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 Entered dateSiteRegionReactor typeEvent description
ENS 5382413 January 2019 17:49:00ClintonNRC Region 3

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.

  • * * RETRACTION AT 1908 EST ON 3/7/19 FROM JAMES FORMAN TO JEFF HERRERA * * *

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).

ENS 5369828 October 2018 08:57:00ClintonNRC Region 3At 0445 (CDT), with reactor power less than 1% rated thermal power on Instrument Range Monitor (IRM) ranges 6 and 7, Clinton Power Station received an automatic Reactor Protection System (RPS) actuation. The Reactor Scram Off Normal procedure was entered and all control rods were verified to be fully inserted. The apparent cause of the scram is cold water injection causing an upscale trip of the IRMs due to Motor Driven Reactor Feedwater Pump (MDRFP) Feedwater Regulating valve 1FW004 valve coming off the full shut seat momentarily. All systems responded appropriately following the scram and the plant is currently stable. Clinton Power Station will be proceeding to Mode 4 to support the planned Maintenance Outage. The NRC Senior Resident Inspector has been notified."
ENS 5362326 September 2018 15:10:00ClintonNRC Region 3At 0946 CDT on 9/26/2018, a disruption in power to the offsite 138 kV line and the subsequent trip of the Emergency Reserve Auxiliary Transformer (ERAT) Static VAR Compensator (SVC) resulted in a degraded voltage signal on the Division 1- 4.16 kV safety bus. The degraded voltage signal resulted in a trip of the ERAT feed to the bus, blocking closure of the 345 kV Reserve Auxiliary Transformer (RAT) feed to the bus and auto start of the Division 1 Emergency Diesel Generator (EDG). The Division 1 EDG successfully started and re-energized the Division 1- 4.16 kV bus as designed. The unit is stable with the Division 1 EDG carrying the Division 1- 4.16 kV bus. The Ameren Transmission System Operator in St. Louis, MO informed the station that they had received a report that a 138 kV to 13.8 kV transformer at Clinton Route 54 substation was on fire and the South feed to the Tabor substation cycled as a result of this fault. The NRC Resident Inspector and Illinois Emergency Management Agency Resident Inspector have been notified."
ENS 5346320 June 2018 17:51:00ClintonNRC Region 3On June 20, 2018, at 1145 hours (CDT), during panel walkdown, it was identified that High-Pressure Core Spray (HPCS) injection valve 1E22F004 was in the open position. Valve 1E22F004 is normally closed for containment integrity purposes. Operations personnel verified that the valve was open locally and that the plant computer indicated the valve is in the 'not closed' position. No alarms or status lamps indicated why the valve would be open and there was no valid demand signal. Reactor power, pressure, level, and feedwater parameters remain steady and unchanged, with no indication of HPCS injection having occurred or in progress. A low-water level signal, or a high drywell pressure signal, or manual operation initiates HPCS. When a high-water level in the reactor vessel is detected, HPCS injection is automatically stopped by a signal to close injection valve 1E22F004. With valve 1E22F004 in the open position without a demand signal, closure on a high reactor water level condition was not assured. Therefore, HPCS was declared inoperable. The following Technical Specifications were entered: 3.5.1, Emergency Core Cooling Systems (ECCS) - Operating and 3.6.1.3, Primary Containment Isolation Valves (PCIVs). Subsequently, HPCS injection valve 1E22F004 was observed to be cycling without operator action. The valve was deactivated in the closed position to assure the containment isolation function. The cause of valve 1E22F004 cycling without operator action is under investigation. HPCS is a single train safety system that consists of a single motor-driven pump, a spray sparger in the reactor vessel, and associated piping, valves, controls and instrumentation. HPCS is part of the ECCS network, which also includes Low-Pressure Core Spray, Low-Pressure Coolant Injection, and the Automatic Depressurization system. This event is being reported as an 8-hour non-emergency notification per 10 CFR 50.72(b)(3)(v) as, 'Any event or condition that at the time of discovery could have prevented the fulfillment of the safety function of structures or systems that are needed to: (A) Shut down the reactor and maintain it in a safe shutdown condition; (B) Remove residual heat; (C) Control the release of radioactive material; or (D) Mitigate the consequences of an accident.' The licensee notified the NRC Resident Inspector.
ENS 5330330 March 2018 20:47:00ClintonNRC Region 3GE-6On 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.
ENS 531109 December 2017 18:42:00ClintonNRC Region 3GE-6

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.

