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	Discovered date	Reporting criterion	Title	Event description
ENS 57090	25 April 2024 03:15:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge	Automatic Reactor Scram with Eccs Actuation	The following information was provided by the licensee via email: On 4/24/2024 at 2215 CDT, Browns Ferry Unit 1 experienced an automatic reactor scram. The cause of the scram is currently under investigation. The main steam isolation valves (MSIVs) remain open with the main turbine bypass valves controlling reactor pressure. The reactor feedwater pumps are in service to control reactor water level. Primary containment isolation systems (PCIS) Groups 2, 3, 6, and 8 isolation signals were received. Upon receipt of these signals, all components actuated as required. Following the reactor scram, due to reactor water level reaching minus 45 inches, both high pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC) initiation signals were received, and both initiated as designed. All safety systems operated as expected. This event requires a 4-hour report per 10 CFR 50.72(b)(2)(iv)(A), `Any event that results or should have resulted in emergency core cooling system (ECCS) discharge into the reactor coolant system as a result of a valid signal except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation. This event requires a 4-hour report per 10 CFR 50.72(b)(2)(iv)(B), `Any event or condition that results in actuation of the reactor protection system (RPS) when the reactor is critical except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation. This event requires an 8-hour report per 10 CFR 50.72(b)(3)(iv)(A), `Any event or condition that results in valid actuation of any of the systems listed in paragraph (b)(3)(iv)(B): 1) Reactor protection system (RPS) including: reactor scram or reactor trip. 2) General containment isolation signals affecting containment isolation valves in more than one system or multiple main steam isolation valves (MSIVs). 4) ECCS for boiling water reactors (BWRs) - high-pressure coolant injection (HPCI). 5) BWR reactor core isolation cooling system (RCIC). All safety systems operated as expected. At no time was public health and safety at risk. The NRC resident inspector has been notified. The following additional information was obtained from the licensee in accordance with Headquarters Operations Officers Report Guidance: Units 2 and 3 were not affected.
ENS 57021	11 March 2024 17:37:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge	Manual Reactor Trip	The following information was provided by the licensee via phone and email: On March 11, 2024, at 1337 EDT, with Unit 1 in Mode 1 at 35 percent power performing power ascension activities, the reactor was manually tripped due to the 'A' reactor feed pump (RFP) tripping on low suction pressure. Due to the power level at the time, the 'B' RFP had not been placed in service. Closure of containment isolation valves (CIVs) in multiple systems and actuation of high-pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC) occurred as a result of reaching the actuation setpoint on reactor water level as designed. The trip was not complex, with all safety systems responding normally post-trip. Operations responded and stabilized the plant. The 'B' RFP was placed in service and is controlling reactor water level. Decay heat is being removed by discharging steam to the main condenser using turbine bypass valves. Unit 2 is not affected. Due to the emergency core cooling system (ECCS) discharging into the reactor, this event is being reported as a four-hour, non-emergency notification per 10 CFR 50.72(b)(2)(iv)(A). Also, the Reactor Protection System actuation while critical is being reported as a four-hour, non-emergency notification per 10 CFR 50.72(b)(2)(iv)(B). Additionally, it is reportable under 10 CFR 50.72(b)(3)(iv)(A) as an event that results in a valid actuation of CIVs, RCIC and HPCI. There was no impact on the health and safety of the public or plant personnel. The NRC resident inspector has been notified. The following additional information was obtained from the licensee in accordance with Headquarters Operations Officers Report Guidance: The cause of the 'A' RFP is under investigation. The reactor electric plant remains in a normal lineup with both emergency diesel generators available. There were no temperature or pressure technical specification limits approached.
ENS 56989	22 February 2024 17:03:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Accident Mitigation - High Pressure Coolant Iinjection Declared Inoperable	The following information was provided by the licensee via email: At 1103 CST on February 22, 2024, a potential through-wall steam leak was identified on the high pressure coolant injection (HPCI) steam supply 1-inch drain line. As a result, HPCI was declared inoperable. Since HPCI is a single-train system, this is a condition that could have prevented the fulfillment of a safety function; therefore, this condition is being reported as an eight-hour, non-emergency notification per 10 CFR 50.72(b)(3)(v)(D). Reactor core isolation cooling (RCIC) and low pressure emergency core cooling systems (ECCS) remain operable. Additional investigation is in progress. There was no impact on the health and safety of the public or plant personnel. The NRC Resident Inspector has been notified.
ENS 56974	17 February 2024 13:37:00	10 CFR 50.72(b)(3)(ii)(A), Seriously Degraded	Primary Containment Degraded	The following information was provided by the licensee via email and phone call: At 0837 EST, on 02/17/2024, during a refueling outage at 0 percent power while performing local leak rate testing (LLRT) on the reactor core isolation cooling (RCIC) isolation valves, which is part of the containment boundary, it was determined that the Unit 1 primary containment leakage rate did not meet 10 CFR 50 Appendix J requirements specified in Technical Specification 5.5.12. This event is being reported as an eight-hour, non-emergency notification per 10 CFR 50.72(b)(3)(ii)(A). There was no impact on the health and safety of the public or plant personnel. The NRC Resident Inspector has been notified.
ENS 56936	29 January 2024 17:02:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Automatic Reactor Scram	The following information was provided by the licensee via email: At approximately 1202 EST on 01/29/24, unit 2 experienced a reactor scram caused by a main turbine trip. Investigation is still ongoing. The following additional information was obtained from the licensee in accordance with Headquarters Operations Officers Report Guidance: All control rods were fully inserted. The licensee indicated that the turbine trip may have been caused by a power load imbalance, however the cause of the incident is under investigation. The scram was not complex. Decay heat is currently being removed thru bypass valves dumping to the main condenser. Initially unit 2 lost the use of the bypass valves due to lack of condenser vacuum. Unit 2 used the high pressure coolant injection (HPCI) system in the condenser storage tank (CST) to CST mode to remove decay heat. Residual heat removal was used to keep the torus cool. Condenser vacuum was regained and unit 2 is back to removing decay heat with the turbine bypass valves. There was no impact to unit 3. The licensee confirmed there was no impact on the health and safety of the public or plant personnel. The NRC Resident Inspector has been notified. * UPDATE ON 01/29/24 AT 1935 EST FROM PAUL BOKUS TO NATALIE STARFISH * * The following information was provided by the licensee via email: Licensee adds 8-hour non-emergency 10 CFR 50.72(b)(3)(iv)(A) specified system actuation report to original 4-hour non-emergency 10 CFR 50.72(b)(2)(iv)(B) RPS Actuation report. At approximately 1202 EST on 01/29/24, unit 2 experienced a reactor scram by a main turbine trip. All control rods inserted. Reactor core isolation cooling system (RCIC) was manually initiated for level control. HPCI was manually initiated for pressure control. Primary containment isolation system (PCIS) Group II and III isolations occurred (specified system actuation). Investigation is ongoing. The NRC Resident Inspector has been notified.
ENS 56897	2 November 2023 01:11:00	10 CFR 50.73(a)(1), Submit an LER	60 Day Notification for an Invalid Specified System Actuation	The following information was provided by the licensee via email and phone: At 2011 EDT on 11/01/23, with Unit 2 in Mode 3 at 0 percent power, Unit 2 received multiple spurious actuations. These actuations consisted of a partial group 1 and a partial group 5 primary containment isolation and a partial secondary containment isolation. The partial Group 1 isolation resulted in the closure of two main steam isolation valves (MSIVs); all other MSIVs were already closed. The partial group 5 isolation auto closed one of the reactor water cleanup (RWCU) isolation valves. The partial secondary containment isolation resulted in the closure of the inboard refueling floor and reactor building secondary containment isolation valves (SCIVs). Additionally, at 2238 EDT, Unit 2 again received multiple spurious actuations. These actuations consisted of a partial group 5 primary containment isolation and a partial secondary containment isolation. The partial group 5 isolation auto closed one of the RWCU isolation valves The partial secondary containment isolation resulted in the closure of the inboard refueling floor and reactor building SCIVs. And again, at 2354 EDT, Unit 2 received spurious actuations which consisted of a partial secondary containment isolation which resulted in the closure of the inboard refueling floor and reactor building SCIVs. The spurious actuations seen on 11/1/23 are triggered at -35 inches reactor water level (RWL) for group 5 and secondary containment isolations and at -101 inches RWL for group 1 isolations. It was determined that a combination of the RWL fluctuating above and below the wide range instrument reference leg tap, the reactor vessel pressure being lowered, and reactor core isolation cooling introducing colder water conditions near the reference leg tap of the wide range instrument caused the spurious actuations. Using multiple RWL indications for each of the instances mentioned above, the actuations were confirmed to be spurious as RWL was being controlled in a band of +55 inches to +85 inches at the time of the actuations. This event is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) as an event that resulted in an invalid actuation of a partial group 1, a partial group 5, and partial secondary containment logic. The NRC Resident has been notified.
ENS 56896	18 December 2023 07:23:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Coolant Injection System Inoperable	The following information was provided by the licensee email: At 0223 EST, on 12/18/2023, while Unit 2 was at 100 percent power in mode 1, the high pressure coolant injection (HPCI) outboard steam isolation valve closed resulting in the HPCI system being declared inoperable. The cause of the outboard steam isolation valve closing is under investigation. HPCI does not have a redundant system, therefore, this condition is being reported as an eight-hour, non-emergency notification per 10 CFR 50.72(b)(3)(v)(D). The safety function was restored at 0512, on 12/18/23, and HPCI has been declared operable. Reactor core isolation cooling (RCIC) and low pressure emergency core cooling systems (ECCS) were operable during this time. There was no impact on the health and safety of the public or plant personnel. The NRC Resident Inspector has been notified.
