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 Entered dateSiteRegionReactor typeEvent description
ENS 5330425 February 2020 10:00:00Grand GulfNRC Region 4GE-6At 0206 (CDT) on March 31, 2018, with the plant in Mode 1 at 100% rated core thermal power, Grand Gulf Nuclear Station experienced a loss of Secondary Containment. During the performance of a Standby Gas Treatment System (SGTS) drawn down test with Auxiliary Building train bay door (1A319A) as the secondary containment boundary, Grand Gulf was unable to maintain secondary containment pressure, as required by SR (surveillance requirement) 3.6.4.1.4, greater than or equal to 0.266 inches of water vacuum for 1 hour. Following initial vacuum draw down, secondary containment pressure degraded to 0.225 inches of water vacuum with operators in the field reporting air leakage from door 1A319A. The test was secured and Secondary Containment was declared inoperable and Technical Specification 3.6.1.4 A.1 was entered. Following completion of the failed surveillance test, Secondary Containment was returned to an operable status at 0315 hours on March 31, 2018, by returning the system to a previously known operable configuration by closing doors 1A310, 1A312 and 1A319. This is being report under 10 CFR 50.72(b)(3)(v)(C). The licensee has notified the NRC Resident Inspector.
ENS 5079525 February 2020 09:04:00Grand GulfNRC Region 4GE-6A reactor SCRAM occurred at 1856 CST on 2/7/15 from 100 percent core thermal power. The cause of the SCRAM appears to be a Generator/Turbine trip, but it is still under investigation. Appropriate off-normal event procedures were entered to mitigate the transient with all systems responding as designed. No loss of offsite or ESF power occurred. No ECCS initiation signals were reached, and no ECCS or Emergency Diesel Generator initiations occurred. Main Steam Isolation Valves remained open and Safety Relief Valves lifted and reseated as designed. Currently, reactor water level is being maintained by the Condensate and Feedwater system in normal band, and reactor pressure is being controlled via turbine bypass valves to the main condenser. Following the reactor SCRAM, all rods fully inserted and all systems functioned as expected. The plant is in a normal electrical lineup. The licensee has notified the NRC Resident Inspector.
ENS 4791325 February 2020 07:37:00PerryNRC Region 3GE-6

Beginning at approximately 1100 hours EDT on May 10, 2012, plant personnel will be taking the plant integrated computer system (ICS) out-of-service for planned maintenance. During the time ICS is out-of-service, the Safety Parameter Display System (SPDS), the Emergency Response Data System (ERDS), and the automatic mode calculation of the Computer Aided Dose Assessment Program (CADAP) will be unavailable. The computer outage is scheduled for two hours. In the event of an emergency, plant parameter data will be orally transmitted to the facilities through the Status Board Ring Down circuit with back-up by the Private Branch Exchange, Off Premise Exchange, and various redundant intrafacility circuits throughout the emergency facilities. The dose assessment function will be maintained during the out-of-service time period by manual input of data into CADAP and, if required, by manual calculation. The ability to open and maintain an 'open line' using the Emergency Notification System will not be affected and will be the primary means of transferring plant data to the NRC as a contingency until the ERDS can be returned to service. This event is being reported in accordance with 10 CFR 50.72(b)(3)(xiii). A follow-up notification will be made when the maintenance activities are completed and the equipment is restored. The NRC Resident Inspector has been notified.

  • * * UPDATE AT 1245 EDT ON 5/10/12 FROM MORSE TO HUFFMAN * * *

The maintenance activities were completed as scheduled and the integrated computer system and associated systems SPDS, ERDS and CADAP has been returned to service as of 1238 EDT. The licensee will notify the NRC Resident Inspector. R3DO (Giessner) notified.