  • * * UPDATE FROM DALE SHELTON TO VINCE KLCO AT 1658 EST ON 12/10/2017 * * *

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).

  • * * UPDATE FROM MICHAEL ANTONELLI TO VINCE KLCO ON 12/11/17 AT 1805 EST * * *

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).

ENS 5286217 July 2017 10:55:00ClintonNRC Region 3GE-6The following information is provided as a 60-day telephone notification to the NRC in accordance with 10 CFR 50.73(a)(1) reported under 10 CFR 50.73(a)(2)(iv)(A) for an invalid actuation of the Division 3 emergency diesel generator (DG). The event occurred on May 18, 2017, at 1115 CDT. As allowed by 10 CFR 50.73(a)(1), the notification is being made via telephone. (a) The specific train(s) and system(s) that actuated were: During troubleshooting of blown fuses for the Reserve Auxiliary Transformer (RAT) main feed metering and relaying circuit, the Division 3 DG automatically started as a result of a loss of power signal, the RAT feed breaker for the offsite power source opened after a 15 second time delay as a result of a degraded voltage signal, and the DG output breaker subsequently closed. The loss of voltage and degraded voltage signals were generated when maintenance technicians opened the wrong test switch in the Division 3 4160-Volt Switchgear 1E22S004. (b) Whether each train actuation was complete or partial: Upon receiving the simulated loss of voltage and degraded voltage signals, the Division 3 DG started and the DG breaker closed as expected. No additional actuations occurred. (c) Whether or not the system started and functioned successfully: Upon receiving the simulated loss of voltage and degraded voltage signals, the Division 3 DG and the DG breaker were verified to have properly functioned in response to the invalid signals. The NRC Resident Inspector has been notified.
ENS 5280615 June 2017 13:14:00ClintonNRC Region 3GE-6At 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.
ENS 5280011 June 2017 01:00:00ClintonNRC Region 3GE-6At 2256 CDT on 6/10/17, Clinton operators manually scrammed the reactor from 99 percent power due to a loss of feedwater heating. The scram was uncomplicated and the plant is stable and in mode 3. All rods inserted and decay heat is being removed by the condenser. All offsite power is available. The cause of the loss of feedwater heating is under investigation. The NRC Resident Inspector and the State of Illinois have been notified.
ENS 527822 June 2017 11:13:00ClintonNRC Region 3GE-6On 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.
ENS 5277730 May 2017 22:22:00ClintonNRC Region 3GE-6At 2038 (CDT), Clinton Power Station received an automatic RPS (Reactor Protection System)actuation. EOP-1 (Emergency Operating Procedure) was entered on RPV (Reactor Pressure Vessel) Level 3. The cause of the scram is unknown at this time. All systems responded appropriately following the scram and the plant is currently stable. Reactor level is being maintained by normal feedwater and decay heat is being removed to the main condenser via the steam dump bypass valves. The plant is in a normal shutdown electrical lineup. The plant main generator was synchronized to the electrical grid and the plant was conducting control rod scram time testing at the time of the reactor trip. The licensee notified the NRC Resident Inspector.
ENS 5275214 May 2017 16:09:00ClintonNRC Region 3GE-6At 0730 (CDT) on 5/14/2017, a visitor was working in the Protected Area (PA) on the turbine building roof and discovered a blue 12 ounce can of beer in their cooler. This was discovered when the visitor was removing items from their cooler into a larger community cooler. The visitor immediately notified their escort of the prohibited item. The escort then notified Security of the event. Security took possession of the item and the individual was escorted offsite. The individual stated when they packed their cooler at home they thought they had picked up a blue can of soda and did not notice it was a blue can of beer. This event is being reported per 10CFR26.719(b). The licensee notified the NRC Resident Inspector.
ENS 5275012 May 2017 08:20:00ClintonNRC Region 3GE-6At 0045 (CDT) on May 12, 2017, it was discovered that a Primary Containment local leak rate test performed on Main Steam Isolation Valves (MSIV) exceeded its acceptance criteria. During Modes 1, 2, and 3, Technical Specification Surveillance Requirement 3.6.1.3.9 requires MSIV leakage for a single MSIV line to be less than or equal to 100 standard cubic feet per hour (scfh) (47,195 sccm) and requires the combined leakage rate for all MSIV leakage paths to be less than or equal to 200 scfh (94,390 sccm) when tested at 9 psig. As-found for the 'D' MSIV line leakage is 53,921.61 standard cubic centimeter per minute (sccm) for the 'D' Inboard MSIV 1B21F022D and 59,698.8 sccm for the 'D' Outboard MSIV 1B21F028D. As-found combined MSIV min-path leakage is 102,463 sccm. This event is being reported as a condition of the nuclear power plant, including its principal safety barriers, being seriously degraded per 10 CFR 50.72(b)(3)(ii)(A) since the Primary Containment Isolation Valves leakage limits for MSIVs were exceeded. The NRC Resident Inspector has been notified.
ENS 527293 May 2017 15:04:00ClintonNRC Region 3GE-6At 0204 (CDT) on 5/3/2017, a facilities person was removing the trash bags from the garbage can in the restroom of the Administrative Building inside the Protected Area. While emptying the trash, they discovered a 100ml alcoholic beverage container in the trash. The container was empty, however, there was an odor of alcohol coming from the bottle. The item was turned over to the security department. The investigation identified the last time this trash bag had been changed out was on 5/2/2017 at 1530 (CDT). This event is being reported per 10CFR26.719(b). The licensee has notified the NRC Resident Inspector.
