the NRC Resident Inspector.
This event is being retracted. An evaluation was performed and it was determined that no loss of safety function occurred following the failure of the Division 3 NSPS Inverter. The investigation determined that a circuit board failed on the inverter causing a blown fuse. The inverter was found in the reverse transfer position and AC power was automatically transferred to its alternate source, supplying its Division 3 loads. The High Pressure Core Spray system remained fully capable of performing its safety function to start and inject under both LOOP and LOCA conditions. The licensee will notify the NRC Resident Inspector. Notified the R3DO (Lanksbury). | High Pressure Core Spray | |
| ENS 45181 | 2 July 2009 19:15:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | Hpcs Inoperable Due to Logic Card Failure | On July 2, 2009, at 0100 hours (CDT), the Main Control Room received an alarm associated with a failure of the Nuclear System Protection System (NSPS) Self Test System (STS). The indicated failure was on a High Pressure Core Spray (HPCS) system logic card. The card was removed and testing of the card, completed at 1415 hours, determined that the failure was on a circuit that would have prevented the automatic initiation capability of HPCS. Since HPCS is an emergency core cooling system and is a single train safety system, this is reportable under 50.72 (b)(3)(v)(D). It is unknown at this time what caused the failure and plans are in progress to repair or replace the card. The logic card is being sent out for repairs. The HPCS system will remain inoperable until the card is repaired and replaced. There is no estimate at this time as to when the card will be replaced. The licensee will notify the NRC Resident Inspector. | High Pressure Core Spray Emergency Core Cooling System | |
| ENS 45676 | 3 February 2010 17:00:00 | 10 CFR 50.72(b)(3)(ii)(A), Seriously Degraded 10 CFR 50.72(b)(3)(v)(C), Loss of Safety Function - Release of Radioactive Material | Feedwater Check Valve Leak Rate Exceeded Technical Specification Requirement | At 1100 (CST) on February 3, 2010, it was discovered that a primary containment local leak rate test performed on feedwater check valve 1B21-F032B exceeded its acceptance criteria. Technical Specification Surveillance Requirement (SR) 3.6.1.3.11 requires that the combined leakage rate for both primary containment feedwater penetrations to be less than or equal to 2 gallons per minute. The measured leakage for 1B21-F032B was reported to be 2.5 gallons per minute (gpm). Operations immediately declared 1B21-F032B inoperable and initiated action to close the feedwater inlet shutoff valve 1B21-F065B to isolate the affected penetration. At 1136 (CST), 1B21-F065B was closed and its breaker was turned off to comply with TS 3.6.1.3, Condition C required actions. At 1447 (CST), the Feedwater Leakage Control System (FWLCS) was declared inoperable in accordance with LCO 3.6.1.9 and the plant entered a 30-day action to restore FWLCS to an operable condition. After performance of a line flush, plans are underway to attempt to re-perform the local leak rate test for the feedwater check valve, 1B21-F032B. If unsuccessful, further corrective actions will be taken. The NRC Senior Resident has been informed. | Feedwater Primary containment | |
| ENS 48269 | 3 September 2012 03:04:00 | 10 CFR 50.72(b)(3)(v)(B), Loss of Safety Function - Remove Residual Heat 10 CFR 50.72(b)(3)(v)(C), Loss of Safety Function - Release of Radioactive Material | Transfer of Emergency Reserve Auxiliary Transformer Isolating Fuel Pool Cooling and Cleanup System, and Fuel Building Ventilation System | At 22:04 CDT on 9/02/2012, the Emergency Reserve Auxiliary Transformer (ERAT) transferred unexpectedly to the Reserve Auxiliary Transformer (RAT). During this transfer, the Fuel Pool Cooling and Cleanup (FC) system pump 'A' tripped and the Fuel Building Ventilation (VF) system isolated. Upper containment pool level dropped below the minimum required level per Technical Specifications (TS) 3.6.2.4 and Secondary Containment differential pressure increased above 0.25 inches vacuum per TS 3.6.4.1. Upper Containment Pool level was restored above the minimum level at 01:27 CDT on 9/3/2012 within the 4 hour completion time. The Upper Containment Pool is a part of the suppression pool makeup system used to ensure the Primary Containment function. Secondary Containment differential pressure was restored at 22:19 on 9/2/2012 when the Standby Gas Treatment System was started. Maintaining secondary containment differential pressure helps to control the release of radioactive material. This event is being reported as a condition that could have prevented the fulfillment of a safety function per 10 CFR 50.72(b)(3)(v)(B) and 10 CFR 50.72(b)(3)(v)(C). The station is currently in a 72-hour action to restore the ERAT to an operable status per TS LCO 3.8.1 Required Action A.2. Plant conditions are stable and actions are underway to repair the ERAT. The NRC Resident (Inspector) has been notified.