ENS 56887	13 December 2023 07:02:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Automatic Reactor Scram	The following information was provided by the licensee via phone and email: At 0102 CST, while operating at 100 percent (reactor) power, River Bend Station experienced an automatic reactor scram caused by a turbine trip signal. The cause of the turbine trip signal is not known at this time and is being investigated. At 0108, reactor core isolation cooling (RCIC) was initiated due to a loss of reactor feed pumps following feedwater heater string isolation. At 0114, reactor water level control was transferred back to feedwater and RCIC was secured. Reactor water level is being maintained by feedwater pumps and reactor pressure is being maintained by turbine bypass valves. The scram was uncomplicated and all other plant systems responded as designed. This event is being reported under 10 CFR 50.72(b)(2)(iv)(B), as any event or condition that results in actuation of the reactor protection system (RPS) when the reactor is critical and 10 CFR 50.72(b)(3)(iv)(A) specified system actuation as result of expected post scram (reactor water) level 3 isolations and manual initiation of RCIC. No radiological releases have occurred due to this event from the unit. The NRC Senior Resident Inspector has been notified of this event. The following additional information was obtained from the licensee in accordance with Headquarters Operations Officers Report Guidance: The cause of the turbine trip, while still under investigation, was likely due to an electrical transient involving the main generator. Walkdowns in the switchyard post-scram identified damage to one of the output breaker disconnects.
ENS 56826	1 November 2023 10:48:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge	Manual Reactor Trip Due to Trip of Reactor Feed Pump	The following information was provided by the licensee via email: At 0648 EDT on 11/1/23, with Unit 2 in MODE 1 at 56 percent power, the reactor was manually tripped due to a trip of the 'B' reactor feed pump (RFP). The 'A' RFP had been previously isolated due to a leak. Closure of containment isolation valves (CIVs) in multiple systems and the actuation of high pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC) occurred as a result of reaching the actuation setpoint on reactor water level as designed. The trip was not complex, with all safety systems responding normally post-trip. Operations responded and stabilized the plant. Reactor water level is being maintained with RCIC. Decay heat is being removed by discharging steam to the main condenser using the turbine bypass valves. Unit 1 was not affected. Due to the emergency core cooling system (ECCS) discharging into the reactor this event is being reported as a four-hour, non-emergency notification per 10 CFR 50.72(b)(2)(iv)(A). Also, the reactor protection system actuation while critical is being reported as a four-hour, non-emergency notification per 10 CFR 50.72(b)(2)(iv)(B). Additionally, it is reportable under 10 CFR 50.72(b)(3)(iv)(A) as an event that results in a valid actuation of CIVs, RCIC and HPCI. There was no impact on the health and safety of the public or plant personnel. The Resident Inspector was notified.
ENS 56710	2 September 2023 10:32:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge	Automatic Reactor Scram Due to Feedwater Transient	The following information was provided by the licensee via email: On 9/2/2023 at 0632 EDT, a feedwater transient occurred resulting in an reactor protection system (RPS) automatic reactor scram on low level (Level 3, 159.3 inches). Following the scram, reactor water level dropped below Level 2 (108.8 inches) resulting in a Group 2 recirculation sample system isolation, Group 3 traveling in-core probe (TIP) isolation valve isolation, Group 6 and 7 reactor water cleanup isolation, and Group 9 containment purge isolations. All control rods inserted as expected. High pressure core spray and reactor core isolation cooling initiated and injected as expected. ECCS systems have been secured and normal reactor pressure and level control has been established for hot shutdown. Nine Mile Point Unit 2 is stable and in Mode 3. These 4 hour and 8 hour non-emergency reports are being made in accordance with 10 CFR 50.72(b)(2) (iv)(A), 10 CFR 50.72(b)(2)(iv)(B), and 10 CFR 50.72(b)(3)(iv)(A). The NRC Resident was informed. There was no impact on Unit 1.
ENS 56673	10 August 2023 04:39:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge	Automatic Reactor Trip	The following information was provided by the licensee via email: At 0039 (EDT) on 8/10/23, with Unit 1 in Mode 1 at 100 percent power, the reactor automatically tripped during a reactor protection system (RPS) bus shift. All systems responding normally post-trip. There was no equipment inoperable at the time of the trip. Operations responded and stabilized the plant. Reactor water level being maintained via feedwater. Decay heat is being removed by cycling safety relief valves. An actuation of high-pressure core spray, division 3 diesel generator, and reactor core isolation cooling occurred during the scram and main steam line isolation closure. The reason for the auto-start was reaching Level 2 (130 inches in the reactor pressure vessel) during the transient. The systems automatically started as designed and injected to the reactor vessel when the Level 2 signal was received. The RPS actuation is being reported as a four-hour, non-emergency notification per 10 CFR 50.72(b)(2)(iv)(B). The emergency core cooling system (ECCS) injection is being reported as a four-hour, non-emergency notification per 10 CFR 50.72(b)(3)(iv)(A). The ECCS actuation is being reported as a eight-hour, non-emergency notification per 10 CFR 50.72(b)(2)(iv)(A). There was no impact on the health and safety of the public or plant personnel. The NRC Resident Inspector has been notified.
ENS 56321	24 January 2023 07:21:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Coolant Injection Inoperable	The following information was provided by the licensee via email: At 0121 CST on 01/24/2023, it was discovered that the Unit 1 High Pressure Coolant Injection System (HPCI) was inoperable; therefore, the condition is being reported as an eight-hour, non-emergency notification per 10 CFR 50.72(b)(3)(v), as an 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. 1-FCV-073-0006B, HPCI Steam Line Condensate Outboard Drain Valve, failed closed during normal plant configuration. This valve is normally open. The HPCI steam line is not being drained with the valve in the current position. The Unit 1 Nuclear Unit Senior Operator entered Unit 1 Technical Specifications LCO 3.5.1 Condition C with required actions C.1 to immediately verify by administrative means that the Reactor Core Isolation Cooling (RCIC) system is operable and C.2 to restore HPCI to operable status in 14 days. RCIC has been verified operable by administrative means. There was no impact to the safety of the public or plant personnel. The NRC Resident Inspector has been notified.
ENS 56116	19 September 2022 06:32:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Safety System Inoperability	The following information was provided by the licensee via email: At 0132 CDT on September 19, 2022, River Bend Station (RBS) was operating at 100% power when the high pressure core spray (HPCS) system was declared inoperable in accordance with technical specification 3.8.9, condition E (declare HPCS and standby service water system pump 2C inoperable immediately) due to a E22-S003, HPCS transformer feeder malfunction. The HPCS is a single train system at RBS, therefore this event is being reported in accordance with 10 CFR 50.72(b)(3)(v)(D) as an event or condition that could have prevented the fulfilment of a safety function. The reactor core isolation cooling system has been verified to be operable. The NRC Resident Inspector has been notified. The following additional information was obtained from the licensee in accordance with Headquarters Operations Officers Report Guidance: RBS has entered a 14-day limiting condition for operation due to the loss of HPCS and they have upgraded their on-line plant risk model to "yellow".