ENS 526019 March 2017 10:57:00ClintonNRC Region 3GE-6On March 7, 2017, Division 2 Residual Heat Removal (RHR) system was inoperable due to a scheduled maintenance system outage window. At 2258 (CST), Operations identified a Division 1 Unit Substation Switchgear relay was cycling, which is part of the Division 1 AC Power system. The specific relay could not be identified at the time. Division 1 AC Power systems were protected. On March 8, 2017 at 1830 hours, Division 2 RHR was restored to operable status. On March 9, 2017 at 0319 hours, Operations declared Division 1 Emergency Diesel Generator (EDG) inoperable due to the (identification of the) Division 1 relay as related to properly tripping non-essential loads on a bus under-voltage condition. The relay would not have actuated to trip non-essential loads. The proper tripping of non-essential loads is a requirement for Division 1 EDG. The Updated Safety Analysis Report (USAR) Emergency Core Cooling Systems (ECCS) analysis specifies with the Division 1 DG failure, the remaining systems available are: Automatic Depressurization System (ADS), High Pressure Core Spray (HPCS), and 2 Low Pressure Core Injection (LPCI) systems. As a result of Division 2 RHR (being) inoperable at the same time Division 1 EDG was inoperable, an unanalyzed condition existed. While Division 2 RHR was inoperable, Division 1 EDG was inoperable. Technical Specification (TS) Limiting Condition of Operation (LCO) 3.8.1, AC Sources - Operating, was not met. Condition B, One Required DG Inoperable, Required Action B.2 declares required features, (normally) supported by the inoperable DG, inoperable when the redundant required features are inoperable, with a completion time of 4 hours. The action would have required declaring Division 1 ECCS inoperable, which includes Division 1 RHR and Low Pressure Core Spray (LPCS). With Division 1 EDG, Division 1 RHR, and Division 2 RHR inoperable, the station did not satisfy the USAR ECCS analysis and was in an unanalyzed condition. This condition is reportable under 10 CFR 50.72(b)(3)(ii)(B), Unanalyzed Condition, since the condition occurred within three years of the date of discovery. The NRC Resident Inspector has been notified.
ENS 5257625 February 2017 04:23:00ClintonNRC Region 3GE-6At 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.
ENS 5255516 February 2017 13:03:00ClintonNRC Region 3GE-6On February 15, 2017 at 1515, it was discovered by corporate Fitness for Duty (FFD) personnel that an unescorted access reactivation feature in the security database (Illuminate) does not reset the flag to include an individual in the random FFD pool due to a database coding error. The Illuminate database was implemented fleet-wide 1/3/17. Review by corporate FFD personnel found one individual currently badged at Clinton Power Station was affected by the coding error. The individual was not in the FFD random pool from 1/3/17 until 2/15/17. Corporate security personnel found no other individuals to be affected by this issue. Affected individual was added to the FFD random pool. Corporate security personnel notified all Exelon sites of the issue. Sites were notified that the ability to use the re-activation feature in Illuminate would be removed from use by site personnel. Pending removal, a daily query would be run in the database to assure the re-activation feature had not been used by site personnel. The licensee informed the NRC Resident Inspector.
ENS 5237718 November 2016 13:40:00ClintonNRC Region 3GE-6During the NRC CDBI (Component Design Basis Inspection), it was identified that the calculation used to demonstrate Control Room Habitability following a Design Basis Accident (DBA) utilized an inappropriate methodology. Specifically, the calculation used dual air inlets for the emergency zones as the type of system used for Main Control (Room) Ventilation (VC) system. In order to use the dual inlet type system in the analysis, each of the VC subsystems is required to be single failure proof. The VC system is single failure proof, but the individual subsystems at the inlet, as designed, are not. The dual inlet type system allows for certain calculated dose concentrations to be reduced by a factor of 4. Elimination of this reduction factor results in higher calculated control room dose following a DBA which exceeds the 5 Rem limit. This event is reportable under 10 CFR 50.72(b)(3)(ii)(B), 'Any event or condition that results in the nuclear power plant being in an unanalyzed condition that significantly degrades plant safety.' A standing order has been issued for compensatory actions in the event of an emergency. The licensee notified the NRC Resident Inspector.
ENS 5210218 July 2016 22:43:00ClintonNRC Region 3GE-6Testing of the Everbridge ERO (Emergency Response Organization) notification system identified the system cannot notify all ERO individuals. This constitutes a loss of offsite communications capability. The issue has subsequently been reported resolved by the vendor. Emergency Response Data System (ERDS) capability was not lost. The Everbridge system capability loss for the common ERF (EOF at Cantera) was identified at approximately 1500 CDT on July 18, 2016. Site and EOF testing verified resolution at 2029 CDT. This event is reportable under 10 CFR 50.72(b)(3)(xiii) as a loss of communications capability. The licensee will notify the NRC Resident Inspector.
ENS 5204324 June 2016 19:45:00ClintonNRC Region 3GE-6