Upper Containment Pool level dropped below the normal pool level of 827 feet-3 inches when the Fuel Pool Cooling and Cleanup system pump 'A' tripped, and was initially reported as dropping below the minimum level (825 feet-6 inches) required by Technical Specification (TS) 3.6.2.4. However, subsequent reports from the field confirmed that the lowest level reached was 827 feet 0 inches, which is greater than the minimum required TS level. Therefore, no loss of safety function occurred for the Upper Containment Pool level as a result of this event, and the event is not reportable under 50.72 (b)(3)(v)(B). The NRC Resident (Inspector) has been notified." Notified R3DO (Pelke). | Secondary containment Primary containment Standby Gas Treatment System Fuel Pool Cooling and Cleanup | |
| ENS 48533 | 24 November 2012 02:08:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident 10 CFR 50.72(b)(3)(v)(C), Loss of Safety Function - Release of Radioactive Material | Inadvertent Loss of Instrument Air | On 11/23/2012 at approximately 1956 CST, it was reported that the Control Room (VC) B Chiller breaker was cycling open and closed. In order to stop the cycling, Control Building Unit Sub B was manually tripped causing the following isolations/actuations: loss of power to instrument air (IA) system containment isolation valves causing the Division 2 valves to isolate; loss of power to the low pressure switch that resulted in an automatic start of Division 2 Shutdown Service Water (SX) system; and loss of power to fuel building (VF) system ventilation Division 2 dampers resulting in a trip of the VF system. High Pressure Core Spray (HPCS) became inoperable based on inoperability of the room cooler for the associated Division 4 inverter and battery charger. Operations entered the Loss of AC Power and Automatic Isolation off-normal procedures. Following the loss of power to the VF system ventilation, at 2008, secondary containment differential pressure became positive. At 2009, power was restored to Control Building Unit Sub B and HPCS was restored to operable. At 2011, the standby gas treatment system (VG) was started and at 2013, secondary containment differential pressure was restored. Following re-energization of Unit Sub B, the IA containment isolation valves were re-opened, VG was secured, VF restarted and the Division 2 SX pump was secured. The loss of secondary containment differential pressure is reportable under 10 CFR 50.72(b)(3)(v)(C) as an event or condition that could have prevented fulfillment of a safety function needed to control the release of radioactive material An unplanned inoperability of HPCS reportable under 10 CFR 50.72(b)(3)(v)(D) as HPCS is a single train safety system The cause of the breaker cycling is unknown at this time. The NRC Resident has been informed. | Secondary containment Service water High Pressure Core Spray Standby Gas Treatment System | |
| ENS 48765 | 18 February 2013 09:18:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | High Pressure Core Spray Declared Inoperable | On February 18, 2013, at 0318 hours (CST), the Main Control Room received an alarm associated with a transfer of the Division 4 Nuclear System Protection System (NSPS) inverter to the alternate source. Plant Technicians were performing a Technical Specification (TS) Surveillance, 'Average Power Range Monitor Flow Biased/Neutron Flux Response Time Test,' when a test cable connector contacted a fuse block staple jumper, causing the transfer of the Division 4 NSPS bus from normal inverter source to its alternate source. TS 3.8.7, 'Inverters - Operating' Surveillance Requirement 3.8.7.1 is not met with the inverter on the alternate source, and Condition C, requires High Pressure Core Spray (HPCS) system to be declared inoperable immediately since the Division 4 NSPS bus was not energized from the inverter. Since HPCS is an emergency core cooling system and is a single train safety system, this is a condition that could have prevented fulfillment of a safety function and is reportable under 10 CFR 50.72(b)(3)(v)(D), system needed to mitigate the consequences of an accident. At 0925 CST, the Division 4 NSPS bus has been restored to service on the normal source. At 0925 CST, HPCS has been declared Operable. The NRC Resident has been notified. | High Pressure Core Spray Emergency Core Cooling System | 05000461/LER-2013-001 |
| ENS 49286 | 15 August 2013 14:15:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | Diesel Generator Declared Inoperable Due to Damper Failing to Open | During a run of the Division 3 Diesel Generator room ventilation fan to perform thermograph, it was identified that the damper (1VD01YC) that provides the flow path from the outside area into the ventilation room would not open when the fan was started. This renders the Division 3 Diesel Generator inoperable. High Pressure Core Spray was declared inoperable at 1420 hours (CDT), but remains available. This report is being made pursuant to 10CFR50.72(b)(3)(v)(D) as an event or condition that could have prevented fulfillment of a safety function needed to mitigate the consequences of an accident. The cause of the damper failing to open has not yet been determined. Troubleshooting is in progress to determine the cause and actions required to restore operability. The Division 1 and Division 2 Diesel Generators are operable. The licensee is in a 14-day shutdown TS LCO. The licensee has notified the NRC Resident Inspector. | High Pressure Core Spray | 05000461/LER-2013-004 |