ENS 5339912 May 2018 06:58:00Grand GulfNRC Region 4GE-6On 5/11/2018, at 2327 hours CDT, with the plant in Mode 5, Grand Gulf Nuclear Station was making preparations for surveillance test 06-OP-1P75-R-0003, Standby Diesel Generator 1 Functional Test. The Grand Gulf Nuclear Station experienced an auto-start of the Division 1 (Emergency) Diesel Generator (EDG) when the 15AA Bus Potential Transformer (PT) fuse drawer was racked out instead of the line PT fuse drawer for Bus 15AA feeder breaker 152-1514. This resulted in the 15AA Incoming Feeder Breaker 152-1511 from Engineered Safety Features Transformer 12 opening, de-energizing the 15AA Bus. The Division 1 EDG started and energized Bus 15AA. The Division 1 LSS SYSTEM FAIL annunciator was received and Standby Service Water A failed to start due to the 15AA Bus PT fuse drawer being racked out. Standby Gas Treatment Train B was manually initiated per the Loss Of AC Power Off Normal Emergency Procedure. Station equipment operated as expected based on the PT fuse drawer that was racked out. The Division 1 EDG was manually tripped from the Control Room because cooling from the Standby Service Water A was not available. RHR (residual heat removal) B was in Shutdown Cooling (mode) and was verified not affected The licensee has notified the NRC Resident Inspector.
ENS 533741 May 2018 20:42:00Grand GulfNRC Region 4GE-6At 1551 hrs (CDT) on 5/1/2018, with the plant in Mode 5, a division one Reactor Pressure Vessel (RPV) Level 1 signal was received; however there was no actual change in RPV level. RPV Level remained at High Water Level supporting refuel operations. This caused an actuation of division one Load Shed and Sequencing system that shed and then re-energized the 15 bus. Division one diesel generator started from standby. Residual Heat Removal pump 'A', which was in shutdown cooling mode, was lost during the bus shed, and was re-sequenced upon re-energization of the 15 bus. Upon restoration of shutdown cooling, the RHR pump discharged into the RPV. RCS temperature increased approximately 5 degrees Fahrenheit as a result of the loss of shutdown cooling. The cause of the actuation signal is under investigation. In accordance with NUREG 1022, Event Reporting Guidelines, this event is conservatively reported under 10 CFR 50.72(b)(2)(iv)(A) as an event that results in emergency core cooling system discharge into the RCS as a result of a valid signal, under 10 CFR 50.72(b)(3)(iv)(B)(8) as an event that results in the actuation of emergency ac electrical power systems, and under 10 CFR 50.72(b)(3)(v)(B) as an event or condition that at the time of discovery could have prevented the fulfillment of a safety function (remove residual heat). The licensee notified the NRC Resident Inspector.
ENS 533175 April 2018 18:23:00Grand GulfNRC Region 4GE-6On Thursday, April 5, 2018, at approximately 1117 hours Central Daylight Time, Entergy contract personnel opened the personnel hatch allowing access to the roof of the Secondary Containment Building for the purposes of performing an inspection of various items located on the roof. During the time period the individuals were on the roof, the hatch was left open. An individual was adjacent to the door with a radio and had constant communication link with the control room operator. Pursuant 10 CFR 50.72(b)(3)(v)(C), and 10 CFR 50.72(b)(3)(v)(D) this event is being reported as an event or condition that could have prevented the fulfillment of a safety function. Because the site had an individual briefed and at the door in constant communications with the control room to close the hatch if condition required such an action, this event is not viewed as an actual loss of safety function. The NRC Resident Inspector was notified.
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 5322723 February 2018 18:04:00Grand GulfNRC Region 4GE-6On February 18, 2018, Grand Gulf Nuclear Station experienced the concurrent inoperability of two Emergency Diesel Generators (DG). This event is being reported as a late 8-hour non-emergency notification per 10 CFR 50.72(b)(3)(v)(D) as an 'Event or Condition that Could Have Prevented Fulfillment of a Safety Function (Accident Mitigation).' On February 14, 2018 at 0100 (CST), the Division 2 Diesel Generator was declared inoperable, and subsequently removed from service for maintenance. On February 18, 2018 at 0006 (CST), the Division 3 Diesel Generator Jacket Water temperature exceeded the trip setpoint and Division 3 Diesel Generator was declared inoperable. The Division 2 Diesel Generator was restored and declared operable on February 18, 2018 at 0355 (CST), and the Division 3 Diesel Generator was restored and declared operable on February 18, 2018 at 1240 (CST). As a result, Technical Specification Condition 3.8.1.E was entered at 0006 (CST) on February 18, 2018 and exited at 0355 (CST) on February 18, 2018. Technical Specification Bases 3.8.1.E.1 states 'With two DGs inoperable, there is one remaining standby AC source. Thus, with an assumed loss of offsite electrical power, insufficient standby AC sources are available to power the minimum required ESF functions.' Offsite power was available throughout this event and there was no impact to the health and safety of the public or plant personnel. The NRC Resident Inspector has been notified.
ENS 5320110 February 2018 22:37:00Grand GulfNRC Region 4GE-6On 2/10/18 at 1835 CST at Grand Gulf Nuclear Station, while the 208 ft. Containment Airlock Outer Door was tagged-out for planned maintenance, the 208 ft. Containment Inner Door was determined to be inoperable. Grand Gulf had performed 06-ME-1M23-R-0001, Personnel Airlock Door Seal Air System Leak Test, on the 208 ft. Containment Airlock Inner Door which had been deemed satisfactory. While performing planned maintenance on the outer door an additional review of the paperwork determined that the test was actually unsatisfactory on the inner door. TS 3.6.1.2 Condition C was entered at 1835 CST on 2/10/18 for both 208 ft. Containment Airlock Doors being inoperable. Maintenance of the Outer Door is expected to be completed, and the airlock returned to operable status, prior to TS required action completion time. The licensee notified the NRC Resident Inspector.
ENS 5318830 January 2018 21:56:00Grand GulfNRC Region 4GE-6On 1/30/2018 at 1750 (CST), the Reactor Pressure Control Malfunctions ONEP (Off Normal Event Procedure) was entered due to main turbine load oscillations of approximately 30 MWe peak to peak. At 1822 (CST), a manual reactor scram was inserted by placing the Reactor Mode Switch in Shutdown due to continued main turbine load oscillations. Reactor SCRAM ONEP, Turbine Trip ONEP, and EP-2 were entered. Reactor water level was stabilized at 36 inches narrow range on startup level and reactor pressure stabilized at 933 psig using main turbine bypass valves. Reactor Water Level 3 (11.4 inches) was reached which is the setpoint for Group 2 (RHR to Radwaste Isolation) and Group 3 (Shutdown Cooling Isolation). No valve isolated in these systems due to all isolation valves in these groups being in their normally closed position. The lowest Reactor Water level reached was -36 inches wide range. No other safety system actuations occurred and all systems performed as designed. That event is being reported under 10CFR 50.72(b)(2)(iv)(B) as any event or condition that results in actuation of the Reactor Protection System (RPS), when the reactor is critical and also reported under 10CFR 50.72(b)(3)(iv)(A), as any event or condition that results in actuation of RPS. The MSIVs are open with decay heat being removed via steam to the main condenser using the bypass valves. Off site power is stable, and the plant is in a normal shutdown electrical lineup. RCIC (Reactor Core Isolation Cooling) was out of service for maintenance, and the reactor water level did not reach the system activation level. The cause of the main turbine load oscillations being investigated. The licensee notified the NRC Resident Inspector.
ENS 5311712 December 2017 20:34:00Grand GulfNRC Region 4GE-6At approximately 1330 CST on Tuesday, December 12, 2017, Grand Gulf Nuclear Station declared Division 3 'C' Battery inoperable due to questions concerning battery terminal connection continuity. Technical Specification 3.8.4, DC Sources - Operating, Condition E, Required Action E.1, requires the station to declare the High Pressure Core Spray System inoperable immediately. The Division 3 'C' Battery and High Pressure Core Spray System was declared operable and the LCOs (Limiting condition of operation) were declared met at 1731CST on Tuesday, December 12, 2017. Based on field measurements of terminal torque and resistance, the as-found and as-left terminal resistance micro-ohm readings indicated satisfactorily all times. Formal evaluation of the as-found condition of the battery is in progress. This report is to notify the NRC of a loss of safety function on the High Pressure Core Spray System. The NRC Resident Inspector was notified.
ENS 5311512 December 2017 17:40:00Grand GulfNRC Region 4GE-6At approximately 0918 CST on Tuesday, December 12, 2017, the Grand Gulf Nuclear Station experienced a loss of the Engineered Safety Features (ESF) Transformer 11 which was powering the Division 1 ESF bus. Subsequently, the station experienced an automatic start of the Division 1 Emergency Diesel Generator (EDG), partial isolation of the primary and secondary containment buildings and the isolation of the Reactor Core Isolation Cooling System (RCIC). It is not currently understood why the RCIC system isolated during this event. A team is investigating this issue separately from the loss of the ESF 11 transformer. The cause of the event is under investigation at this time. No other issues or unexpected events occurred. The NRC Resident Inspector has been notified of the event.
ENS 5309025 November 2017 06:02:00Grand GulfNRC Region 4GE-6