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.

ENS 5193917 May 2016 18:43:00ClintonNRC Region 3GE-6On May 17, 2016 with the plant in Mode 4 (Cold Shutdown) during a refueling outage, personnel entered the drywell to perform a walkdown. At 0945 CDT, water was identified leaking from flexible hoses located at the inner elbow of MSL (Main Steam Line) B and MSL C. It was concluded that the leakage was from an elbow tap welded to the flexible hoses associated with flow instrumentation on MSL C and MSL B. Due to the refueling outage, the plant subsequently entered Mode 5 at 0955 and is currently in Mode 5 (Refueling) and 0 percent rated thermal power. The degraded component on MSL B was previously replaced in 2008 and on MSL C in 2007. The station has determined that this event is reportable under the provisions of 10 CFR 50.72 (b)(3)(ii)(A) as an event or condition that resulted in the condition of the nuclear power plant, including its principal safety barriers being seriously degraded, as an 8-hour notification. The NRC Resident Inspector has been notified.
ENS 518452 April 2016 18:27:00ClintonNRC Region 3GE-6At 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.
ENS 5183630 March 2016 20:45:00ClintonNRC Region 3GE-6At 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.
ENS 5173213 February 2016 09:09:00ClintonNRC Region 3GE-6

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.

ENS 5166920 January 2016 18:31:00ClintonNRC Region 3GE-6At 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--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.
ENS 5142828 September 2015 20:28:00ClintonNRC Region 3GE-6At 1444 CDT on September 28, 2015, the station's seismic instrumentation generated a seismic event alarm that was determined to be invalid based upon no seismic activity being felt on site, and no activity detected in the area by either the National Earthquake Information Center, or nearby nuclear plants. The instrumentation that actuated recorded steady values of -0.3 to -0.4g on three axes of one instrument, which is greater than the +/- 0.02g threshold value in the Emergency Action Level in the station's emergency procedures; however, no other instrument channel or axis indicated a valid event exceeding the 0.02g threshold. Since the event alarm was determined to be invalid as described above, no EAL thresholds were met. The seismic instrumentation was declared non-functional since it would not generate a seismic event alarm during an actual event until the invalid event was reset. The alarm was reset through the alarm reset process. The seismic instrumentation alarm capability was restored and returned to service at 1746. The Seismic Instrumentation remains non-functional pending troubleshooting. This resulted in a Loss of Emergency Assessment Capability while the seismic instrumentation was out of service. This is a reportable condition in accordance with 10 CFR 50.72(b)(3)(xiii). The licensee has notified the NRC Resident Inspector. This is a recurring event. See EN #51263 and EN #51282.
ENS 5132417 August 2015 13:01:00ClintonNRC Region 3GE-6At 0505 CDT on August 17, 2015, Clinton Power Station's Seismic Instrumentation system was removed from service to support scheduled maintenance. During this time, the seismic instrumentation will not be able to generate Main Control Room annunciation or provide ground acceleration information necessary for Emergency Action Level (EAL) threshold determination until the seismic instrumentation is restored. Since the duration of the maintenance activity is expected to last greater than 24 hours, with no viable compensatory measure specified in the EAL's, this condition will result in a loss of emergency assessment capability while the Seismic Instrumentation is out of service and results in a reportable condition in accordance with 10 CFR 50.72(b)(3)(xiii). The licensee has notified the NRC Resident Inspector and the licensee has informed the State of Illinois Resident Engineer. The licensee also notified the State of Illinois Emergency Management Agency.