ENS 56054	18 August 2022 01:08:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Safety System Inoperability	The following information was provided by the licensee via email: At 2108 EDT on August 17, 2022 the Division 2 Mechanical Draft Cooling Tower (MDCT) fans were declared inoperable due to failure of the over speed fan brake inverter. The brakes prevent fan over speed from a design basis tornado. The MDCT fans are required to support operability of the Ultimate Heat Sink (UHS). The UHS is required to support operability of the Division 2 Emergency Equipment Cooling Water (EECW) system. The Division 2 EECW system cools various safety related components, including the High Pressure Coolant Injection (HPCI) room cooler and Division 2 Control Center HVAC (CCHVAC) chiller. An unplanned HPCI inoperability occurred based on a loss of the HPCI Room Cooler. At the time of the event, Division I CCHVAC was inoperable for maintenance (but was running for a maintenance run) and the event caused an inoperability of Division 2 CCHVAC. This resulted in an inoperability of both divisions of CCHVAC. Failure of the Division 2 MDCT Fan brake inverter occurred due to a trip of the DC input breaker. The breaker was reset at 2128 EDT restoring Division 2 UHS Operability. This report is being made pursuant to 10CFR50.72(b)(3)(v)(D) as a condition that at the time of discovery could have prevented the fulfilment of the safety function of structures or systems that are needed to mitigate the consequences of an accident based on a loss of a single train safety system and loss of both divisions of a safety system. The Senior NRC Resident Inspector has been notified * * RETRACTION ON 09/08/2022 AT 0856 EDT FROM JEFF MYERS TO MIKE STAFFORD * * * The following information was provided by the licensee via email: On 8/17/22 at 2108 EDT the Division 2 (Div. 2) mechanical draft cooling tower (MDCT) brake inverter input breaker tripped for an unknown cause. The result of the loss of power was the inoperability of the MDCT fan brakes which impacts the ultimate heat sink (UHS) (TS 3.7.2). The UHS cascades to the EECW (emergency equipment cooling water) (TS 3.7.2) which is a support system for Div. 2 CCHVAC (Control Cell) Chiller A/C system (TS 3.7.4). This resulted in the inoperability of the Div. 2 CCHVAC Chiller. The cause for the breaker to trip is an intermittent electrical transient. Immediate corrective action was to reset the breaker, and the long-term action is to implement a modification to mitigate susceptibility to voltage variations. Div. 1 has implemented this long-term mod and no unexpected trips have occurred to date. Div. 1 CCHVAC Chiller was previously inoperable from equipment issues which was repaired, and the unit was in service for a 24-hour confidence run. Although licensed personnel had not completed the administrative actions for documenting operability during the 24-hour confidence run to monitor parameters, the (post maintenance test) PMT related to the maintenance was already completed, which included a 4-hour run in accordance with surveillance 24.413.01, Div. 1 and Div. 2 Chilled Water Pump and Valve, to verify normal operation and motor current. These PMT's were completed prior to the identified inoperability of the Div. 2 UHS due to the tripped breaker on the brake power supply. At the time of the MDCT brake inverter trip, the Operations' Senior License and the Night Shift Manager were aligned that, although still operating as part of the 24-hour confidence run, the unit was in service and capable of performing its safety function, but the administrative tasks were not completed, the Limited Condition of Operation (LCO) sheet had not been cleared, and no log entries were made. Since the Div. 1 Chiller was, in fact, operable at the time of the trip of the breaker on the inverter, this would allow the use of Technical Specification (TS) 3.0.9 'Barriers'. Per Operations Department Expectation (ODE)-12 `LCOs' (standard guidance and expectations for preparing and implementing an LCO), Operations determined that the MDCT brakes are barriers to a tornado event and TS 3.0.9 could be utilized. By invoking TS 3.0.9, as long as all other supported systems in the other division are operable, Div. 2 supported systems relying upon the UHS can remain operable and the Automatic Depressurization System (ADS) and Reactor Core Isolation Cooling (RCIC) system can be used as backup to the High Pressure Coolant Injection (HPCI) system. Based on this information, there was no loss of safety function with CCHVAC A/C system or HPCI. Therefore, the NRC non-emergency 10CFR50.72(b)(3)(v)(D) report was not required and the NRC report 56054 can be retracted. The NRC Resident Inspector has been notified. Notified R3DO (Orlikowski)
ENS 55997	16 July 2022 00:20:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Coolant Injection (HPCI) Inoperable	The following information was provided by the licensee via email: At 2020 Eastern Daylight Time (EDT) on July 15, 2022, the HPCI System was declared inoperable. Therefore, this condition is being reported as an eight-hour, non-emergency notification per 10 CFR 50.72(b)(3)(v)(D). The Reactor Core Isolation Cooling (RCIC) System and Automatic Depressurization System (ADS) were operable during this time. HPCI availability was restored at 2023. Additional investigation is in-progress. There was no impact on the health and safety of the public or plant personnel. Unit 2 is not affected by this event. The NRC Resident Inspector has been notified. The following additional information was obtained from the licensee in accordance with Headquarters Operations Officers Report Guidance: HPCI is considered inoperable but available at this time, resulting in a 14-day Shutdown LCO (Limiting Condition for Operation), due to the HPCI inoperability.
ENS 55992	12 July 2022 14:17:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Coolant Injection Inoperable	The following information was provided by the licensee via fax or email: At 0917 CDT on 7/12/2022, during the performance of U1 (Unit 1) High Pressure Coolant Injection (HPCI) rated flow test, the 1-FCV-73-19 (HPCI governor valve) failed to operate as expected. This condition results in U1 HPCI being inoperable; therefore, this condition is being reported as an eight-hour, non-emergency notification per 10 CFR 50.72(b)(3)(v). The Automatic Depressurization System (ADS) and Reactor Core Isolation Cooling (RCIC) system remain operable. There was no impact on the health and safety of the public or plant personnel. The NRC Resident Inspector has been notified. U1 entered TS LCO 3.5.1 Condition C, 14-day Shutdown LCO (Limiting Condition for Operation), due to the HPCI inoperability.
ENS 55859	7 March 2022 04:40:00	10 CFR 50.73(a)(1), Submit an LER	Invalid Actuation 60-DAY Telephone Notification	The following information was provided by the licensee via fax or email: This 60-day telephone notification is being made in lieu of an LER submittal per 10 CFR 50.73(a)(1). This notification is made pursuant to the reporting requirements specified in 10 CFR 50.73(a)(2)(iv)(A) for invalid actuations of systems listed in 10 CFR 50.73(a)(2)(iv)(B). At approximately 0040 Eastern Standard Time (EST) on March 7, 2022, Unit 1 received inadvertent High-Pressure Coolant Injection (HPCI) and Reactor Core Isolation Cooling (RCIC) initiation signals. Subsequently, at approximately 0148 EST on March 7, 2022, Unit 1 received inadvertent Low-Pressure Coolant Injection (LPCI) and Core Spray initiation signals. In addition, all four Emergency Diesel Generators auto started, Group 10 (Instrument Air) Primary Containment Isolation System actuations occurred, and the Residual Heat Removal (RHR) Service Water Booster pumps tripped resulting in a brief interruption (approximately 9 minutes) to the Shutdown Cooling (SDC) heatsink. Jumpers, installed per planned refueling outage activities, prevented discharge of Emergency Core Cooling Systems into the reactor. HPCI, RCIC, and RHR Loop `A' were removed from service and under clearance. RHR SDC remained operable via RHR Loop `B' and forced circulation was maintained in the reactor. At the time of these events, Unit 1 was shutdown for refueling and the `A' and `C' reactor water level transmitters had been isolated in preparation for planned replacement. Leak-by of the instrument isolation valves occurred on both transmitters. Leak-by on the `C' instrument occurred at a faster rate with the `A' instrument providing the confirmatory signals resulting in Low Level 2 (LL2) and Low Level 3 (LL3) indication at approximately 0040 EST and 0148 EST, respectively. All actuations occurred as designed for LL2 and LL3 signals. During these events, reactor water level remained stable at the Reactor Vessel Head Flange and the `B' and `D' reactor water level transmitters remained off-scale-high, as expected under these conditions. Therefore, the actuations were not initiated in response to actual plant conditions, it was not an intentional manual initiation, and there were no parameters satisfying the requirements for initiation of the system (i.e., there was no low reactor water level condition). Considering the above, these actuations were invalid. There was no impact on the health and safety of the public or plant personnel.
ENS 55821	5 April 2022 06:23:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge	Scram on LOW Level	The following information was provided by the licensee via telephone and email: On 4/5/2022, at time 0223, during maintenance on Feedwater Level Control Valve 2FWS-LV10B, a Feedwater transient occurred resulting in an RPS Automatic Reactor Scram on Low Level (Level 3, 159.3 inches). Following the scram, reactor water level dropped below Level 2 (108.8 inches) resulting in a Group 2 Recirculation Sample System Isolation, Group 3 TIP ((Traversing Incore Probe)) Isolation Valve Isolation, Group 6 and 7 Reactor Water Cleanup Isolation and Group 9 Containment Purge Isolations. All control rods inserted as expected. High Pressure Core Spray and Reactor Core Isolation Cooling initiated and injected as expected. ECCS Systems have been secured and normal reactor pressure and level control has been established for hot shutdown. Nine Mile Point Unit 2 is stable in Mode 3. These 4 hour and 8-hour non-emergency ENS ((Emergency Notification System)) reports are being made in accordance with 10 CFR 50.72(b)(2)(iv)(A), 10 CFR 50.72(b)(2)(iv)(B), and 10 CFR 50.72(b)(3)(iv)(A). The NRC Resident was informed. The following additional information was obtained from the licensee in accordance with Headquarters Operations Officers Report Guidance: There was no impact on Unit 1.
ENS 55780	10 March 2022 01:13:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Coolant Injection (HPCI) Inoperable	The following information was provided by the licensee: At 2013 EST on March 9, 2022, the HPCI System was declared inoperable following evaluation of routine HPCI surveillance testing data indicating that the required response time for reaching rated conditions was not met. Therefore, this condition is being reported as an eight-hour, non-emergency notification per 10 CFR 50.72(b)(3)(v)(D). The Reactor Core Isolation Cooling (RCIC) System and Automatic Depressurization System (ADS) are operable. There was no impact on the health and safety of the public or plant personnel. Investigation is in-progress to determine the cause. Unit 1 is not affected by this event. Unit 1 is in a refueling outage. The NRC Resident Inspector has been notified. * * RETRACTION ON 05/04/22 AT 1135 EDT FROM CHARLIE BROOKSHIRE TO DAN LIVERMORE * * * The following information was provided by the licensee via email: At 20:13 EST on March 9, 2022, the HPCI System was declared inoperable following evaluation of routine HPCI surveillance testing data indicating that the required response time for reaching rated flow and pressure was not met. Subsequent to this, it was determined that the required response time was overly conservative for assuring the safety function of the system could be fulfilled. The required response time was revised. The operability determination for this event has been updated indicating that system operability was never lost for this event. There was not a condition that could have prevented the system from fulfilling the safety function. The NRC Resident Inspector has been notified. Notified R2DO (Miller).