At 0238 (CST) a manual reactor scram was inserted by placing the Reactor Mode Switch in Shutdown. At 0149 (CST), with reactor power just above the point of adding heat, IRM (Intermediate Range Monitor) channels A, C, and D received a spurious upscale trip signal which immediately cleared. Upon investigation, operability of RPS (Reactor Protection System) scram function for Intermediate Range Detectors was placed in question. This event is being reported under 10 CFR 50.72(b)(2)(iv)(B), as any event or condition that results in actuation of the Reactor Protection System (RPS), when the reactor is critical. The licensee notified the NRC Resident Inspector.

  • * * UPDATE ON NOVEMBER 26, 2017, AT 1850 FROM GRAND GULF TO MICHAEL BLOODGOOD * * *

At 0238 (CST) a manual reactor scram was inserted by placing the Reactor Mode Switch in Shutdown. At 0149 (CST), with reactor power just above the point of adding heat, Intermediate Range Monitor neutron flux detector (IRM) channels A, C, and D received a spurious Upscale Trip signal which immediately cleared. Upon investigation, IRM channels A, C, and D were declared Inoperable. IRM G was already Inoperable for another reason. RPS scram function from IRM channels B, E, F, and H was always Operable and available. That event is being reported under 10CFR 50.72(b)(2)(iv)(B), as any event or condition that results in actuation of the Reactor Protection System (RPS), when the reactor is critical. This Revised Statement to Event Notification # 53090 is being made to make it clear that only four IRM channels (A, C, D, G) were Inoperable and that the IRM RPS SCRAM function was still available from the four remaining Operable IRM channels (B, E, F, and H). The licensee notified the NRC Resident Inspector. Notified R4DO (O'Keefe)

  • * * RETRACTION ON 01/16/2018 AT 1629 EST FROM JASON COMFORT TO DAVID AIRD * * *

On 11/25/17, at 0149 (CST), with reactor power just above the point of adding heat, Intermediate Range Monitor neutron flux detector (IRM) channels A, C, and D received a spurious Upscale Trip signal which immediately cleared. Upon investigation, IRM channels A, C, and D were declared Inoperable. IRM G was already Inoperable for another reason. At 0238 (CST) a manual reactor scram was inserted by placing the Reactor Mode Switch in Shutdown. RPS scram function from IRM channels B, E, F, and H was always Operable and available. That event was initially being reported under 10 CFR 50.72(b)(2)(iv)(B), as any event or condition that results in actuation of the Reactor Protection System (RPS), when the reactor is critical. After the trip alarms were received, the Operators spent approximately twenty minutes investigating possible causes and implications, and consulted with Reactor Engineering and the Shift Technical Advisor. The investigation showed that the plant was stable and the upscale IRM alarms were spurious. A review of plant technical specifications by the operators determined that a plant shutdown was not required. After further discussions, Operations concluded that a shutdown to allow further investigation of the issue was the prudent course of action. Prior to shutting down, Operations spent approximately twenty minutes reviewing procedures, notifying personnel to exit containment, and conducting a brief. The shutdown was then conducted by inserting a manual reactor scram by placing the reactor mode switch in SHUTDOWN. This was initially reported under 10 CFR 50.72(b)(2)(iv)(B) as an actuation of the RPS. Based on the sequence of events, and Operator actions in conducting the shutdown, the event is considered 'part of a pre-planned sequence during testing or reactor operation' as specified in 10 CFR 50.72(b)(2)(iv)(B) and 10 CFR 50.73(a)(2)(iv)(A). In accordance with NUREG-1022, Section 3.2.6, the event is not reportable as an actuation of RPS. The licensee notified the NRC Resident Inspector. Notified R4DO (Taylor).

ENS 530545 November 2017 17:11:00ClintonNRC Region 3GE-6At 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.
ENS 5303826 October 2017 18:18:00Grand GulfNRC Region 4GE-6

At 1055 (CDT), drywell purge supply/initial vacuum relief 1E61F003B was declared INOPERABLE for Drywell Vacuum Relief System while performing a monthly surveillance. 1E61F003B is a Division II powered valve. Division 1 Emergency Diesel Generator is INOPERABLE due to a tagout. At 1455, under LCO 3.8.1.B.2 the station declared both divisions of Drywell Vacuum Relief INOPERABLE. GGNS (Grand Gulf Nuclear Station) identified that a loss of Safety Function occurred due to a loss of two 10-inch vacuum relief lines from the Drywell required by Technical Specification 3.6.5.6 and therefore could have prevented fulfillment of its safety function. That event is being reported under 10CFR50.72(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 mitigate the consequences of an accident. Both divisions inoperable has placed the plant in a 72-hr. LCO shutdown action statement. The licensee has notified the NRC Resident Inspector.