ENS 512821 August 2015 15:28:00ClintonNRC Region 3GE-6At 1205 CDT on August 01, 2015, the station's Seismic Instrumentation generated a seismic event alarm that was determined to be invalid, based upon no seismic activity being felt on site and no activity detected in the area by either the National Earthquake Information Center or nearby nuclear plants. The instrumentation that actuated, recorded a value of 0.07 g on a single axis of one instrument, which is greater than the 0.02 g threshold value in the Emergency Action Level in the station's emergency procedures; however, no other instrument channel or axis indicated a valid event exceeding the 0.02 g threshold. Since the event alarm was determined to be invalid as described above, no EAL thresholds were met. The seismic instrumentation was declared non-functional since it would not generate a seismic event alarm during an actual event until the invalid event was reset. The alarm was reset through the alarm reset process. The seismic instrumentation alarm capability was restored and returned to service at 1250 CDT. This resulted in a Loss of Emergency Assessment Capability while the Seismic Instrumentation was out of service. This is a reportable condition in accordance with 10 CFR 50.72(b)(3)(xiii). The licensee has notified the NRC Resident Inspector. The licensee performed a channel calibration in response to the previous Seismic Instrumentation malfunction (see EN # 51263) and plans to perform more extensive troubleshooting in response to the latest malfunction. The licensee will notify the State of Illinois plant inspector.
ENS 5126326 July 2015 11:50:00ClintonNRC Region 3GE-6At 0449 CDT on July 26, 2015, the station's Seismic Instrumentation generated a seismic event alarm that was determined to be invalid based upon no seismic activity being felt on site, and no activity detected in the area by either the National Earthquake Information Center, or nearby Exelon plants. The instrumentation that actuated recorded a value of 0.0449 g on a single axis of one instrument, which is greater than the 0.02 g threshold value in the Emergency Action Level in the station's emergency procedures; however, no other instrument channel or axis indicated a valid event exceeding the 0.02 g threshold. Since the event alarm was determined to be invalid as described above, no EAL thresholds were met. The seismic instrumentation was declared non-functional since it would not generate a seismic event alarm during an actual event until the invalid event was reset. The alarm was reset through the alarm reset process. The seismic instrumentation was declared functional and returned to service at 0520. This resulted in a Loss of Emergency Assessment Capability while the Seismic Instrumentation was out of service. This is a reportable condition in accordance with 10 CFR 50.72(b)(3)(xiii). The licensee has notified the NRC Resident Inspector.
ENS 5122110 July 2015 14:57:00ClintonNRC Region 3GE-6At 0710 CDT on July 10, 2015, Exelon was notified by the siren vendor that siren CL27 experienced a communications failure during the daily test. Siren CL27 affects 33.9% of the Clinton EPZ population. The loss of communications represents more than 25% of the EPZ population and is therefore reportable under 10 CFR 50.72(b)(3)(xiii). The siren vendor is currently investigating to repair the issue. The DeWitt County Emergency Manager has been notified. DeWitt County has implemented the backup means of notification called 'Route Alerting' in lieu of siren communications. Route Alerting consists of vehicles and public address systems. The NRC Senior Resident has been notified. 1300 - Siren returned to service.
ENS 512088 July 2015 13:23:00ClintonNRC Region 3GE-6The following information is provided as 60-day telephone notification to the NRC in accordance with 10 CFR 50.73(a)(1) reported under 10 CFR 50.73(a)(2)(iv)(A) for an invalid actuation of the Division 2 emergency diesel generator (DG). The event occurred on May 11, 2015, at 0119 CDT. As allowed by 10 CFR 50.73(a)(1), the notification is being made via telephone. (a) The specific train(s) and system(s) that actuated were: During the restoration from surveillance test procedure CPS 9080.25, 'DG 1B Test Mode Override, Load Reject Operability and Idle Speed Override,' the Division 2 DG automatically started. The Division 2 DG started when the maintenance technicians improperly removed a temporary toggle switch installed for simulation of a Loss of Coolant Accident (LOCA) signal. (b) Whether each train actuation was complete or partial: Upon receiving the simulated LOCA signal, the Division 2 DG started as expected. No additional actuations occurred. (c) Whether or not the system started and functioned successfully: Upon receiving the simulated LOCA signal, the Division 2 DG started and was verified to have properly started in response to a start signal. The NRC resident has been notified.
ENS 5117925 June 2015 09:27:00ClintonNRC Region 3GE-6At 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.
ENS 510384 May 2015 13:05:00ClintonNRC Region 3GE-6