| ENS 49617 | 9 December 2013 02:27:00 | 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)(v)(C), Loss of Safety Function - Release of Radioactive Material | Manual Scram Due to Loss of Division 1 480 Vac Power Causing Loss of Instrument Air to Containment and Scram Air Header | While operating at rated electrical power, the station experienced a transformer fault which resulted in a loss of Division 1 480 VAC power. This resulted in the operators inserting a Manual Scram due to loss of Instrument Air to Containment and the scram air header. On the scram, all control rods fully inserted and no safety relief valves lifted. Reactor vessel level is being maintained by normal feedwater and decay heat is being removed via steam to the main condenser through the steam bypass valves. The plant is currently in Mode 3 and proceeding to Mode 4 to comply with Technical Specification requirements. The plant is in a normal shutdown electrical lineup with the exception of the loss of Division 1 480 VAC power. Reporting in accordance with 10CFR50.72(b)(3)(v)(C) due to loss of normal ventilation to secondary containment which resulted in a positive secondary containment pressure for approximately 15 minutes. Secondary Containment required pressure was restored at 2043 CST. Reporting in accordance with 10CFR50.72(b)(3)(v)(D) due to loss of Division 1 480 VAC power resulting in loss of a single train of Low Pressure Core Spray. The licensee has notified the NRC Resident Inspector. | Feedwater Secondary containment Core Spray Safety Relief Valve Main Condenser Control Rod | 05000461/LER-2013-008 |
| ENS 49758 | 23 January 2014 01:56:00 | 10 CFR 50.72(b)(3)(v)(C), Loss of Safety Function - Release of Radioactive Material | Loss of Secondary Containment Differential Pressure | A spurious closure of a Secondary Containment isolation damper caused a trip of the Fuel Building ventilation system and a loss of Secondary Containment differential pressure. Secondary Containment differential pressure exceeded -0.25 inches of water vacuum rendering Secondary Containment inoperable between the time of 1956 and 2003 (CST). The damper re-opened, fuel building ventilation was restarted and Secondary Containment differential pressure was restored to normal. This event is reportable under 10CFR50.72(b)(3)(v)c. The Licensee will be notifying the NRC Resident Inspector". Investigation for the spurious closure of a Secondary Containment isolation damper is in progress. | Secondary containment | 05000461/LER-2014-001 |
| ENS 50463 | 17 September 2014 00:05:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | Loss of Division 3 of Shutdown Service Water Requires Hpcs to Be Declared Inoperable | At 1905 hours (CDT), during surveillance testing of the Division 3 Shutdown Service Water (SX) system, the Division 3 SX pump tripped for unknown reasons. The Division 3 SX system was declared inoperable and in accordance with Technical Specification 3.7.2, Action A, the High Pressure Core Spray (HPCS) system was declared inoperable. Since the HPCS system is a single train safety system, this event is reportable under 10CFR50.72(b)(3)(v)(D). An investigation is underway to determine the cause of SX pump to trip. The NRC Resident (Inspector) has been notified. | Service water High Pressure Core Spray | |
| ENS 50794 | 7 February 2015 05:55:00 | 10 CFR 50.72(b)(3)(v)(C), Loss of Safety Function - Release of Radioactive Material | Leakage Detection System Inoperable | On 2/6/15 at 2300 (CST) the Division 1 Reactor Water Cleanup (RT) system differential flow instrument was declared inoperable due to erratic indication. The Division 1 RT differential flow instrument was declared inoperable in accordance with Technical Specification 3.3.6.1 Action D.1. At time 2355 Division 2 RT differential flow instrument failed downscale and was declared inoperable in accordance with Technical Specification 3.3.6.1 Action D.1 and also Technical Specification 3.3.6.1 Action E.1 (entered due to Division 1 RT differential flow already inoperable). Since this condition renders the Leakage Detection System incapable of performing its safety function, it is reportable under 10CFR50.72(b)(3)(v)(C). Division 1 RT differential flow was declared Operable at time 0036 on 2/7/15. Division 2 RT differential flow was restored to Operable at time 0225 on 2/07/2015. The NRC Resident (Inspector) has been notified. | Reactor Water Cleanup | 05000461/LER-2015-001 |
| ENS 51179 | 25 June 2015 08:01:00 | 10 CFR 50.72(b)(3)(v)(C), Loss of Safety Function - Release of Radioactive Material | Secondary Containment Pressure Increase Due to Voltage Transient | At approximately 0301 (CDT) on 6/25/15, the Main Control Room received numerous annunciators that indicated a trip of the Emergency Reserve Auxiliary Transformer (ERAT) Static VAR Compensator (SVC) caused by a voltage transient on the 138 kV feed due to thunderstorms in the area. The Division 1 Safety Bus was manually aligned from the reserve source to its normal source. As a result of the voltage transient, the Division 1 Fuel Building Ventilation (VF) system isolation dampers closed causing a trip of VF supply and exhaust fans. With no running VF fans, secondary containment differential pressure rose to slightly greater than 0 inches water gauge and which exceeded the Technical Specification requirement of greater than 0.25 inches vacuum water gauge. The Control Room entered EOP-8, Secondary Containment Control. This event is being reported as a condition that could have prevented fulfillment of a safety function under 10 CFR 50.72(b)(3)(v)(C). Secondary Containment differential pressure was restored within Technical Specification requirements at 0319 (CDT) by reopening the VF isolation dampers and restarting the VF supply and exhaust fans. The ERAT SVC was returned to service at 0457 (CDT). The NRC Resident Inspector has been notified. | Secondary containment | |