  • * * RETRACTION FROM RALPH FLICKINGER TO HOWIE CROUCH AT 1643 EST ON 12/15/17 * * *

At 1055 (CDT on 10/26/17), Drywell purge supply/initial vacuum relief 1E61F003B was declared INOPERABLE for Drywell Vacuum Relief System while performing a monthly surveillance. 1E61F003B is a Division II powered valve. Division 1 Emergency Diesel Generator was INOPERABLE due to a tagout. At 1455 (CDT on 12/26/17), under LCO 3.8.1.B.2, the station declared both divisions of Drywell Vacuum Relief INOPERABLE. GGNS identified that a loss of Safety Function occurred due to a loss of two 10-inch vacuum relief lines from the Drywell required by Technical Specification 3.6.5.6 and therefore could have prevented fulfillment of its safety function. This was initially reported under 10 CFR 50.72(b)(2)(v)(D). Div. 1 EDG was initially taken out of service at 1455 on 10/26 for preplanned maintenance (OP-EVAL). It was subsequently declared INOPERABLE-INOP due to a visible flaw indication in the exhaust manifold (1117 on 10/27). A subsequent Maintenance Functional Failure Evaluation and Past Operability Determination concluded the diesel was capable of performing its intended function for the required mission time, and therefore met the definition of OPERABLE. NUREG-1022 provides clarification for 10 CFR 50.72(b)(2)(v). NUREG Section 3.2.7, paragraph 4, states '...unless a condition is discovered that would have resulted in the system (otherwise) being declared inoperable, reports are not required when systems are declared inoperable solely as a result of Required Actions for which the bases is the assumption of an additional random single failure (i.e., . ..LCO 3.8.1, 'AC Sources Operating,' Required Actions .., B.2, or C.1). Per ACTION 3.8.1 .B.2, both trains of Drywell vacuum and Drywell Purge were inoperable for the purposes of Tech Specs. However, the normal power supply was available to Division 1 and there were no conditions which would have rendered the Division 1 diesel inoperable. Therefore, per Section 3.2.7 of NUREG-1022, this was not a Loss of Safety Function and was not reportable under 50.72(b)(2)(v)(D). The licensee has notified the NRC Resident Inspector. Notified R4DO (Deese).

ENS 530004 October 2017 05:53:00PerryNRC Region 3GE-6

On October 4, 2017, at 0250 hours (EDT), the Perry Nuclear Power Plant commenced a Technical Specification (TS) shutdown by lowering reactor power from 100 percent rated thermal power to 98 percent to comply with TS LCO 3.0.3. Reactor power was further reduced to 82 percent rated thermal power at 0430 hours (EDT). The plant had entered TS 3.0.3 at 0155 hours (EDT) upon loss of MCC (Motor Control Center), Switchgear, and Miscellaneous Electrical Equipment Areas HVAC System train A while train B was removed from service for maintenance. MCC switchgear ventilation train A was declared inoperable based on excessive belt noise and a dropped belt on MCC switchgear supply fan A. This also constitutes a loss of safety function. This event is being reported in accordance with 10 CFR 50.72(b)(2)(i) and 10 CFR 50.72(b)(3)(v)(D). The NRC Resident Inspector was notified.

  • * * UPDATE ON 10/04/17 AT 0926 EDT FROM DAN HARTIGAN TO STEVEN VITTO * * *

Due to the loss of both trains of MCC, Switchgear, and Miscellaneous Electrical Equipment Areas HVAC, actions were taken in LCO 3.8.7 for AC and DC Distribution Systems, LCO 3.8.4 for DC Sources, LCO 3.8.1 for AC Sources, and the associated support systems, the High Pressure Core Spray system was also declared inoperable, which is a single train safety system and therefore, an additional loss of safety function. This event is being reported in accordance with 10 CFR 50.72(b)(3)(v)(B), 10 CFR 50.72(b)(3)(v)(C) and 10 CFR 50.72 (b)(3)(v)(D). At 0620 hours (EDT) the A train of MCC, Switchgear, and Miscellaneous Electrical Equipment Areas HVAC and High Pressure Core Spray was declared operable and LCO 3.0.3 was exited. The plant was restored to 100% (percent) power at 0804 (EDT). The NRC Resident Inspector was notified. Notified R3DO(Hills).

ENS 5293629 August 2017 14:42:00Grand GulfNRC Region 4GE-6

On August 22, 2017 at 2321 hours, Grand Gulf Nuclear Station entered Technical Specification conditions for three Limiting Condition for Operations (LCOs) not met due to Residual Heat Removal 'A' (RHR 'A') being declared inoperable. LCOs not met:

  1) 3.5.1 for one low pressure ECCS (Emergency Core Cooling System) injection/spray subsystem.
  2) 3.6.1.7 for one RHR containment spray subsystem, and
  3) 3.6.2.3 for one RHR suppression pool cooling subsystem.

The station has made the decision to shutdown the plant based on the results of troubleshooting performed on the RHR 'A' pump. The restoration of RHR 'A' pump will not be completed prior to the end of the 7 day LCO completion time. Grand Gulf Nuclear Station initiated plant shutdown required by Technical Specifications 3.5.1, 3.6.1.7, and 3.6.2.3 at 1200 hours CDT on 08/29/2017 due to expected restoration of RHR 'A' exceeding the completion time of 7 days prior to restoring operability. The licensee notified the NRC Resident Inspector.