At approximately 0615 (CDT) on 5/4/2015, the Area Radiation (AR)/Process Radiation (PR) Local Area Network (LAN) lost power following preparation for a planned Unit Sub 1M outage during the current refueling outage. Preparations for this planned outage included de-energizing the plant process computer data diode uninterruptible power supply that in turn caused a loss of power to the AR/PR LAN. As a result of this power loss, indication was lost in the Main Control Room for the main HVAC and Standby Gas Treatment System effluent radiation monitors without any viable compensatory measure to determine Total Noble Gas Release Rates. The station has determined that this constitutes a major loss of assessment capability per 10 CFR 50.72(b)(3)(xiii). Local radiation monitors continue to function properly. Power to the AR/PR LAN has been restored. Time of restoration was 1159 CDT. There is no impact to current plant operation. The NRC Resident Inspector has been notified.

  • * * RETRACTION PROVIDED BY MARK CONSTABLE TO JEFF ROTTON AT 1420 EST ON 12/02/2015 * * *

This event has been reviewed and it was determined that the radioactive release rates displayed on the Safety Parameter Display System screens are obtained directly from the associated radiation monitors (0RIX-PR008 and 0RIX-PR012) and HVAC stack and Standby Gas Treatment System stack flow monitors (0UIX-PR050 and 0UIX-PR051) and are not processed through the AR/PR LAN. As a result, there was no loss of radiation release Emergency Action Level assessment capability with a loss of the AR/PR LAN. Therefore, there was no major loss of emergency assessment capability and this event is not reportable. The NRC Resident Inspector has been notified. Notified R3DO (Lipa)

ENS 5099921 April 2015 12:06:00ClintonNRC Region 3GE-6Clinton Power Station (CPS) has completed a review of the station seismic monitor performance. The CPS seismic monitor laptop is currently operable; however, this review identified 3 times in the last 3 years that the seismic monitoring laptop was declared non-functional such that the capability to perform an EAL assessment in accordance with the Radiological Emergency Plan Annex would be adversely impacted. A loss of the seismic laptop computer prevents active seismic data from processing through the central recording unit and will not alarm in the main control room. The seismic monitor laptop became non-functional and unresponsive on the following dates: 1) January 4, 2013 2) July 19, 2013 3) November 2, 2014 The loss of assessment capability is reportable to the NRC within 8 hours of discovery in accordance with 10 CFR 50.72 (b)(3)(xiii) This report is required per 10 CFR 50.72(1)(1)(ii) as an event that occurred within 3 years of the date of discovery. The NRC Resident Inspector has been notified. Notified the R3DO (Valos).
ENS 507947 February 2015 07:37:00ClintonNRC Region 3GE-6On 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.
ENS 5046316 September 2014 23:20:00ClintonNRC Region 3GE-6At 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.
ENS 5045212 September 2014 12:05:00ClintonNRC Region 3GE-6The following information is provided as 60 day telephone notification to the NRC in accordance with 10 CFR 50.73(a)(1) reported under 10 CFR 50.73(a)(2)(iv)(A) for an invalid actuation of Division 1 Shutdown Service Water (SX) and an invalid actuation signal for Division 1 Containment Isolation Group 12. This event occurred on July 26, 2014, at 1648 CDT. As allowed by 10 CFR 50.73(a)(1) this notification is made via telephone. (a) The specific train(s) and system(s) that actuated were: On July 26th, during lightning strikes on the switchyard grid system, the Division 1 SX (Shutdown Service Water) auto-started as a result of momentary loss of power to the Low Pressure Auto Start Relay. A lightning strike causing voltage transients also caused a Division 1 Group 12 Containment Isolation signal affecting DIV 1 Hydrogen monitor. (b) Whether each train actuation was complete or partial. Upon receiving the invalid signal from momentary loss of power, for Division 1 SX and Group 12 Containment Isolation signal, the systems responded as expected for existing plant conditions. For group 12 isolation, (Containment Monitoring) 1CM011/12/47 and 48 valves closed from their normally open position. For DIV 1 Shutdown Service Water (SX), the start of the Shutdown Service Water (SX) pump and alignment of valves operated as expected. The actuation was considered a complete Division 1 SX and Division 1 Group 12 Containment Isolation actuation. Containment Isolation Signals: The following Group 12 valves closed and associated shunt trips occurred on a loss of power to (Radiation Monitors) 1RIX-PR001A/1C: 1CM011, 1CM012, 1CM047, and 1CM048. (c) Whether or not the system started and functioned successfully. Upon receiving the invalid signal from momentary loss of power, Division 1 SX and Containment Isolation signals started and functioned successfully. The NRC Senior Resident Inspector has been notified.
ENS 5041027 August 2014 13:35:00ClintonNRC Region 3GE-6