ENS 55682	1 January 2022 17:10:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Core Spray System Declared Inoperable	The Licensee provided the following information via fax: During performance of a surveillance of the High Pressure Core Spray (HPCS) service water system on January 1, 2022, the HPCS system was declared inoperable for performance of the surveillance. During the surveillance, pump discharge pressure and flow were above the action range curve specified in the surveillance. For the given flow rate, pump discharge pressure was too high. This condition prevents declaring the HPCS service water system and HPCS system operable. The HPCS service water and HPCS systems remain inoperable. The station entered Technical Specification (TS) 3.7.2.A and TS 3.5.1.B at 0910 (PST) on January 1, 2022. In accordance with TS 3.5.1.B, the Reactor Core Isolation Cooling (RCIC) system was verified to be operable. TS 3.5.1 Action B provides a 14-day completion time to restore HPCS to an operable status. All other Emergency Core Cooling systems (ECCS) are operable. This event is being reported as an event or condition that could have prevented the fulfillment of a safety function credited for mitigating the consequences of an accident per 10 CFR 50.72(b)(3)(v)(D). The HPCS system is a single train system at Columbia. The NRC resident has been notified. The following additional information was obtained from the licensee in accordance with Headquarters Operations Officers Report Guidance: The licensee is investigating the cause of the high pump discharge pressure and verifying instrumentation accuracy. * * RETRACTION ON 1/6/22 AT 1715 EST FROM CHASE WILLIAMS TO TOM KENDZIA * * * This Notification is to retract EN 55682, Unplanned High Pressure Core Spray (HPCS) Inoperability. On 1/1/2022 at (1735 EST), Columbia Generating Station notified the NRC under 10 CPR 50.72(b)(3)(v)(D) of the inoperability of a single train of safety system (HPCS) for performance of the surveillance. During the surveillance pump discharge pressure and flow were above the action range curve specified in the surveillance. Engineering performed an analysis of this event and concluded the HPCS was operable during the event and would have performed its required safety function. The results of initial IST testing of HPCS-P-2 via OSP-SW/IST-Q703 on 01/01/22 resulted in measured parameters falling outside of the acceptable range specified for this pump. Systematic error was suspected as the cause of the failure and the test was reperformed following taking actions to eliminate the suspected systematic errors. The second performance of the test on 01/01/22 resulted in acceptable pump performance. Evidence exists that the initial performance of the test failed due to imprecise averaging techniques due to difficulties in averaging continuously changing values on the test instrument. The second performance of OSP-SW/IST-Q703 should be considered a successful test and the test of record as the systematic error was eliminated and measured parameters are considered valid. The NRC Resident Inspector has been notified. The HOO notified R4DO (Rolando-Otero).
ENS 55558	3 June 2021 06:41:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Coolant Injection Inoperable Due to LOW Level Instrumentation	At 0241 (EDT) on June 3, 2021, during performance of a High Pressure Coolant Injection (HPCI) Condensate Storage Tank (CST) level functional surveillance, the HPCI torus suction inboard isolation valve was slow to open during swap of suction from the CST to the Torus. On June 9, 2021, it was determined that as a result of the June 3, 2021, slow swap condition, TS 3.3.5.1 Required Action D.1 to declare HPCI inoperable within 1 hour was applicable due to inoperable CST low level instrumentation channels. At 1817 (EDT) on June 3, 2021, HPCI suction was swapped to the torus, making TS Required Action D.1 no longer applicable. Reactor Core Isolation Cooling (RCIC) was available throughout this condition. At 0900 (EDT) on November 3, 2021, it was determined that an NRC event report due to HPCI inoperability should have been made. This event is being reported as a late 8-hour non-emergency notification pursuant to 10CFR50.72(b)(3)(v)(D) based on an unplanned HPCI inoperability. The cause of the slow valve opening was later determined to be corrosion products on contacts of a relay in the CST low level instrumentation logic. On June 4, 2021 at 1451 (EDT), the HPCI CST Level Functional Test was completed Satisfactorily, restoring HPCI Instrumentation to Operable. There was no impact on the health and safety of the public or plant personnel. The NRC Resident Inspector has been notified.
ENS 55451	9 September 2021 05:33:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Core Spray Inoperable	At 0033 CDT on September 9, 2021, Grand Gulf Nuclear Station (GGNS) was operating at 70 percent power when the High Pressure Core Spray (HPCS) was declared inoperable. The inoperability determination was made due to control room annunciations. In accordance with GGNS Technical Specification 3.5.1.B.1, the Reactor Core Isolation Cooling system was verified to be operable. Troubleshooting is in progress. This event is being reported in accordance with 10 CFR 50.72(b)(3)(v)(D) as an event or condition which could have prevented the fulfillment of a safety function. The NRC Resident Inspector has been notified.
ENS 55448	8 September 2021 05:59:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Unit 1 High Pressure Coolant Injection (HPCI) System Inoperable	At 0159 EDT on 09/08/2021, the HPCI pump discharge valve failed to reopen during a valve surveillance, resulting in the HPCI system being declared INOPERABLE. HPCI does not have a redundant system; therefore, this condition is being reported as an eight-hour, non-emergency notification per 10 CFR 50.72(b)(3)(v). Reactor Core Isolation Cooling system and low pressure Emergency Core Cooling Systems were OPERABLE during this time. There was no impact on the health and safety of the public or plant personnel. The NRC Resident Inspector has been notified.
ENS 55423	22 August 2021 09:29:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	HPCI Declared Inoperable	At 0529 EDT on August 22, 2021, HPCI ((High Pressure Coolant Injection System)) was declared inoperable due to receiving the HPCI Inverter Circuit Failure annunciator. The cause of the annunciator was a fuse failure. The cause of the fuse failure is unknown at this time and is under investigation. Concurrent with the HPCI fuse failure was a similar fuse failure within the Division 2 EDG ((emergency diesel generators)) Load Sequencer which renders the Division 2 EDGs inoperable. Relation to the HPCI issue is unknown and is part of the investigation. The RCIC ((Reactor Core Isolation Cooling System)) was verified operable per Tech Spec 3.5.1 E.1. In addition, offsite circuits were verified operable per Tech Spec 3.8.1.B. Division 1 EDGs remain operable. This report is being made pursuant to 10CFR50.72(b)(3)(v)(D) based on an unplanned HPCI inoperability. There was no impact on the health and safety of the public or plant personnel. The Senior NRC Resident Inspector has been notified.
ENS 55394	3 August 2021 14:26:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Automatic Reactor Trip	At 1026 EDT on 8/3/21, with Unit 1 in MODE 1 at 100 percent power, the reactor automatically tripped due to low reactor water level. The low reactor water level condition was due to a loss of both reactor feed pumps. The cause of the loss of feed pumps is under investigation. Additionally, the low reactor water level resulted in the automatic actuation of High Pressure Coolant Injection (HPCI) and Reactor Core Isolation Cooling (RCIC) systems, and Containment Isolation Valves (CIVs) in multiple systems. All safety systems responded normally. Operations responded and stabilized the plant. Reactor water level is being maintained via RCIC system. Decay heat is being removed by discharging steam to the main condenser using the turbine bypass valves. Unit 2 is not affected. Due to the Reactor Protection System actuation while critical, this event is being reported as a four-hour, non-emergency notification per 10 CFR 50.72(b)(2)(iv)(B). It is also reportable under 10 CFR 50.72(b)(3)(iv)(A) as an event that results in a valid actuation of the HPCI and RCIC systems and CIVs. There was no impact on the health and safety of the public or plant. The Licensee notified the NRC Resident Inspector. The Unit will proceed to Mode 4 while the cause of the loss of feed pumps is under investigation.
ENS 55224	30 April 2021 03:54:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Coolant Injection (Hpci) Declared Inoperable	On 4/29/21 at 2354 (EDT), an alarm was received for U2 HPCI Inverter Power Failure. (It was) identified that the High Pressure Coolant Injection (HPCI) flow controller had lost power due to a failure of an inverter. Without the flow controller, HPCI would not auto start to mitigate the consequences of an accident; thus, HPCI was declared inoperable. All other emergency core cooling systems and reactor core isolation cooling (RCIC) system remain operable. HPCI is a single train system with no redundant equipment in the same system; therefore, this failure is reportable as an event or condition that could have prevented fulfillment of a safety function needed to mitigate the consequences of an accident per 10CFR50.72(b)(3)(v)(d). The NRC Resident has been informed of this notification.
ENS 54826	10 August 2020 17:58:00	10 CFR 50.72(a)(1)(i), Emergency Class Declaration	Notice of Unusual Event Due to Loss of Offsite Power Due to High Winds	At 1258 CDT on August 10, 2020, Duane Arnold Energy Center declared an Unusual Event due to a loss of offsite power due to high winds. The event at the single unit plant resulted in an automatic scram from 82 percent power (Mode-1) to zero percent power (Mode-3). They are headed to Mode-4. There is damage on site, but the Reactor Building is intact. All rods inserted and cooling is being addressed via Reactor Core Isolation Cooling (RCIC) for level control and Safety Relief Valves are removing decay heat to the torus. Both Standby Diesel Generator are running. The licensee notified the NRC Resident Inspector, the Iowa Department of Emergency Management, and the Linn County and Benton County Emergency Management agencies. Notified DHS SWO, FEMA Operations Center, CISA Central, FEMA NWC (email), DHS Nuclear SSA (email), and FEMA NRCC SASC (email). * * UPDATE ON 08/10/2020 AT 1554 EDT FROM CURTIS HANSEN TO OSSY FONT * * * This report is being made under CFR 50.72 (b)(2)(iv)(B) for an automatic reactor scram due to loss of offsite power due to high winds. In addition, this report is being made under CFR 50.72 (b)(3)(iv)(A) and (B) due to PCIS ((Primary Containment Isolation System)) Groups 1, 2, 3, 4 and 5 (activating) due to loss of offsite power. All isolations went to completion. RCIC injecting for level control. All rods fully inserted during the scram. The plant electrical line up is both SBDGs (Standby Diesel Generators) are running. Decay heat is being removed via SRVs (Safety Relief Valves) to the torus. Progress towards shutdown cooling. NRC Senior Resident (Inspector) notified at 1448. Notified R3DO (Pelke).