ENS 5292123 August 2017 10:51:00Grand GulfNRC Region 4GE-6

At approximately 0340 CDT on Wednesday, August 23, 2017, Grand Gulf Nuclear Station was notified by the Entergy System Dispatcher that the NRC had called them and told them that the NRC could not contact Grand Gulf on the Emergency Notification System (ENS) line nor commercial telephone. Control Room personnel immediately tested several offsite lines including the NRC ENS line and found the lines were non-functional. Offsite prompt Public Warning Sirens were available at all times. State and Local notification capability was available via UHF radio communication. GGN Emergency Response Organization notification capability was available at all times via satellite phone activation of group paging. GGN site Emergency Response Facility intercommunications were available at all times via site internal telephones. In-plant and offsite team communications were available at all times via UHF radio. This event is being reported (8-hour notification) as an event or condition that adversely impacted offsite communications in accordance with 10 CFR 50.72(b)(3)(xiii), specifically the loss of the NRC Emergency Notification System (ENS). The phone company has been contacted and actions are being taken to restore normal communications capability at this time. The NRC Resident Inspector has been notified.

  • * * UPDATE AT 1701 EDT ON 08/23/17 FROM LEROY PURDY TO JEFF HERRERA * * *

At 1701 EDT on 8/23/17 the phone systems at Grand Gulf have been restored. The licensee will be notifying the NRC Resident Inspector. Notified the R4DO (Farnholtz)

ENS 5291518 August 2017 23:41:00River BendNRC Region 4GE-6At 2055 CDT on August 18, 2017, an automatic actuation of the reactor protection system occurred while the plant was operating at 100 percent power. No plant parameters requiring the actuation of the emergency diesel generators or the emergency core cooling system were exceeded. The main feedwater system remained in service following the scram to maintain reactor water level, and the main condenser remained available as the normal heat sink. The scram occurred after a planned swap of the main feedwater master controller channels in preparation for scheduled surveillance testing. When the channel swap was actuated, the feedwater regulating valves moved to the fully open position. The scram signal originated in the high-flux detection function of the average power range monitors, apparently from the rapid increase in feedwater flow. The cause of the apparent feedwater controller malfunction is under investigation. The NRC Resident Inspector has been notified. No safety relief valves opened. Decay heat is being removed via steam to the main condenser using the bypass valves and steam drains. The licensee intends to go to Cold Shutdown to investigate the malfunction.
ENS 5290315 August 2017 04:58:00PerryNRC Region 3GE-6On August 14th, 2017 at 2257 (EDT), while shutting down the Annulus Exhaust Gas Treatment System (AEGTS) Train B, secondary containment pressure momentarily lowered. This resulted in the Technical Specification (TS) for Secondary Containment to not be met for 15 seconds. The minimum Secondary Containment vacuum observed during that time was 0.52 inch of vacuum water gauge. Secondary Containment pressure was returned to within the TS operability limit of 0.66 inch of vacuum water gauge (TS SR 3.6.4.1.1) by the AEGTS Train A that remained in operation. There were no radiological releases associated with this event. Declaring Secondary Containment inoperable is reportable under (10 CFR) 50.72(b)(3)(v)(C) & (D) for an event or condition that could have prevented the fulfillment of a safety function of a system that is needed to:(C) Control the release of radioactive material; or (D) Mitigate the consequences of an accident. The licensee has notified the NRC Resident Inspector.
ENS 5289710 August 2017 17:14:00River BendNRC Region 4GE-6A non licensed supervisor confirmed positive for alcohol during a fitness for duty test. The employee's access has been terminated. The NRC Resident Inspector has been notified.
ENS 528918 August 2017 20:22:00PerryNRC Region 3GE-6On August 8, 2017, at 1554 hours (EDT), during restoration from testing of the High Pressure Core Spray (HPCS) Suppression Pool Level High Instrumentation, unexpected as-left indications were found that impacted both of the required channels of instrumentation. Subsequent venting of the instrumentation lines was completed and both channels of instrumentation are reading consistent with previously taken as-found data. The instrumentation was declared OPERABLE at 1635. The initial cause of the unexpected as-left indications appears to be the introduction of air into the instrumentation lines during the calibration activities. This is considered a loss of safety function based on both of the HPCS Suppression Pool Level High Instrumentation channels being declared INOPERABLE and the loss of the automatic HPCS suction swap to the Suppression Pool on a high level. This event is being reported in accordance with 10 CFR 50.72(b)(3)(v)(D). The (NRC Resident Inspector) has been notified.
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 5284310 July 2017 05:42:00Grand GulfNRC Region 4GE-6At 2158 (CDT) a door to the Control Room Envelope was left unsecure. GGNS (Grand Gulf Nuclear Station) identified that a loss of Safety Function occurred due to a breach in the Control Room Envelope resulting in inoperability of both divisions of Standby Fresh Air and therefore could have prevented fulfillment of its safety function. The Control Room Envelope was inoperable for one minute. This event is being reported under 10CFR 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 mitigate the consequences of an accident. The licensee notified the NRC Resident Inspector.
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 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 527273 May 2017 12:59:00PerryNRC Region 3GE-6On April 30, 2017, at 1818 (EDT), the main turbine steam bypass valve #1 partially opened. Power was incrementally lowered. While lowering power the bypass valve would shut and then reopen and power would again be lowered. When power was lowered to approximately 74 percent the bypass valve remained closed. During the transient the reactor protection system (RPS) Turbine Stop Valve Closure and Control Valve Fast Closure trip functions were declared inoperable due to the opening of the bypass valve which affects the bypass setpoint for those RPS trip functions. With the loss of these RPS trip functions a loss of safety function existed intermittently for approximately 37 minutes. The manual reactor trip function and other RPS functions remained operable. Both channels of the rod withdrawal limiter (RWL) and the end of cycle reactor recirculation pump trip (EOC-RPT) function were also declared inoperable. These functions are credited in accident analysis, this also resulted in a loss of safety function. Currently the bypass valve is closed and the RWL, EOC-RPT and RPS function are operable. Troubleshooting continues to determine the issue with the main turbine that caused the bypass valve to open. NRC Resident Inspector has been notified.
ENS 5263123 March 2017 07:24:00River BendNRC Region 4GE-6