| ENS 51669 | 20 January 2016 19:11:00 | 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 | Primary-Secondary Containment Pressure Differential Exceeded Due to Ccp Exhaust Fan Trip | At 1308 CST on January 20, 2016, the main control room received an alarm that the containment building (VR) ventilation system continuous containment purge (CCP) exhaust fan (1VR07CB) tripped. At 1311 CST, primary-to-secondary containment differential pressure was reported to be +0.411 psid. Technical Specification (TS) Limiting Condition for Operation (LCO) 3.6.1.4, Primary Containment Pressure, Action A.1, was entered due to the differential pressure outside the � 0.25 psid requirement. At 1327 CST, the CCP B subsystem was restarted and at 1339 CST, primary-to-secondary differential pressure was restored to within the limits of TS 3.6.1.4. The cause of the trip of the 1VR07CB is under investigation. This event is reportable under 10 CFR 50.72(b)(3)(ii)(B) as an unanalyzed condition that could have prevented the fulfillment of the primary containment function due to the differential pressure being outside the primary containment initial conditions to ensure that containment pressures remain within design values during a loss of coolant accident. This event is reportable under 10 CFR 50.72(b)(3)(v)(D) as an event or condition that could have prevented the fulfillment of the primary containment function for the same reason. The NRC Resident has been notified. | 05000461/LER-2016-001 | |
| ENS 51732 | 13 February 2016 08:06:00 | 10 CFR 50.72(b)(3)(v)(C), Loss of Safety Function - Release of Radioactive Material | Secondary Containment Inoperable | On 02/13/2016 at 0206 CST, an unexpected trip of a Fuel Building ventilation exhaust fan occurred and secondary containment differential pressure became positive. Secondary containment was declared INOPERABLE when Technical Specification-required differential pressure was not being maintained and entered LCO 3.6.4.1 Action A.1 At 0256 (CST), the standby gas treatment system was started and secondary containment differential pressure was restored to Technical Specification requirements at 0257 CST. This loss of secondary containment is reportable under 10 CFR 50.72(b)(3)(v)(C) as an event or condition that could have prevented fulfillment of a safety function needed to control the release of radioactive material. The cause of the fuel building exhaust fan trip is unknown at this time. The NRC Resident Inspector has been notified. | Secondary containment Standby Gas Treatment System | 05000461/LER-2016-002 |
| ENS 51836 | 30 March 2016 20:45:00 | 10 CFR 50.72(b)(3)(v)(C), Loss of Safety Function - Release of Radioactive Material | Secondary Containment Differential Pressure Outside Required Technical Specification Value | At approximately 1545 CDT on 3/30/16, the Main Control Room received numerous annunciators that indicated a trip of the Emergency Reserve Auxiliary Transformer (ERAT) Static VAR Compensator (SVC) caused by a voltage transient on the 138 kV feed due to thunderstorms in the area. As a result of the voltage transient, the Division 1 Fuel Building ventilation (VF) system isolation dampers closed causing a trip of VF supply and exhaust fans. With no running VF fans, secondary containment differential pressure rose to slightly greater than 0 inches water gauge which exceeded the Technical Specification requirement of greater than 0.25 inches vacuum water gauge. The Control Room entered EOP-8, Secondary Containment Control. This event is being reported as a condition that could have prevented fulfillment of a safety function under 10 CFR 50.72(b)(3)(v)(C). Secondary Containment differential pressure was restored within Technical Specification requirements at 1550 CDT by starting the Standby Gas Treatment HVAC (VG) system. The NRC Resident has been notified. | Secondary containment HVAC | 05000461/LER-2016-004 |
| ENS 51845 | 2 April 2016 17:57:00 | 10 CFR 50.72(b)(3)(v)(C), Loss of Safety Function - Release of Radioactive Material | Insulator Failure on Reserve Auxiliary Transformer | At approximately 1257 (CDT) on 4/02/16, the Main Control Room received numerous annunciators that indicated a trip of the Reserve Auxiliary Transformer (RAT) Static VAR Compensator (SVC) that was caused by an insulator failure of the 'A' phase 345kV Circuit Switcher. As a result of the voltage transient, the Division 1 Fuel Building Ventilation (VF) system isolation dampers closed causing a trip of VF supply and exhaust fans. With no running VF fans, secondary containment differential pressure rose to slightly greater than 0 inches water gauge which exceeded the Technical Specification requirement of greater than 0.25 inches vacuum water gauge. The Control Room entered EOP-8, Secondary Containment Control. This event is being reported as a 'Condition that Could Have Prevented Fulfillment of a Safety Function' under 10CFR50.72(b)(3)(v)(C). Secondary Containment differential pressure was restored within Technical Specification requirements at 1300 (CDT) by starting the Standby Gas Treatment HVAC (VG) system. The NRC Resident Inspector has been notified. | Secondary containment HVAC | |
| ENS 52043 | 24 June 2016 20:11:00 | 10 CFR 50.72(b)(3)(v)(C), Loss of Safety Function - Release of Radioactive Material | Loss of Secondary Containment | On 06/24/2016 at 1511(CDT), an unexpected trip of a Fuel Building ventilation supply fan occurred followed by an exhaust fan trip and secondary containment differential pressure became positive. At 1512 (CDT), the standby fuel building ventilation fans auto started and secondary containment differential pressure was restored to Technical Specification required conditions. Secondary containment was declared INOPERABLE when Technical Specification-required differential pressure was not being maintained and LCO 3.6.4.1 Action A.1 was entered and exited for the given time period. Emergency Operating Procedure (EOP) - 8 was entered due to Secondary containment differential pressure reading positive (greater than 0 inches of water). This loss of secondary containment is reportable under 10CFR 50.72(b)(3)(v)(C) as an event or condition that could have prevented fulfillment of a safety function needed to control the release of radioactive material. The cause of the fuel building supply fan trip is under investigation. The NRC Resident Inspector has been informed. | Secondary containment | |