ENS 54812	4 August 2020 03:12:00	10 CFR 50.72(a)(1)(i), Emergency Class Declaration	Unusual Event Declared Due to a Loss of Offsite Power	At 2312 EDT, on August 3, 2020, Brunswick Unit 1 declared an Unusual Event due to a loss of offsite power. The unit was at approximately 20 percent power and was not synced to the grid when the unit automatically scrammed. All control rods fully inserted. Emergency Diesel Generators started and began powering the safety buses. Safety systems actuated as expected. The Unit also experienced a loss of Fuel Pool Cooling and Cleanup System, but one pump was returned to service. Unit 2 remains at 100 percent power and is unaffected. The licensee notified State and local governments, as well as the NRC Resident Inspector. Notified DHS SWO, FEMA Operations Center, CISA IOCC, FEMA NWC (email), DHS Nuclear SSA (email), and FEMA NRCC SASC (email). * * UPDATE FROM MARK TURKAL TO DONALD NORWOOD AT 0120 EDT ON 8/4/2020 * * * At approximately 2302 EDT, a loss of offsite power occurred on Unit 1. This resulted in a Reactor Protection System (RPS) actuation. Per design, emergency diesel generators 1 and 2 properly started and loaded to their respective emergency buses. The Reactor Core Isolation Cooling (RCIC) system was manually started and is being used to control reactor water level. The High Pressure Coolant Injection (HPCI) system was manually started and is being used for pressure control. As previously reported, an Unusual Event was declared at 2312 EDT due to the loss of offsite power. At the time of the event, Unit 1 was in the process of shutting down for maintenance associated with a ground on the main generator. Due to the RPS actuation while critical, this event is being reported as a four-hour, nonemergency notification per 10 CFR 50.72(b)(2)(iv)(B). As a result of the reactor trip, reactor water level reached low level 1 (LL1). The LL1 signal causes a Group 2 (i.e., floor and equipment drain isolation valves), Group 6 (i.e., monitoring and sample isolation valves) and Group 8 (i.e., shutdown cooling isolation valves) isolations. The LL1 isolations occurred as designed; the Group 8 valves were closed at the time of the event. Per design, the loss of offsite power also caused a Group 1 (i.e., main steam isolation valve) isolations. Due to the Emergency Diesel Generator and Primary Containment Isolation System (PCIS) actuations, this event is also being reported as an eight-hour, nonemergency notification in accordance with 10 CFR 50.72(b)(3)(iv)(A). Unit 2 was not affected. There was no impact to the health and safety of the public or plant personnel. The safety significance of the event is minimal. All safety related systems operated as designed. Investigation of the cause of the loss of offsite power is in progress. The licensee notified the NRC Resident Inspector. Notified R2DO (Inverso). * * UPDATE ON 8/4/2020 AT 1534 EDT FROM JOSEPH ELKINS TO ANDREW WAUGH * * * At 1454 EDT on August 4, 2020, the Unusual Event was exited when offsite power was restored to Unit 1. Per design, when the loss of offsite power to Unit 1 occurred, all four emergency diesel generators (EDGs) started and EDGs 1 and 2 properly suppled emergency buses 1 and 2. Since Unit 2 was not affected by the loss of power, EDGs 3 and 4 ran unloaded. With restoration of offsite power to Unit 1, EDG 2 has been secured. EDGs 1, 3, and 4 are being secured as required by plant operating procedure. Notified R2DO (Inverso), NRR EO (Miller), IRD MOC (Grant), DHS SWO, FEMA OC, DHS NICC WO, CISA IOCC (email), DHS SWO (email), FEMA NWC (email), FEMA Ops Center (email), FEMA-NRCC-sasc (email), NRCC THD Desk (email), NuclearSSA (email). ********************************************************************************************************************************
ENS 54691	3 May 2020 12:21:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation	Automatic Reactor Scram Due to Main Turbine Trip	At 0821 EDT on May 3, 2020, the Susquehanna Steam Electric Station Unit 1 reactor automatically scrammed due to a trip of the Main Turbine. The Unit 1 reactor was operating at 76 percent reactor power following a ramp schedule to full power subsequent to a maintenance outage. The Control Room received indication of a Main Turbine trip with both divisions of the Reactor Protection System actuated and all control rods inserted. The Reactor Recirculation Pumps tripped on End of Cycle - Recirculation Pump Trip. Reactor water level lowered to -1 inch causing Level 3 (+13 inches) isolations. No Emergency Core Cooling System or Reactor Core Isolation Cooling actuations occurred. The operations crew subsequently maintained reactor water level at the normal operating band using Reactor Feed Water. No Steam Relief Valves opened. The reactor is currently stable in Mode 3. Investigation into the trip of the Main Turbine is in progress. The NRC Resident Inspector was notified. A voluntary notification to the Pennsylvania Emergency Management Agency and press release will occur. This event requires a 4-hour Emergency Notification System (ENS) notification in accordance with 10 CFR 50.72(b)(2)(iv)(B) and an 8-hour ENS notification in accordance with 10 CFR 50.72(b)(3)(iv)(A) and 10 CFR 50.72(b)(3)(iv)(B).
ENS 54292	25 September 2019 06:38:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Loss of High Pressure Core Spray System	At 2338 PDT on September 24, 2019, the High Pressure Core Spray (HPCS) system was declared inoperable due to a leak on DSA-PCV-2C (2 inch Diesel Starting Air Pressure Control Valve). With one of two air headers isolated and being drained for maintenance, this leak caused the remaining starting air header for HPCS-GEN-DG3 (HPCS Diesel Generator) to lower to less than the operability limit. Upon declaring the HPCS system inoperable, TS 3.5.1 Action B was entered. In accordance with Action B, the Reactor Core Isolation Cooling (RCIC) system was verified to be operable. Action B provides a 14 day completion time to restore HPCS to an operable status. All other Emergency Core Cooling Systems (ECCS) were operable during this event. This event is being reported as an event or condition that could have prevented the fulfillment of a safety function credited for mitigating the consequences of an accident per 10 CFR 50.72(b)(3)(v)(D). The HPCS system is a single train system at Columbia. The leak was isolated and starting air header pressure restored to the HPCS diesel generator at 0104 PDT on September 25, 2019, and all associated Technical Specifications were exited. The NRC Resident Inspector was notified.
ENS 54198	3 August 2019 23:47:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Manual Reactor Trip and Manual Actuation of Reactor Core Isolation Cooling	At 1947 (EDT) on 8/3/19, with Hope Creek in Mode 1 at 37 percent power, the reactor was manually scrammed due to loss of condenser vacuum. All control rods fully inserted into the core. All safety systems responded as designed and expected. Reactor level was stabilized using Reactor Core Isolation Cooling (RCIC) and Reactor Feedwater Pumps. Currently reactor water level is being maintained by the feedwater system and decay heat is being removed by the main condenser using the main turbine bypass valves. Due to the Reactor Protection System actuation while critical, this event is being reported as a four-hour, non-emergency notification per 10 CFR 50.72(b)(2)(iv)(B). Due to the manual actuation of RCIC, this event is also being reported as an eight-hour, non-emergency notification per 10 CFR 50. 72(b )(3)(iv)(A). There was no impact on the health and safety of the public or plant personnel. The NRC Resident Inspector has been notified. The plant is in its normal shutdown electrical lineup with all safe shutdown equipment available. The licensee will be notifying the state of Delaware, state of New Jersey and the Lower Alloway Creek township.
ENS 54197	3 August 2019 07:26:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge	En Revision Imported Date 8/7/2019	EN Revision Text: AUTOMATIC REACTOR SCRAM ON LOW REACTOR WATER LEVEL At 0226 (CDT), an automatic scram on low reactor water level occurred due to a trip of the 'B' Reactor Feed pump. All control rods fully inserted. Reactor water level 2 was reached and the High Pressure Core Spray system, Reactor Core Isolation Cooling system, Division 3 diesel generator, Standby Gas Treatment Systems 'A' and 'B' and all shutdown safety related service water pumps started as expected. Reactor Core Isolation Cooling and High Pressure Core Spray injected as expected. All level 2 containment isolation signals occurred as expected and all level 2 containment valves closed as expected. Reactor water level is currently being controlled in band by condensate. Reactor pressure is being maintained by main turbine Bypass Valves. This event is being reported under 10 CFR 50.72(b)(2)(iv)(A), for ECCS discharge to RCS; 10 CFR 50.72(b)(2)(iv)(B), for RPS actuation, and 10 CFR 50.72(b)(3)(iv)(A), for specified system actuation. The NRC Senior Resident Inspector has been notified. No safety relief valves lifted during the transient. The plant is in a normal shutdown electrical lineup with all safety equipment available. The licensee notified the Illinois Emergency Management Agency per their communications protocol. * * UPDATE FROM DAVID LIVINGSTON TO HOWIE CROUCH AT 0321 EDT ON 8/4/19 * * * Following automatic initiation of the High Pressure Core Spray (HPCS) System as described above, the HPCS System was manually secured following station procedures after verification that additional RPV (reactor pressure vessel) injection was no longer required. Securing HPCS injection in this manner prevents automatic restart of the system in the event of a subsequent low RPV level condition, rendering it inoperable. As the HPCS system is considered a single train safety system, this meets the reportability requirements of 10 CFR 50.72(b)(3)(v)(D). This reportable condition was identified following review of post-scram actions. The HPCS system has been restored to a Standby lineup. The licensee will be notifying the NRC Resident Inspector. Notified R3DO (Pelke). * * UPDATE FROM JAMES FORMAN TO KERBY SCALES AT 1545 EDT ON 8/6/19 * * * Following the scram, the Primary Containment to Secondary Containment and the Drywell to Primary Containment differential pressure limits were exceeded. Technical Specification (TS) Limiting Condition for Operation (LCO) 3.6.1.4, Primary Containment Pressure, and 3.6.5.4, Drywell Pressure, Actions A.1, B.1, and B.2 were entered. Primary Containment to Secondary Containment differential pressure and Drywell to Primary Containment differential pressure were restored to within the LCO limits at 1505 on 8/3/19 and the associated TS Actions were exited. This event is reportable under 10 CFR 50.72(b)(3)(ii)(B) as an unanalyzed condition that could have prevented the fulfillment of the primary containment function due to being outside the initial conditions to ensure that drywell and containment pressures remain within design values during a loss of coolant accident. This event is also reportable under 10 CFR 50.72(b)(3)(v)(C) as an event or condition that could have prevented the fulfillment of the drywell and primary containment functions to control the release of radioactive material for the same reason. The licensee notified the NRC Resident Inspector. Notified R3DO (Pelke).