River Bend Station personnel declared the High Pressure Core Spray (HPCS) system inoperable at 0256 on 3/23/2017. During performance of the HPCS Pump and Valve Operability Test, the operators observed an unusual system response after E22-MOVF023 (HPCS Test Return to the Suppression Pool) was stroked closed. A field check showed that the key that connects the E22-MOVF023 valve stem to the anti-rotation device had become dislodged. E22-MOVF023 is a Primary Containment Isolation Valve (PCIV) and is designed to close automatically on an ECCS (Emergency Core Cooling System) initiation signal to ensure that injection flow is directed to the reactor vessel. Technical Specification (TS) 3.6.1.3 requires that containment penetrations associated with an inoperable PCIV be isolated. E22-MOVF023 was declared inoperable at 0028. Operators were unable to close or demonstrate that E22-MOVF023 was fully closed as required by TS 3.6.1.3 and proceeded to isolate the associated containment penetration by closing other system valves. This action was completed at 0320. The net effect of the actions taken to isolate the containment penetration is that HPCS is inoperable as of 0256. This results in 14 day LCO. The licensee has notified the NRC Resident Inspector.

  • * * UPDATE FROM DAN JAMES TO KARL DIEDERICH ON 3/23/17 AT 10:01 EDT * * *

The Event Time was 0028 CDT rather than 0256 CDT. "The scheduled surveillance test of the high pressure core spray system was initiated at 2355 CDT on March 22, and the pump was secured at 0028 CDT on March 23. The inspection of the HPCS test return valve to the suppression pool occurred at 0050 CDT, and it was at that point that an apparent malfunction of the valve had occurred to the extent that it did not appear to be able to perform its safety function to close upon receipt of a design basis system initiation signal. Thus, the event time for this condition would be more accurately defined as 0028 CDT. Notified R4DO (James Drake) via e-mail.

ENS 5260210 March 2017 11:41:00River BendNRC Region 4GE-6At 0714 CST on March 10, 2017, with the unit in Mode 1 at approximately 17% power, a manual actuation of the reactor protection system (RPS) was initiated due to rising reactor pressure caused by the closure of the Main Turbine Control Valves (MTCV's). The cause of the closure of the MTCV's is under investigation. The unit is currently stable in Mode 3. All control rods inserted as expected; water level control is stable in the normal control band and reactor pressure is being maintained with steam line drains (aligned to the main condenser). The NRC Senior Resident Inspector has been notified.
ENS 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 5256820 February 2017 17:24:00River BendNRC Region 4GE-6

During the investigation associated with Event Notification 52566 that was reported on 2/18/17, it has been determined that an unanalyzed condition (new potential single failure concerns) exists. This condition exists only during periods of manually alternating divisions of Control Building Chilled Water systems; in that potential failures of Control Room Air Handling Units (HVC-ACU1A or B) or Control Building Air Handling Units (HVC-ACU2A or B) could fail in a manner that challenges the operability of the alternate division.

As reported in Event Notification 52566, the impact of this event was a loss of safety function cooling to both Division 1 and 2 AC/DC power distribution systems and Divisions 1 and 2 Control Room Fresh Air systems. Contingency actions are in development to address the impact of the potential failure mode. The plant remains in a planned refueling outage, Mode 5 with water level greater than 23' above the vessel flange. Shutdown cooling remains in service and is not affected by this issue. Investigation is ongoing. The NRC Resident Inspector has been briefed on this issue.

  • * * UPDATE FROM ROB MELTON TO DONALD NORWOOD AT 2129 EST ON 2/20/2017 * * *

The licensee updated information in the first paragraph of the original above with the following: During the investigation associated with Event Notification 52566 that was reported on 2/18/17, it has been determined that an unanalyzed condition (new potential single failure concerns) exists. During periods of alternating divisions of Control Building Chilled Water systems, the potential exists for failures of Control Room Air Handling Units (HVC-ACU1A or B) or Control Building Air Handling Units (HVC-ACU2A or B) that could challenge the operability of the alternate division. The licensee notified the NRC Resident Inspector of this update. Notified R4DO (Gepford)

  • * * UPDATE FROM STEVEN CARTER TO MARK ABRAMOVITZ AT 1513 EDT ON 2/22/17 * * *

After further investigation it has been determined that an unanalyzed condition (new single failure concerns) exists with the dampers associated with the Control Room Fresh Air system. The potential exists for damper failures for HVC-FN1A Control Room Booster Fan 1A motor and HVC-FN1B Control Room Booster Fan 1B motor that could challenge the operability of the alternate division. Contingency actions are in development to address the impact of the potential failure mode. The plant remains in a planned refueling outage, Mode 5, with water level greater than 23 feet above the vessel flange. Shutdown cooling remains in service and is not affected by this issue. Investigation is ongoing. The NRC Resident Inspector has been briefed on this issue. Notified R4DO (Pick).