| ENS 52576 | 25 February 2017 04:39:00 | 10 CFR 50.72(b)(3)(v)(C), Loss of Safety Function - Release of Radioactive Material | Secondary Containment Differentail Pressure Exceeded Technical Specifications | At approximately 2239 (CST) on 2/24/17, the Main Control Room received numerous annunciators that indicated a loss of the 138 kV off-site feed to the Emergency Reserve Auxiliary Transformer (ERAT). As a result of the voltage transient, the Division 1 Fuel Building ventilation (VF) system isolation dampers closed causing a trip of VF supply and exhaust fans. With no running VF fans, secondary containment differential pressure rose to slightly greater than 0 inches water gauge which exceeded the Technical Specification requirement of greater than 0.25 inches vacuum water gauge. The Control Room entered EOP-8, Secondary Containment Control. This event is being reported as a Condition that Could Have Prevented Fulfillment of a Safety Function under 10CFR50.72(b)(3)(v)(C). Secondary Containment differential pressure was restored within Technical Specification requirements at 2242 (CST) by starting the Standby Gas Treatment HVAC (VG) system. The NRC Resident (Inspector) has been notified. | Secondary containment HVAC | |
| ENS 52782 | 2 June 2017 07:41:00 | 10 CFR 50.72(b)(3)(v)(C), Loss of Safety Function - Release of Radioactive Material | Secondary Containment Declared Inoperable | On 6/2/2017 at 0241 CDT, Clinton Power Station entered Mode 2 with secondary containment boundary doors propped open. Specifically, both doors for Reactor Water Cleanup (RT) 'B' pump room were propped open with welding cables routed through pump room doors to perform welding in the RT pump room. At 0300 CDT, a Senior Reactor Operator identified that the doors were propped open and Secondary Containment was declared inoperable. LCO 3.6.4.1 Required Action A.1 was entered to restore Secondary Containment to Operable in four hours. At 0324 CDT, the cabling for the welding machine was removed and the doors were closed. Investigation determined that authorization had been granted while in mode 4, when secondary containment was not required to be operable. The doors were propped open at the beginning of the shift, prior to the mode change to mode 2 (0241 CDT). This loss of secondary containment is reportable under 10 CFR 50.72(b)(3)(v)(C) as an event or condition that could have prevented fulfillment of a safety function needed to control the release of radioactive material. The NRC Resident Inspector has been notified. | Secondary containment Reactor Water Cleanup | |
| ENS 52806 | 15 June 2017 14:58:00 | 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 0958 hours (CDT), during planned surveillance testing of the Division 3 Shutdown Service Water (SX) subsystem, the Division 3 SX pump tripped for unknown reasons. The Division 3 SX subsystem was declared inoperable and in accordance with Technical Specification 3.7.2, Action A.1, the High Pressure Core Spray (HPCS) system was declared inoperable. Since the HPCS system is a single train safety system, this event is reportable under 10CFR50.72(b)(3)(v)(D). An investigation is underway to determine the cause of the SX pump trip. The NRC Resident has been notified. | Service water High Pressure Core Spray | 05000461/LER-2017-008 |
| ENS 53054 | 5 November 2017 18:40:00 | 10 CFR 50.72(b)(3)(v)(C), Loss of Safety Function - Release of Radioactive Material | Loss of Secondary Containment Pressure Due to Voltage Transient | At approximately 1240 CST on 11/05/17, the Main Control Room received numerous annunciators that indicated a trip of the Emergency Reserve Auxiliary Transformer (ERAT) Static VAR (volt-ampere reactive) Compensator (SVC) caused by a voltage transient on the 138 kV feed due to thunderstorms in the area. As a result of the voltage transient, the Division 1 Fuel Building ventilation (VF) system isolation dampers closed causing a trip of VF supply and exhaust fans. With no running VF fans, secondary containment differential pressure rose to slightly greater than 0 inches water gauge which exceeded the Technical Specification requirement of greater than 0.25 inches vacuum water gauge at 1241. The Control Room entered EOP-8, Secondary Containment Control. This event is being reported as a Condition that Could Have Prevented Fulfillment of a Safety Function under 10CFR50.72(b)(3)(v)(C). Secondary Containment differential pressure was restored within Technical Specification requirements at 1242 by starting the Standby Gas Treatment HVAC (VG) system. The NRC Resident Inspector has been notified. | Secondary containment HVAC | |
| ENS 53110 | 9 December 2017 19:48:00 | 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)(ii)(B), Unanalyzed Condition 10 CFR 50.72(b)(3)(v)(C), Loss of Safety Function - Release of Radioactive Material | Manual Reactor Scram Due to Loss of Division 1 Ac Power to Numerous Components | At approximately 1347 (CST) on 12/09/17, the Main Control Room received annunciators that indicated a trip of the 4160 V 1A1 breaker 1AP07EJ, 480V XFMR 1A and A1 breaker. Numerous Division 1 components lost power (powered from unit subs 1A and A1). The Division 1 containment Instrument Air isolation valves had failed closed by design due to the loss of power. Due to the loss of containment instrument air, several control rods began to drift into the core as expected and, by procedure, the reactor mode switch was placed in the shutdown position at 1353 (CST). All control rods fully inserted. Also due to the loss of power, the Fuel Building ventilation dampers failed closed by design. With the normal ventilation system secured, secondary containment differential pressure rose to slightly greater than 0 inches water gauge which exceeded the Technical Specification requirement of greater than 0.25 inches vacuum water gauge at 1348 (CST). The Control Room entered EOP-8, Secondary Containment Control. Secondary Containment differential pressure was restored within Technical Specification requirements at 1351 (CST) by starting the Division 2 Standby Gas Treatment system. This event is being reported as a manual actuation of the Reactor Protection System (RPS) and as a Condition that Could Have Prevented Fulfillment of a Safety Function. The cause is currently under investigation. The NRC Resident has been notified. The licensee informed the NRC Resident Inspector.