ENS 54116	13 June 2019 01:27:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Coolant Injection (Hpci) Inoperable	At 2127 EDT on June 12, 2019, during routine testing, the HPCI turbine experienced an overspeed trip and then subsequently restarted and ramped to the required speed. As a result, the response time of the system exceeded the 60-second acceptance criteria, thereby rendering the system inoperable. This condition is being reported as an eight-hour, non-emergency notification per 10 CFR 50.72(b)(3)(v)(D). The Reactor Core Isolation Cooling (RCIC) System and Automatic Depressurization System (ADS) are operable. The safety significance of this event is minimal. Troubleshooting activities are in progress. There was no impact on the health and safety of the public or plant personnel. The NRC Resident Inspector has been notified.
ENS 54102	5 June 2019 04:00:00	10 CFR 21.21(d)(3)(i), Failure to Comply or Defect 10 CFR 21.21(a)(2), Interim Report for Comply or Defect in Component	En Revision Imported Date 10/14/2019	EN Revision Text: PART 21 INTERIM NOTIFICATION - FAILURE OF A SIGNAL CONVERTER SUPPLIED TO COOPER NUCLEAR PLANT The following is a summary of the information received from Engine Systems, Inc. via facsimile: ESI was notified on April 6, 2019 that a signal converter (also called a signal conditioner) that sends the Reactor Core Isolation Cooling turbine speed to the turbine controller had failed. The converter is at the manufacturer's facility undergoing testing at this time and they have been unable to complete their evaluation within 60-days. The evaluation is expected to be completed by July 31, 2019. The converter was only supplied to Cooper Nuclear Plant. * * UPDATE FROM DAN ROBERTS TO DONALD NORWOOD AT 1710 EDT ON 7/19/2019 * * * The following is a synopsis of information received via facsimile: On June 5, 2019, Engine Systems, Inc. (ESI) issued an interim report regarding an identified deviation for which ESI was unable to complete an evaluation within the 60-day requirement. Per the interim report, ESI committed to complete the evaluation by July 31, 2019. The evaluation is now complete and the deviation is determined to be reportable in accordance with 10 CFR Part 21. ESI supplied the component which failed to comply or contained a defect. That part was a Signal Converter Transmitter, P/N SCT/4-20MA/4-20MA/24DC/-LIM-TA(DCM). This component was only supplied to Cooper Nuclear Station. The nature of the defect was that a power inverter transformer, internal to the signal converter transmitter, failed shorted. The transformer failure adversely affected other circuit board mounted components which prevented the device from functioning properly. The signal converter transmitter is a component of a turbine control panel. Within the panel, the transmitter is used to sense the customer's remote speed setpoint input signal and convert the signal which is transmitted to the turbine control. Since the signal converter transmits the customer's remote speed setpoint input to the turbine control, operability of the device is critical to operation of the RCIC turbine control system. Therefore, a failure of the signal converter would adversely affect the RCIC turbine control system and thus may affect the safe shutdown of the reactor. At Cooper Nuclear Station, the failed component has been removed and replaced with a spare transmitter from a different batch. No further action is necessary. For ESI, the previous design transformer (used in the failed transformer) was discontinued by the transformer manufacturer in 2016 which required the signal converter transmitter manufacturer to source a new transformer. The new transformer has the same functionality with a slightly different form factor which minimizes the potential for common cause failure with the original style transformer. Therefore, no additional actions are required since a different transformer is in current use. ESI has included a verification of the current transformer design in the commercial grade dedication package. The names and addresses of the individuals reporting this information are: John Kriesel Engineering Manager Engine Systems, Inc.; 175 Freight Rd. Rocky Mount, NC 27804 Dan Roberts Quality Manager Engine Systems, Inc.; 175 Freight Rd. Rocky Mount, NC 27804 Notified R4DO (Proulx) and the Part 21/50.55 Reactors E-mail group. * * UPDATE FROM DAN ROBERTS TO DONALD NORWOOD AT 1643 EDT ON 10/11/2019 * * * The following is a synopsis of information received via facsimile: Subsequent to the issue of the report on July 19, 2019, ESI became aware of another potential defect with the same device. As a result, ESI has amended the report to expand the extent of condition. ESI supplied the component which failed to comply or contained a defect. That part was a Signal Converter Transmitter, P/N SCT/4-20MA/4-20MA/24DC/-LIM-TA(DCM). This component was only supplied to Cooper Nuclear Station. The nature of the defect was that four circuit board mounted components (two transistors, a capacitor, and a diode) failed, causing the device to go to zero output. These prevented the device from functioning properly. Corrective actions for Cooper Nuclear: As stated above, no further action is necessary. Corrective actions for ESI for the subsequent failure: ESI has been unable to positively determine the root cause; however, correspondence with the signal converter manufacturer indicates this may be related to the previous style transformer. While no anomalies were detected with the transformer, the failed components are electrically connected to the transformer. Verification of the current style transformer is performed in the commercial grade dedication package. The names and addresses of the individuals reporting this information are: John Kriesel Engineering Manager Engine Systems, Inc.; 175 Freight Rd. Rocky Mount, NC 27804 Dan Roberts Quality Manager Engine Systems, Inc.; 175 Freight Rd. Rocky Mount, NC 27804 Notified R4DO (Kellar) and the Part 21/50.55 Reactors E-mail group.
ENS 54096	1 June 2019 04:45:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Manual Reactor Scram Due to Low Reactor Water Level	At 2345 CDT at River Bend Station (RBS) Unit 1, a manual Reactor scram was inserted in anticipation of receiving an automatic Reactor Water Level 3 (9.7") scram due to the isolation of the 'B' Heater String with the 'A' Heater String already isolated. The 'B' heater string isolation caused loss of suction and subsequent trip of the running Feed Water Pumps 'A' and 'C'. All control rods fully inserted with no issues. Subsequently Reactor level was controlled by the Reactor Core Isolation Cooling (RCIC) system. Feed Water Pump 'C' was restored 4 minutes after the initial trip and the RCIC system secured. Currently RBS-1 is stable and is being cooled down using Turbine Bypass Valves. No radiological releases have occurred due to this event from the unit. The plant is currently under a normal shutdown electrical lineup. The licensee notified the NRC Resident Inspector. * * UPDATE AT 1603 EDT ON 6/10/19 FROM ALFONSO CROEZE TO JEFF HERRERA * * * This amended event notification is being made to provide additional information that was not included in the original notification made on 6/1/19 at 0315 EDT. This event was reportable under 10 CFR 50.72(b)(3)(iv)(A) which was not annotated or described in the original report. Forty-two minutes after the Feed Water Pump 'C' was started, the pump tripped causing a Reactor Water Level 3 (9.7") RPS actuation. Feed Water was restored five minutes later using the Feed Water Pump 'A'. The NRC Resident Inspector has been notified. Notified the R4DO (Warnick).
ENS 53942	17 March 2019 12:35:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	En Revision Imported Date 4/24/2019	EN Revision Text: HIGH PRESSURE COOLANT INJECTION SYSTEM DECLARED INOPERABLE At 0735 CDT on March 17, 2019, the High Pressure Coolant Injection (HPCI) system was isolated due to a water-side leak from the HPCI Gland Seal Condenser. Unit 3 declared the HPCI system Inoperable and entered Technical Specification LCO 3.5.1 Condition C with required actions to verify the Reactor Core Isolation Cooling system is Operable, and to restore the HPCI system to Operable status within 14 days. All other Unit 3 Emergency Core Cooling Systems (ECCS) remain Operable. This condition is being reported pursuant to 10 CFR 50.72(b)(3)(V)(D), 'Any event or condition that at the time of discovery could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident.' This is also reportable as a 60-day written report in accordance with 10 CFR 50.73(a)(2)(V)(D). There was no impact on the health and safety of the public or plant personnel. The NRC Resident Inspector has been notified of this event. * * RETRACTION FROM WESLEY CONKLE TO HOWIE CROUCH ON 4/23/19 AT 1549 EDT * * * ENS Event Number 53942, made on March 17, 2019, is being retracted. NRC Notification 53942 was made to ensure that the Eight-Hour Non-Emergency reporting requirements of 10 CFR 50.72 (b)(3)(v)(D) were met when the licensee discovered an event, that at the time of discovery, could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident. At 0735 CDT, on March 17, 2019, during the performance of a routine surveillance, a momentary pressure transient of 844 psig from the Feedwater system was introduced into the High Pressure Coolant Injection (HPCI) system discharge and suction piping that ruptured the seal on the gland seal condenser and flooded the U3 HPCI Room. Unit 3 HPCI was declared inoperable due to isolation of the waterside of the HPCl system. On April 11, 2019, a Past Operability Evaluation was completed which determined that the HPCI System remained operable. The evaluation of the potential pressure transient and room flooding concluded that the HPCI System could have performed its specified safety function of vessel injection throughout the time that the gland seal was ruptured. Therefore, this event is not reportable under 10 CFR 50.72(b)(3)(v)(D). TVA's evaluation of this event is documented in the Corrective Action Program in Condition Report 149973. The licensee has notified the NRC Resident Inspector. Notified R2DO (Ehrhardt).