At 0645 CDT on August 27, 2014, Exelon was notified that during the daily test at 0530 CDT of the offsite sirens, the vendor received an alarm on Clinton Power Station siren communications. This Emergency Preparedness (EP) siren communications issue results in 26 of the 40 EP sirens not being verified as functional, which affects 84.4% of the EPZ population. The loss of communications represents more than 25% of the EPZ population for greater than 1 hour and is therefore reportable under 10 CFR 50.72(b)(3)(xiii). The cause of issue has been isolated to a microwave link at Clinton Power Station that communicates via radio frequency to each siren. The siren vendor is currently investigating to repair the issue. The DeWitt County Emergency Manager has been notified. DeWitt County has implemented the Emergency Message System through 'Code Red' notification in lieu of siren communications. The NRC Senior Resident has been notified.

  • * * UPDATE FROM RICH CHAMPLEY TO CHARLES TEAL AT 1755 EDT ON 8/27/14 * * *

The DeWitt County Emergency Manager has been notified. DeWitt County has implemented the backup means of notification called 'Route Alerting' in lieu of siren communications. Route Alerting consists of vehicles and public address systems. At 1400 CDT only 2 sirens remain not fully functional. These 2 sirens represent 0.7% of EPZ population. Work continues to restore these 2 sirens. The NRC Senior Resident has been informed. Notified R3DO (Stone).