During a review of plant logs it was identified that the primary to secondary containment differential pressure was identified to be outside of Technical Specification 3.6.1.4 limits of 0 plus or minus 0.25 psid at 2009 on 12/9/17 due to the primary containment ventilation system dampers closing as a result of the loss of power. This parameter is an initial safety analysis assumption to ensure that primary containment pressures remain within the design values during a Loss of Coolant Accident (LOCA). As a result, this condition is reportable as an unanalyzed condition that significantly degrades plant safety. The NRC Senior Resident Inspector has been notified. Notified the R3DO (Stone).
During the post transient review of the trip of the 4160 V 1A1 breaker 1AP07EJ, 480V XFMR 1A and A1, it was identified that the unplanned INOPERABILITY of the Low Pressure Core Spray (LPCS) system due to the loss of power to the injection valve constitutes an event or condition that could have prevented fulfillment of a safety function and is reportable under 10CFR50.72(b)(3)(v)(D) for Accident Mitigation. The High Pressure Core Spray (HPCS) remained available to perform the core spray function, if necessary, during a design basis Loss of Coolant Accident (LOCA), however HPCS and LPCS are each considered single train safety systems. The NRC Senior Resident Inspector has been notified. Notified the R3DO (Stone). | Secondary containment Reactor Protection System Primary containment High Pressure Core Spray Core Spray Standby Gas Treatment System Control Rod | |
| ENS 53303 | 30 March 2018 18:05:00 | 10 CFR 50.72(b)(3)(ii)(A), Seriously Degraded 10 CFR 50.72(b)(3)(v)(C), Loss of Safety Function - Release of Radioactive Material | Primary Containment Declared Inoperable Due to Both Airlock Doors Open Simultaneously | On March 30, 2018 at 1305 CDT, with the reactor at 98 percent core thermal power and steady state conditions, plant personnel identified that both doors of the containment personnel airlock were open simultaneously due to failure of the interlock. Personnel were at both the outside and inside doors. Immediate action was taken to close the inner containment personnel airlock door and it was verified closed. Both doors of the containment personnel airlock were open for less than one minute. There was no radioactive release as a result of the event. The cause of the interlock failure is under investigation. This condition requires an 8-hour non-emergency notification in accordance with 10 CFR 50.72(b)(3)(ii)(A), the condition of the nuclear power plant, including its principal safety barriers (primary containment), being seriously degraded. This condition is also reportable under 10 CFR 50.72(b)(3)(v)(C) as an event or condition that could have prevented fulfillment of a safety function needed to control the release of radioactive material. The NRC Resident Inspector was notified. | Primary containment | |
| ENS 53409 | 17 May 2018 20:03:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | Emergency Diesel Generators Inoperable | On May 17, 2018, with the Unit in Mode 4, Clinton Power Station experienced the concurrent inoperability of two Emergency Diesel Generators (DG). This event is being reported as an 8-hour non-emergency notification per 10 CFR 50.72(b)(3)(v) as, 'Any event or condition that at the time of discovery could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident.' On May 17, 2018, at 15:03 CDT, it was identified that the Division 2 DG air start receiver isolation valves 1DG160 and 1DG161 were shut. With these valves shut, the Division 2 DG is inoperable. At the time, Division 1 DG was also inoperable for a 4160V 1A1 partial bus outage. The Technical Specification (TS) Actions for TS 3.8.2, AC Sources Shutdown, and TS 3.5.2, RPV Water Inventory Control, were entered as a result of the inoperability of the onsite AC power sources to isolation valves being credited to limit RPV DRAIN TIME. Division 2 DG air receivers were realigned at 15:45 CDT and the Division 2 DG auto start function was restored. Offsite power was available throughout this event and there was no impact to the health and safety of the public or plant personnel. Investigation is ongoing. It has been determined that the air start receiver isolation valves remained closed following system restoration on May 11, 2018. However, the Division 2 DG was not required to be Operable by TS until 00:45 CDT on May 14, 2018 when the Division 1 DG was made inoperable as a result of scheduled plant maintenance. The NRC Resident Inspector has been notified. | Emergency Diesel Generator | |