ENS 53923	10 March 2019 04:59:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Automatic Scram Resulting in Rps and Eccs Actuation	At 2259 CST on 3/9/2019, Browns Ferry Unit-3 received an automatic SCRAM on Main Generator Breaker Failure and Turbine Load Reject. Unit-3 declared a Notification of Unusual Event SU1 for loss of offsite AC power to Unit-3 specific 4kV Shutdown Boards for greater than 15 minutes. Primary Containment Isolation Systems (PCIS) Groups 1, 2, 3, 6, and 8 isolation signals were received. Upon receipt of these signals, all required components actuated as required. Main steam relief valves lifted on the initial transient. High Pressure Coolant Injection (HPCI) and Reactor Core Isolation Cooling (RCIC) initiated on low reactor water level. HPCI remains in service for reactor level and pressure control. RCIC is not in service at this time, the station is investigating low flow from the pump. All four Unit-3 Diesel Generators started and loaded as expected. Residual Heat Removal System is in service for suppression pool cooling. 4kV Station Unit Boards have been restored from the 161kV system. Actions are in progress to restore 4kV Shutdown Boards to offsite power. This event is reportable within 1 hour in accordance with 10 CFR 50.72(a)(1)(i) for declaration of the Licensees Emergency Plan. Complete as documented on EN 53922. This event requires a 4 hour report per 10 CFR 50.72(b)(2)(iv)(B), 'Any event or condition that results in actuation of the reactor protection system (RPS) when the reactor is critical except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation.' This event also requires an 8 hour report per 10 CFR 50.72(b)(3)(iv)(A). 'Any event or condition that results in valid actuation of any of the systems listed in paragraph (b)(3)(iv)(B), (1) Reactor protection system (RPS) including: reactor scram or reactor trip, (2) General containment isolation signals affecting containment isolation valves in more than one system or multiple main steam isolation valves (MSIVs), (4) ECCS (Emergency Core Cooling System) for boiling water reactors (BWRs) including: core spray systems; high-pressure coolant injection system; low pressure injection function of the residual heat removal system, (5) BWR reactor core isolation cooling system; isolation condenser system; and feedwater coolant injection system, and (8) Emergency AC electrical power systems, including: Emergency diesel generators (EDGs).' The NRC resident inspector has been notified. As of the event report, the MSIVs were opened and decay heat was being removed via the bypass valves to the condenser.
ENS 53861	6 February 2019 00:04:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Unit One Hpci System Inoperable Due to Blown Fuse	On February 5, 2019, at 1804 (CST), during a Unit 1 High Pressure Coolant Injection (HPCI) operability surveillance, a fuse blew in the logic for the motor speed changer for the turbine. The Unit 1 HPCI system was taken out of service for planned maintenance earlier in the day. The fuse issue was not related to any maintenance activities. Had HPCI been demanded, this fuse failure would not have allowed HPCI to reach its required speed. HPCI remains inoperable pending resolution of the issue. The Reactor Core Isolation Cooling (RCIC) system was confirmed operable. There were no other systems inoperable at the time of the event. HPCI had been last successfully tested on November 6, 2018. This event is being reported as a condition that could have prevented fulfillment of a safety function in accordance with 10 CFR 50.72(b)(3)(v)(D). The HPCI system is a single train system and the loss of HPCI could impact the plant's ability to mitigate the consequences of an accident. The NRC Senior Resident Inspector has been notified. Inoperable HPCI places the unit in a 14 day Technical Specification Limiting Condition of Operability.
ENS 53818	8 January 2019 05:00:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Reactor Core Isolation Cooling Declared Inoperable	On January 8, 2019, at 0945 EST Pilgrim Nuclear Power Station discovered that the Reactor Core Isolation Cooling (RCIC) system failed to meet its surveillance test requirements and was declared inoperable; therefore, this condition is being reported as an eight-hour, non-emergency notification per 10 CFR 50.72(b)(3)(v), 'event or condition that could have prevented the fulfillment of a safety function: (D), mitigate the consequences of an accident.' There was no impact on the health and safety of the public or plant personnel. The NRC Resident Inspector has been notified.
ENS 53788	12 December 2018 06:00:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge	En Revision Imported Date 12/17/2018	EN Revision Text: MANUAL REACTOR SCRAM DUE TO FAILED OPEN TURBINE BYPASS VALVE At 1351 CST, the reactor was manually shutdown due to 'A' Turbine Bypass Valve opening. The Main Steam Line Isolation Valves were manually closed to facilitate reactor pressure control. Reactor level is being maintained through the use of Reactor Core Isolation Cooling System, Control Rod Drive System, and High Pressure Core Spray System. High Pressure Core Spray System was manually started to initially support reactor water level control. Reactor Pressure is being controlled through the use of the Safety Relief Valves and the Reactor Core Isolation Cooling System. The plant is stable in MODE 3. The cause of the 'A' Turbine Bypass Valve opening is under investigation at this time. The NRC Resident Inspector has been notified. * * UPDATE ON 12/14/18 AT 1140 EST FROM GERRY ELLIS TO TOM KENDZIA * * * This is an update to EN # 53788 to correct an error on the event classification block of the form. The original notification did not have the block for 8 hour notification for Specified System Actuation checked. The actuation of Reactor Core Isolation Cooling System was discussed in original notification. The licensee notified the NRC Resident Inspector. Notified R4DO (Taylor).
ENS 53776	13 October 2018 05:00:00	10 CFR 50.73(a)(1), Submit an LER	60-Day Optional Telephonic Notification of Invalid Specified System Actuation	This 60-day telephone notification is being made per the reporting requirements specified by 10 CFR 50.73(a)(2)(iv)(A) and 10 CFR 50.73(a)(1) to describe an invalid actuation of a Primary Containment Isolation System (PCIS) Group 1 for Main Steam Isolation Valves (MSIVs), Group 3 for Reactor Water Cleanup (RWCU), Group 6 for Secondary Containment isolation, Group 7 for Reactor Water Sampling, Diesel Generator, Reactor Core Isolation Cooling (RCIC) System logic, and Residual Heat Removal (RHR) logic. Group 1, Group 6, Diesel Generator actuation, RCIC actuation and RHR actuation are within scope of 10 CFR 50.73(a)(2)(iv). Group 3 and Group 7 are not within scope as they affect only one system. Cooper Nuclear Station (CNS) was shut down in Mode 5 at the time of the event with the reactor cavity flooded. On October 13, 2018, at 0028 Central Daylight Time, CNS received full PCIS Groups 1, 3, and 6, and a half Group 7 on the Division 1 side. The MSIVs and RWCU isolation valves were already closed for maintenance. The Secondary Containment isolated. Control Room Emergency Filter and the Standby Gas Treatment Systems initiated. The inboard Reactor Water Sample valve isolated. Diesel Generator #1 started but was not required to connect to the critical bus. Reactor Core Isolation Cooling System logic actuated with no expected response due to being isolated for shutdown conditions. Division 1 RHR pump logic actuated. Division 1 RHR system was operating in shutdown cooling mode. The actuation caused the Division 1 RHR outboard injection and heat exchanger bypass valves to open. Shutdown cooling was unaffected and remained in service throughout the event. The plant systems responded as expected with no Emergency Core Cooling System injection. At the time of the event, an in-service inspection of welds inside the reactor vessel was taking place using a robot scanner that uses two vortex thrusters to hold the robot to the vessel wall. The robot inadvertently passed over an instrument penetration, drawing suction on the process leg, resulting in low reactor water level indications and the subsequent invalid Level 1 and 2 system actuations. Actual reactor vessel water level remained steady at cavity flooded conditions. The NRC Resident Inspector has been notified of this event.
ENS 53676	19 October 2018 05:00:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge	Automatic Reactor Trip Due to Feedwater Regulating Valve Failing Closed	At 1725 CDT, a Feedwater Regulating valve failed closed, resulting in a reactor level transient, which initiated a reactor trip, Primary Containment Isolation System signals to valves in Groups 2, 3, and 4 and initiation of High Pressure Coolant Injection and Reactor Core Isolation Cooling. All control rods inserted and level has been restored to normal. The cause of the feedwater valve failure is under investigation. All other systems responded as expected. This report is being made under 10 CFR 50.72 (b)(2)(iv)(B), (b)(3)(iv)(A) and (b)(2)(iv)(A). The Senior Resident Inspector has been informed. Decay heat is being removed via the main condenser and reactor vessel water level is being maintained by the condensate and feedwater systems.