ENS 5256619 February 2017 00:21:00River BendNRC Region 4GE-6At 1537 CST on February 18th, 2017, while the plant was in MODE 5 for a scheduled refueling outage, the main control room experienced a loss of Control Building chilled water and the associated ventilation systems while attempting to alternate divisions for testing. An equipment malfunction in a breaker supplying a Main Control Room air handling unit caused a loss of both divisions of Control Room and Control Building chilled water systems and associated ventilation systems until 1737 CST. During the period between 1537 and 1737, neither division of Control Building chilled water was able to perform the support function for cooling Division 1 and 2 AC and DC power distribution systems or the support function for the Division 1 and 2 Control Room Fresh Air systems. Shutdown Cooling remained in service throughout this event. There were no apparent effects on any plant equipment from the loss of chill water and ventilation. The Division 1 Control Building chill water and ventilation system was returned to service at 1737 on February 18, 2017. Actions were initiated to terminate the OPDRV (operations with potential to drain the reactor vessel) that was in progress at the time of the event by installing the reactor recirculation pump seal. As a conservative measure, actions were initiated to set containment and containment was set at 2145. Troubleshooting and analysis is ongoing to confirm and correct the problem which caused the loss of the Control Building chill water and ventilation system. This condition is being reported in accordance with 10 CFR 50.72(b)(3)(v)(B). The NRC Senior Resident Inspector has been notified.
ENS 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 5251627 January 2017 23:05:00Grand GulfNRC Region 4GE-6This notification is to report a loss of safety function in accordance with 10 CFR 50.72(b)(3)(v)(D). At approximately 1808 CST hours on Friday, January 27, 2017, the Grand Gulf Nuclear Station Unit 1 High Pressure Core Spray (HPCS) system was declared inoperable due to the trip of the HPCS Jockey Pump. At the time of discovery, Unit 1 was in Mode 2 and raising power in the source range to return to power operations. No other safety systems were inoperable at the time of this event. Investigation into the cause of the event is ongoing and the system will be returned to operational status prior to proceeding to Mode 1. The licensee has notified 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 522258 September 2016 04:27:00Grand GulfNRC Region 4GE-6On September 4, 2016 at 0258 (CDT), Grand Gulf Nuclear Station entered three (Technical Specification) Limiting Conditions for Operations (LCOs) due to residual heat removal pump 'A' (RHR 'A') being declared inoperable. LCOs entered: 1) 3.5.1 for one low pressure ECCS injection/spray subsystem, 2) 3.6.1.7 for one RHR containment spray subsystem, and 3) 3.6.2.3 for one RHR suppression pool cooling subsystem. Station management has made the decision to shutdown the plant to repair the RHR 'A' pump prior to the end of the 7 day LCO completion time based on troubleshooting and testing performed on the RHR 'A' pump. Grand Gulf Nuclear Station initiated plant shutdown required by Tech Spec Actions 3.5.1, 3.6.1.7, and 3.6.2.3, at 0300 CDT on 09/08/2016 due to expected inability to restore RHR 'A' to operable status prior to exceeding the LCO time of 7 days. The unit is currently at 82 percent power. There are no other systems out of service that would complicate the orderly shutdown to Mode 4. The licensee will notify 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 5204425 June 2016 18:30:00Grand GulfNRC Region 4GE-6At 1407 (CDT), during power ascension to 100 percent, turbine control valves closed unexpectedly causing reactor protection trip signals that in turn caused a reactor scram. Reactor scram, turbine trip ONEPs (Off Normal Event Procedure), and EP2 (Emergency Procedure for Level Control) were entered. Reactor water level was stabilized at 36 inches narrow range on startup level and reactor pressure stabilized at 935 psig using bypass valves. No other safety system actuations occurred and all systems performed as designed. All control rods inserted. Reactor level is maintained by feedwater. Normal electrical shutdown configuration is through offsite electrical power sources. The Safety Relief Valves lifted, then closed. The plant is stable at normal level and pressure and remains in Mode 3. The event is under licensee investigation. The licensee notified 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 5192813 May 2016 20:02:00River BendNRC Region 4GE-6

At 1200 (CDT) May 13, 2016, while the plant was operating at 100% power, it was brought to the attention of the River Bend Station Main Control Room staff that an existing design inadequacy could prevent both trains of the Standby Gas Treatment System (GTS) from performing its design function. Under certain specific conditions, the installed Masterpact breakers may not close to allow energization of the filter train exhaust fans. A start signal (reactor level 2, drywell pressure 1.68 psid, annulus high radiation, annulus low flow) combined with a trip signal within a certain time differential, could result in a failure of the breakers to close. As a result of this condition, both Standby Gas Trains were declared inoperable, which required entry into LCO 3.6.4.3 Condition C (requires entering Mode 3 in 12 hours). Declaring both trains of Standby Gas Treatment System inoperable resulted in loss of the safety function since a system that has been declared inoperable is one in which the capability has degraded to the point where it cannot perform with reasonable expectation or reliability. The Standby Gas Treatment System (GTS) limits release to the environment of radioisotopes, which may leak from the primary containment, ECCS systems, and other potential radioactive sources to the secondary containment under accident conditions. At 1240 (CDT) May 13, 2016, one division of GTS, GTS 'A', was manually started from the Main Control Room. This action prevents the breaker failure mode, restored the operability of one train and restored the safety function of the GTS system. LCO 3.6.4.3 Condition A (restore Operability in 7 days) is currently entered for Standby Gas Train 'B'. During the 40 minutes of inoperability, both trains of Standby Gas remained available. At no time was the health or safety of the public impacted. This condition is being reported in accordance with 10CFR50.72(b)(3)(v)(C) as an event that could have caused a loss of safety function to control the release of radioactive material. The Senior NRC Resident was notified.

  • * * UPDATED AT 1341 EDT ON 05/17/16 FROM DAN PIPKIN TO RICHARD SMITH * * *

Further review has determined that the design inadequacy discussed in EN #51928 could adversely effect the ability of the main control building heating, ventilation, and air conditioning (HVAC) system to perform its design safety function, based upon a particular sequence of events occurring within a short window of time (approximately 75 milliseconds). River Bend has implemented compensatory actions to ensure operability of the main control building HVAC system. The Resident Inspector has been notified by the licensee. Notified the R4DO (Miller).

ENS 518993 May 2016 01:50:00River BendNRC Region 4GE-6

At 2229 (CDT) on 05-02-2016, River Bend Station declared the High Pressure Core Spray system INOPERABLE in accordance with Technical Specification 3.8.9, Condition E (Declare High Pressure Core Spray System and Standby Service Water System Pump 2C inoperable immediately) due to Division 1 Control Room Air Conditioning System HVK-CHL1C being INOPERABLE due to a trip of the chiller on high inboard bearing temperature. Actions taken to exit the LCO: Alternated divisions of Control Room Air Conditioning System to Division 2 HVK-CHL1D in service and Division 1 HVK-CHL1A in standby. The licensee notified the NRC Resident Inspector.