| ENS 53463 | 20 June 2018 05:00:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | High-Pressure Core Spray Inoperable | On June 20, 2018, at 1145 hours (CDT), during panel walkdown, it was identified that High-Pressure Core Spray (HPCS) injection valve 1E22F004 was in the open position. Valve 1E22F004 is normally closed for containment integrity purposes. Operations personnel verified that the valve was open locally and that the plant computer indicated the valve is in the 'not closed' position. No alarms or status lamps indicated why the valve would be open and there was no valid demand signal. Reactor power, pressure, level, and feedwater parameters remain steady and unchanged, with no indication of HPCS injection having occurred or in progress. A low-water level signal, or a high drywell pressure signal, or manual operation initiates HPCS. When a high-water level in the reactor vessel is detected, HPCS injection is automatically stopped by a signal to close injection valve 1E22F004. With valve 1E22F004 in the open position without a demand signal, closure on a high reactor water level condition was not assured. Therefore, HPCS was declared inoperable. The following Technical Specifications were entered: 3.5.1, Emergency Core Cooling Systems (ECCS) - Operating and 3.6.1.3, Primary Containment Isolation Valves (PCIVs). Subsequently, HPCS injection valve 1E22F004 was observed to be cycling without operator action. The valve was deactivated in the closed position to assure the containment isolation function. The cause of valve 1E22F004 cycling without operator action is under investigation. HPCS is a single train safety system that consists of a single motor-driven pump, a spray sparger in the reactor vessel, and associated piping, valves, controls and instrumentation. HPCS is part of the ECCS network, which also includes Low-Pressure Core Spray, Low-Pressure Coolant Injection, and the Automatic Depressurization system. This event is being reported as an 8-hour non-emergency notification per 10 CFR 50.72(b)(3)(v) as, 'Any event or condition that at the time of discovery could have prevented the fulfillment of the safety function of structures or systems that are needed to: (A) Shut down the reactor and maintain it in a safe shutdown condition; (B) Remove residual heat; (C) Control the release of radioactive material; or (D) Mitigate the consequences of an accident.' The licensee notified the NRC Resident Inspector. | Feedwater Primary containment Core Spray Automatic Depressurization System Emergency Core Cooling System | |
| ENS 53824 | 13 January 2019 14:30:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | En Revision Imported Date 3/8/2019 | EN Revision Text: HIGH PRESSURE CORE SPRAY SELF TEST FAILURE On January 13, 2019, the Self Test System reported a fault associated with the logic system for the High Pressure Core Spray (HPCS) high reactor water level closure function that could prevent the system from performing its safety function. The HPCS system was subsequently declared inoperable with actions taken per LCO (Limiting Condition for Operation) 3.6.1.3 to close and deactivate the 1E12-F004 valve, a primary containment isolation valve. Since HPCS is an emergency core cooling system and is a single train safety system, this condition is reportable under 10 CFR 50.72(b)(3)(v)(D) 'Any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident.' The NRC Resident Inspector has been notified. HPCS is in a 14-day technical specification LCO action statement.
Testing of the logic system load driver card for the High Pressure Core Spray (HPCS) high reactor water level closure function was completed both on site and at General Electric Hitachi (GEH). This testing determined the cause of the self-test system fault report was limited to the self-test portion of the load driver card and did not impact the ability of HPCS system to perform its specified safety function. Based on the testing results, this event is not reportable under 10 CFR 50.72(b)(3)(v)(D), 'Any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident.' Therefore, EN 53824 is being retracted. The NRC Resident Inspector has been notified. Notified the R3DO (Hills). | Primary containment High Pressure Core Spray Emergency Core Cooling System | |
| ENS 54197 | 3 August 2019 07:26:00 | 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 | En Revision Imported Date 8/7/2019 | EN Revision Text: AUTOMATIC REACTOR SCRAM ON LOW REACTOR WATER LEVEL At 0226 (CDT), an automatic scram on low reactor water level occurred due to a trip of the 'B' Reactor Feed pump. All control rods fully inserted. Reactor water level 2 was reached and the High Pressure Core Spray system, Reactor Core Isolation Cooling system, Division 3 diesel generator, Standby Gas Treatment Systems 'A' and 'B' and all shutdown safety related service water pumps started as expected. Reactor Core Isolation Cooling and High Pressure Core Spray injected as expected. All level 2 containment isolation signals occurred as expected and all level 2 containment valves closed as expected. Reactor water level is currently being controlled in band by condensate. Reactor pressure is being maintained by main turbine Bypass Valves. This event is being reported under 10 CFR 50.72(b)(2)(iv)(A), for ECCS discharge to RCS; 10 CFR 50.72(b)(2)(iv)(B), for RPS actuation, and 10 CFR 50.72(b)(3)(iv)(A), for specified system actuation. The NRC Senior Resident Inspector has been notified. No safety relief valves lifted during the transient. The plant is in a normal shutdown electrical lineup with all safety equipment available. The licensee notified the Illinois Emergency Management Agency per their communications protocol.