ENS 5011012 May 2014 17:37:00ClintonNRC Region 3GE-6At 0845 (CDT) during planned maintenance, the annunciators which would indicate flooding in the Emergency Core Cooling System (ECCS) Pump Rooms to the max safe water level in the rooms were disabled. These max safe water level alarms are used to assess the emergency action level (EAL) entry condition (HA4) for flooding (ALERT classification). Compensatory measures are in place to perform periodic walk downs of RHR A, RHR B, RHR C, HPCS, LPCS, RCIC rooms and the fuel building basement once per shift to verify no leakage. Additionally, the annunciator for max normal water level is operational and pump run times are still available in the Main Control Room to indicate increased leakage into the ECCS rooms. This max normal water level alarm is used to assess the EAL entry condition (HU4) for flooding (Unusual Event classification) and EOP-8 entry. Since the operator compensatory actions that were established are not proceduralized, then this is reportable as a loss of emergency assessment capability under 10 CFR 50.72(b)(3)(xiii). The expected return to service time of all alarms is 2300 CDT. The licensee will notify the NRC Resident Inspector.
ENS 4995825 March 2014 22:44:00ClintonNRC Region 3GE-6The plant was stable at 85 percent power when off-gas flow started lowering. The operating crew entered the loss of vacuum off-normal procedure and commenced an emergency power reduction to attempt to slow/halt the loss of vacuum while attempting various prescribed actions in the off-normal procedure. When vacuum reached 24 in. Hg, a rapid plant shutdown was performed as prescribed in the off-normal procedure. Power was at 46 percent when a rapid plant shutdown was commenced with the mode switch placed in shutdown at 1942 CDT. All control rods fully inserted on the scram, no emergency core cooling system injected or was required, no safety/relief valve(s) lifted and all systems responded as expected on the scram. The plant will remain in mode 3 with normal makeup from the feedwater system and pressure control on the turbine bypass valves with the main condenser available as a heat sink. All vital and non-vital electrical busses are powered from reserve off-site sources and no emergency diesel generators started on the scram. The cause of the loss of vacuum is under investigation. The licensee notified the NRC Resident Inspector.
ENS 4975822 January 2014 23:36:00ClintonNRC Region 3GE-6A 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.
ENS 4972515 January 2014 13:05:00ClintonNRC Region 3GE-6The following report is being made in accordance with Clinton Power Station Operating License, Appendix B, Environmental Protection Plan. On 1/14/14, an inspection of the Clinton Lake was conducted via boat of inaccessible areas. The inspection revealed more than one hundred deceased fish over several locations. The species predominantly observed were buffalo fish and carp, with some game fish identified. While no direct cause was identified for the fish loss, the fish loss closely coincides with two recent unplanned plant shutdowns that occurred in December 2013. The licensee informed the State and the NRC Resident Inspector.
ENS 4963213 December 2013 20:07:00ClintonNRC Region 3GE-6During a feed pump shift from the motor driven reactor feed pump to the 'A' turbine driven reactor feed pump during power ascension, reactor pressure vessel (RPV) water level was approaching the Reactor Protective System (RPS) automatic scram set point when a manual reactor scram was inserted. All control rods fully inserted. RPV water level is being maintained by the normal condensate booster / feedwater systems. RPV pressure is being maintained via normal main steam system. There were no actuations of any Emergency Core Cooling System and no Safety Relief Valves actuations. All systems responded as expected. The licensee notified the NRC Resident Inspector.
ENS 496179 December 2013 01:15:00ClintonNRC Region 3GE-6While 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.
ENS 4937320 September 2013 18:00:00ClintonNRC Region 3GE-6During the performance of a focused area self assessment (FASA) for the Clinton Power Station Fire Protection Program, the FASA team identified a noncompliance with the Safe Shutdown Analysis for a fire outside the Diesel Generator (DG) rooms (i.e., Fire Zone CB-1e, CB-1f, CB-2 and CB-4). The CO2 panels for each DG train are all located in the same area outside the DG engine bay rooms (i.e., 737' Control Building) and a fire in this area could cause fire damage to all three CO2 panels and/or wiring such that a trip (short) could be initiated to all three DG Ventilation (VD) fans. Loss of the VD fans (1VD01CA, B and C) results in loss of cooling in the DG rooms and ultimately loss of the diesels. This constitutes an Unanalyzed Condition that Significantly Affects Plant Safety. Compensatory measures are in-place that will allow these VD trips to be overridden and the VD fans to be restarted from the Main Control Room. The NRC Resident Inspector has been notified.
ENS 4928615 August 2013 17:53:00ClintonNRC Region 3GE-6During 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.
ENS 4897426 April 2013 12:55:00ClintonNRC Region 3GE-6On 4/26/13 at about 0855 CDT while operating at rated electrical power, operators initiated a manual reactor scram due to rapidly decreasing level in the main Electro Hydraulic Control (EHC) oil reservoir. All systems responded as expected with no complications. The cause of the main EHC decrease in level is under investigation. The plant is stable in mode 3. The NRC Resident Inspector has been notified. The licensee reports that bypass valves remain available via a separate EHC system and decay heat is being routed to the condenser.
ENS 488127 March 2013 11:52:00ClintonNRC Region 3GE-6While operating at rated electrical power, a main generator trip and subsequent turbine trip resulted in a reactor scram. The cause of the generator trip is under investigation. All systems operated as expected with no complications. The plant is stable in Mode 3. The licensee notified the NRC Resident Inspector and the State of Illinois.
ENS 4876518 February 2013 11:35:00ClintonNRC Region 3GE-6On 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.
ENS 4874011 February 2013 12:59:00ClintonNRC Region 3GE-6A non-licensed, supervisory employee had a confirmed positive for alcohol during a random fitness-for-duty test. The employee's access to the plant has been restricted. The licensee notified the NRC Resident Inspector.