  • * * RETRACTION ON 6/22/16 AT 1137 EDT FROM JACK MCCOY TO DONG PARK * * *

Supplement: An operability evaluation has been performed based on system operating procedures in place at the time of this event, and on calculations regarding heat-up rates of the spaces served by the main control room air conditioning system. Operating procedures already in place on May 2 specified the operator actions required to restore the air conditioning system to service following the unanticipated trip of a chiller. The normal shift complement was on duty at the time of the event, and could have provided an adequate number of operators to accomplish this task. The operability evaluation made no new assumptions regarding availability of operators. The manual actions to be performed for the start of an alternate chiller following a trip of an in-service chiller system have been determined to require 2.15 hours, based on ANSI 58.8 guidance. (ANSI/ANS 58.8, Time Response Design Criteria for Nuclear Safety Related Operator Actions, provides the industry guidance In this regard.) Calculations of building heat-up rates have demonstrated that the loss of the air conditioning system can be sustained for 19 hours before temperatures in the rooms containing the Division 3 electrical equipment that support operability of the HPCS system exceed their maximum allowable ambient value. Based on the conclusions of the operability evaluation, the trip of the 'C' HVK chiller on May 2 had no actual adverse effect on the ability of the electrical distribution systems in the main control building to support the safety function of the HPCS system. Event Notification No. 51899 is hereby withdrawn. The licensee has notified the NRC Resident Inspector. Notified R4DO (Rollins).

ENS 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 517849 March 2016 16:53:00River BendNRC Region 4GE-6On January 10, 2016, at 0243 CST, with the plant in cold shutdown, the primary containment isolation logic was actuated as the result of an invalid signal. This condition occurred while operators were installing electrical jumpers designed to bypass certain isolation signals for the suction valves in the residual heat removal (RHR) system that comprise the shutdown cooling flow path. These jumpers are installed under procedural guidance for the purposes of increasing the reliability of the shutdown cooling loop by disabling isolation signals that are not required to be operable in certain plant operating modes. Although it could not be proven, it appears that inadvertent contact with an energized circuit occurred during the jumper installation, causing a fuse to blow, de-energizing part of the primary isolation logic. This caused the automatic closure of Division 1 suction and return valves in the shutdown cooling loop, as well as valves connecting the reactor plant sampling systems to the RHR system. The main control room crew implemented recovery procedures to restore shutdown cooling to service at 0401 CST, prior to exceeding any temperature limits. This event resulted from the failure to maintain corrective actions in place that were develop after a similar event in 1994. Additionally, the operators were not using the type of jumpers required by the procedure, which likely contributed to the blown fuse. The RHR system operating procedure has been revised to require that the potentially affected valves in the shutdown cooling loop will be de-energized during jumper installation to eliminate the possibility of inadvertent isolation. This is being reported in accordance with 10 CFR 50.73(a)(1) as an invalid actuation of the primary containment isolation logic. During this event, the RCS temperature increased from approximately 130 to 190 degree F. The licensee will notify the NRC Resident Inspector.
ENS 5176027 February 2016 09:20:00Grand GulfNRC Region 4GE-6A contract employee supervisor had a confirmed positive for alcohol during follow up FFD testing. The employee's access to all Entergy plants has been terminated. The licensee has notified the NRC Resident Inspector.
ENS 5175424 February 2016 18:16:00River BendNRC Region 4GE-6At 1100 CST on February 24, 2016, with the plant in cold shutdown (Mode 4), the shift manager was notified of a condition that could potentially prevent the automatic closure of the circuit breakers powering the emergency ventilation fans in the both the Division 1 and 2 emergency diesel generator rooms. These fans are not in Technical Specifications, however, they provide a support function to the emergency diesel generators, requiring that both diesel generators to be declared inoperable. This inoperability constitutes a condition that could potentially prevent fulfillment of the safety function of onsite AC power sources, and is being reported pursuant to 10 CFR 50.72(b)(3)(v). Four additional breakers are affected by the same condition. These breakers supply power to Division 1 and 2 containment unit coolers and the Division 1 and 2 auxiliary building 141 ft. elevation general area unit coolers. The auxiliary building unit coolers are not in Technical Specifications, however, they provide a support function to the electrical distribution system. The Technical Specification required action is to declare both trains of the residual heat removal system (shutdown cooling mode) inoperable. This inoperability constitutes a condition that could potentially prevent the fulfillment of the decay heat removal safety function, and is being reported pursuant to 10 CFR 50.72(b)(3)(v). Division 2 residual heat removal is operating in shutdown cooling, satisfactorily maintaining reactor coolant temperature. The affected breakers can be manually operated to start/stop their associated equipment, if necessary for operation. This condition was identified during an Engineering review. The licensee has compensatory measures in place. Long term corrective actions are under review. The licensee informed the NRC Resident Inspector.
ENS 5170129 January 2016 23:00:00River BendNRC Region 4GE-6On January 29, 2016, at 1518 CST, with the plant in cold shutdown, power was lost on reserve station service (RSS) line no. 1. This is one of two sources of offsite power required by Technical Specifications. The power loss de-energized the Division 1 onsite AC safety-related switchgear, causing an automatic start of the Division 1 emergency diesel generator (EDG). The Division 1 reactor protection system (RPS) bus was also de-energized, causing a half-scram signal. Approximately 8 minutes later, a full actuation of the RPS occurred due to a high water level condition in the control rod drive hydraulic system scram discharge volume header. All reactor control rods were already fully inserted. The loss of Division 1 RPS also caused the actuation of the Division 1 primary containment isolation logic. The Division 1 isolation valves in the balance-of-plant systems closed as designed. Both trains of the standby gas treatment system actuated. The loss of RSS no. 1 occurred during post-modification testing on relays at the local 230kV switchyard. The exact cause of the event is under investigation. This event is being reported in accordance with 10 CFR 50.72(b)(3)(iv)(A). The unit remains in cold shutdown with 1 source of offsite power and all 3 (EDG) available. The (NRC) Resident Inspector has been notified.