Following automatic initiation of the High Pressure Core Spray (HPCS) System as described above, the HPCS System was manually secured following station procedures after verification that additional RPV (reactor pressure vessel) injection was no longer required. Securing HPCS injection in this manner prevents automatic restart of the system in the event of a subsequent low RPV level condition, rendering it inoperable. As the HPCS system is considered a single train safety system, this meets the reportability requirements of 10 CFR 50.72(b)(3)(v)(D). This reportable condition was identified following review of post-scram actions. The HPCS system has been restored to a Standby lineup. The licensee will be notifying the NRC Resident Inspector. Notified R3DO (Pelke).
Following the scram, the Primary Containment to Secondary Containment and the Drywell to Primary Containment differential pressure limits were exceeded. Technical Specification (TS) Limiting Condition for Operation (LCO) 3.6.1.4, Primary Containment Pressure, and 3.6.5.4, Drywell Pressure, Actions A.1, B.1, and B.2 were entered. Primary Containment to Secondary Containment differential pressure and Drywell to Primary Containment differential pressure were restored to within the LCO limits at 1505 on 8/3/19 and the associated TS Actions were exited. This event is reportable under 10 CFR 50.72(b)(3)(ii)(B) as an unanalyzed condition that could have prevented the fulfillment of the primary containment function due to being outside the initial conditions to ensure that drywell and containment pressures remain within design values during a loss of coolant accident. This event is also reportable under 10 CFR 50.72(b)(3)(v)(C) as an event or condition that could have prevented the fulfillment of the drywell and primary containment functions to control the release of radioactive material for the same reason. The licensee notified the NRC Resident Inspector. Notified R3DO (Pelke). | Secondary containment Service water Reactor Core Isolation Cooling Primary containment High Pressure Core Spray Standby Gas Treatment System Safety Relief Valve Control Rod | |
| ENS 54281 | 16 September 2019 13:17:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | Accident Mitigation | On 9/16/19 at 0817 CDT, the Division 1 and Division 2 reactor water cleanup (RT) system differential flow instrumentation was declared inoperable due to failing downscale caused by flashing in the sensing lines that occurred during reactor cooldown for refueling outage C1R19. The Division 1 and Division 2 RT differential flow instrumentation were declared inoperable in accordance with Technical Specification 3.3.6.1 Conditions D and E which require restoring at least one division of instruments to operable status within one hour. This condition renders the leakage detection system incapable of performing its safety function, thus it is reportable under 10 CFR 50.72(b)(3)(v)(D). In response to the above, system alignment was changed to increase subcooling to restore indication. Division 1 and 2 Division RT differential flow instrumentation were declared operable at 0852 on 9/16/19. The NRC Resident Inspector has been notified. | Reactor Water Cleanup | |
| ENS 54403 | 21 November 2019 18:25:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | EN Revision Imported Date : 1/13/2020 UNIT 1 HIGH PRESSURE CORE SPRAY INOPERABLE On 11/21/2019, at 1225 CST, as a result of Division 4 DC bus voltage oscillations, bus voltage lowered to less than the required improved technical specification (ITS) voltage of 127.6 VDC. This resulted in declaring High Pressure Core Spray (HPCS) system inoperable per technical specification LCO 3.8.4 and 3.8.9 actions. Division 4 DC bus voltage was restored to greater than 127.6 VDC at 1227 CST. The HPCS system remains inoperable due to Division 4 DC battery charger inoperability. Since HPCS is an emergency core cooling system and is a single train safety system, this condition is reportable under 10 CFR 50.72(b)(3)(v)(D). The NRC Resident Inspector has been notified. Clinton Power Station has implemented required compensatory actions due to the Division 4 DC battery charger and HPCS remaining inoperable.
The purpose of this notification is to retract a previous report made on 11/21/2019 (EN 54403) under 10 CFR 50.72(b)(3)(v)(D). Subsequent to the initial notification, the event and the NRC guidance in NUREG-1022 pertaining to 10 CFR 50.72(b)(3)(v)(D) were reviewed further. The evaluation determined that the Division 4 DC bus voltage oscillations were caused by a degraded but operable charger. The Division 4 battery remained fully charged during the event and its operability was not impacted. Therefore, the HPCS system remained Operable. Under these circumstances, this event does not represent an inoperability of an accident mitigation system under 10 CFR 50.72(b)(3)(v)(D). Therefore, EN 54403 is retracted. The NRC Resident Inspector has been notified. Notified R3DO (Hanna). | High Pressure Core Spray Emergency Core Cooling System | ||
| ENS 55002 | 17 November 2020 01:18:00 | 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident | Both Trains of Main Control Room Ventilation and Air Conditioning Systems Inoperable | At 1918 CST on 11/16/2020, it was discovered both required trains of the Main Control Room Ventilation and Air Conditioning systems were simultaneously inoperable. Due to these inoperabilities, the systems were in a condition that could have prevented the fulfillment of a safety function; therefore, this condition is being reported as an eight-hour, non-emergency notification per 10 CFR 50.72(b)(3)(v). Subsequent post-maintenance testing demonstrated that the Division 1 Main Control Room Ventilation system was available at the time of the event and was restored to operable status at 2036 CST on 11/16/2020. There was no impact on the health and safety of the public or plant personnel. The NRC Resident Inspector has been notified. |