ENS 53630	30 September 2018 04:00:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge	Automatic Scram Due to a Loss of Two Condensate Pumps	On Sunday, September 30, 2018, at 1130 EDT, an automatic scram was received on U3 following a loss of two condensate pumps. Following the reactor scram, water level lowered from normal level of 23" to below 1" which resulted in automatic Group II and Group III isolations. Reactor water level lowered to -48" which resulted in initiation of the High Pressure Coolant Injection and Reactor Core Isolation Cooling systems. Reactor water level and reactor pressure have been restored to their normal bands. All systems responded properly to the event. Unit 3 remains in Mode 3 with reactor pressure being controlled on the turbine bypass valves. The cause and details of the event are under investigation. This report is being made in accordance with 10 CFR 50.72(b)(2)(iv)(A), 10 CFR 50.72(b)(2)(iv)(B), and 10 CFR 50.72(b)(3)(iv)(A). All control rods inserted. Decay heat is being removed via the main condenser. The NRC Resident Inspector has been notified. A notification to the media and a press release were made. Unit 2 was unaffected and continues coastdown to refueling.
ENS 53625	26 September 2018 04:00:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Core Injection (Hpci) System Inoperable	On 9/26/2018 at 1530 EDT, it was discovered that the HPCI system was inoperable due to a blown fuse in the 10C617 Panel, E21-F15A. Therefore, this condition Is being reported as an eight-hour, non-emergency notification per 10 CFR 50.72(b)(3)(v)(D). The blown fuse also impacts 'A' channel Residual Heat Removal (RHR) subsystem and 'A' Core Spray (CS) subsystem. These Emergency Core Cooling subsystems have been declared inoperable. Remaining Emergency Core Cooling subsystems and the Reactor Core Isolation Cooling (RCIC) system remain OPERABLE. There was no impact on the health and safety of the public or plant personnel." The licensee notified the NRC Resident Inspector and will notify the local authorities.
ENS 53617	21 September 2018 04:00:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident 10 CFR 50.72(b)(2)(i), Tech Spec Required Shutdown 10 CFR 50.72(b)(3)(ii)(A), Seriously Degraded	High Pressure Coolant Injection System Inoperable	On 9/21/18, at 1755 EDT, Peach Bottom Atomic Power Station Unit 3 declared the High Pressure Coolant Injection system (HPCI) inoperable due to an inoperable differential pressure indicating switch (DPIS). The DPIS is used to isolate the HPCI system when there is a high steam line flow condition. Operations declared the HPCI system inoperable and entered Technical Specification 3.5.1 Condition C for HPCI being inoperable. Technical Specification 3.3.6.1 was also entered for HPCI instrumentation being inoperable. Other standby systems (Reactor Core Isolation Cooling and Low Pressure Emergency Core Cooling Systems) are OPERABLE. HPCI is a single train system. Therefore, per NUREG-1022, this condition is being reported pursuant to 10CFR 50.72(b)(3)(v)(D) as a condition that could have prevented the fulfillment of the safety function of a system required to mitigate the consequences of a design event. This condition has been entered into the corrective action program (IR 4175355). Investigation of the exact cause of the indication issue is in progress. The NRC Resident has been informed of this notification. * * UPDATE AT 1317 EDT ON 09/22/2018 FROM CRAIG TAULMAN TO JEFF HERRERA * * * On 09/22/18 at 0955 EDT, RCS (Reactor Coolant System) pressure boundary leakage was identified as the cause of the HPCI high steam flow indication issue. Technical Specification 3.4.4 was entered which will require the initiation of a nuclear plant shutdown. This indicates a degradation of a principal safety barrier. Current Unit 3 reactor power is 35%. This condition is being reported pursuant to 10 CFR 50.72(b)(2)(i) and 50.72(b)(3)(ii). This condition is being tracked in the corrective action program (IR 4175355). The NRC Resident has been informed". Peach Bottom will be notifying State and local agencies regarding the event. Notified the R1DO (Greives).
ENS 53265	15 March 2018 19:24:00	10 CFR 50.72(b)(3)(ii)(B), Unanalyzed Condition	Failure to Meet Appendix R Requirements	At 1524 (EDT) on Thursday, March 15, 2018, Operations was notified of a failure to meet Appendix R requirements for Peach Bottom Atomic Power Station (PBAPS) Unit 2 and Unit 3. Valves associated with the feedwater system for both units were not properly considered as Hi-Lo Pressure interface valves as required by the Appendix R program. This results in the susceptibility to a hot short condition that could open valves, diverting flow from the reactor, damage piping and prevent injection. U3 (Unit 3) Fire Safe Shutdown Credited Reactor Core Isolation Cooling (RCIC) System is affected. U2 (Unit 2) is affected by a potential leak path through the Reactor Water Cleanup system. This event is being reported as an occurrence of an event or condition that results in the nuclear power plant being in an unanalyzed condition that significantly degrades plant safety under 10 CFR 50.72(b)(3)(ii). The Station (PBAPS) is performing hourly fire watches for the impacted areas and is also evaluating this condition for corrective action. The licensee notified the NRC Resident Inspector.
ENS 53188	31 January 2018 00:22:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Manual Reactor Scram Due to Main Turbine Load Oscillations	On 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 53162	10 January 2018 15:28:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Automatic Reactor Scram Due to Turbine Control Valve Fast Closure Scram Signal	At 0928 CST on January 10, 2018, the Unit 3 reactor automatically scrammed due to a Reactor Protection System (RPS) signal generated from Turbine Control Valve Emergency Trip System pressure low. The reactor had been operating near 73 percent power for an emergent issue for Turbine Control Valve (TCV) No. 3. With TCV No. 3 out of service and closed, the unit was operating with RPS in a half scram condition. A subsequent failure of the TCV No. 2 sensing line resulted in RPS coincidence logic being met for TCV fast closure SCRAM. The investigation of the TCV No. 2 sensing line failure continues. All control rods fully inserted into the core. Main Steam Isolation Valves remained open with Main Turbine Bypass Valves controlling reactor pressure. Reactor Feedwater pumps remained in service to control reactor water level. Primary Containment Isolation Signals Groups 2, 3, 6, and 8 containment isolation and initiation signals were received. Upon receipt of these signals all required components actuated as required. Neither High Pressure Coolant Injection nor Reactor Core Isolation Cooling initiation signals were received. This event is reportable within 4 hours per 10 CFR 50.72(b)(2)(iv)(B) 'any event or condition that results in actuation of the Reactor Protection System (RPS) when the reactor is critical except when the actuation results from and is part of a preplanned sequence during testing or reactor operation.' It is also reportable within 8 hours per 10 CFR 50.72(b)(3)(iv)(A) and requires an LER within 60 days per 10 CFR 50.73(a)(2)(iv)(A). The NRC Resident inspector has been notified.
ENS 53123	17 December 2017 08:16:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Coolant Injection (Hpci) System Declared Inoperable	On December 17, 2017 at 0316 EST, the Unit 2 HPCI system was isolated and declared inoperable due to a packing failure of the HPCI Turbine Steam Supply Valve (i.e., 2-E41-F001). Isolation of the HPCI system due to the packing failure prevents the HPCI system from performing its design safety function. As such, this event is being reported in accordance with 10 CFR 50.72(b)(3)(v)(D) as a condition that at the time of discovery could have prevented the fulfillment of the safety function of a system that is needed to mitigate the consequences of an accident. Unit 2 HPCI system has been isolated and depressurized. The HPCI system will remain inoperable until the valve can be repaired. The safety significance of this condition is minimal. All other Emergency Core Cooling Systems (ECCS) and the Reactor Core Isolation Cooling (RCIC) system remain operable. This event did not result in any adverse impact to the health and safety of the public. The NRC Resident Inspector has been notified. * * RETRACTION ON 1/29/18 AT 1514 EST FROM MARK TURKAL TO DONG PARK * * * Based upon further evaluation, Duke Energy is retracting Event Notification 53123. Engineering has determined that the packing failure of the HPCI Turbine Steam Supply Valve did not prevent the HPCI system from performing its safety function. Environmental conditions resulting from the steam leak would not have caused automatic HPCI isolation or otherwise have degraded HPCI operation. Additionally, the amount of steam diverted through the packing leak was negligible with respect to total steam flow and did not affect HPCI system performance. HPCI would have remained operable throughout its entire mission time. Therefore, this condition does not represent an event or condition that could have prevented fulfillment of a safety function needed to mitigate the consequences of an accident and is not reportable in accordance with 10 CFR 50.72(b)(3)(v)(D). The NRC Resident Inspector was notified of this retraction. Notified R2DO (Heisserer).
ENS 53115	12 December 2017 15:18:00	10 CFR 50.72(b)(3)(iv)(A), System Actuation	Automatic Start of Edg Due to Loss of Esf Transformer	At 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 53059	8 November 2017 00:10:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Unit 1 High Pressure Coolant Injection Inoperable	On November 7, 2017 at 1810 (CST), Unit 1 High Pressure Coolant Injection (HPCI), was manually isolated following failure of the remote turbine trip pushbutton to function. Unit 1 HPCI Operability Testing was in progress to the point of securing the HPCI turbine with the remote manual pushbutton. The pushbutton failed to trip the turbine resulting in operator action to lower the flow controller setpoint and isolating the HPCI steam line. HPCI remains isolated and is Inoperable pending resolution of the Turbine Trip circuitry. This event is being reported as a condition that could have prevented fulfillment of a safety function in accordance with 10CFR50.72(b)(3)(v)(D). The HPCI system is a single train system and the loss of HPCI could impact the plant ability to mitigate the consequences of an accident. The Reactor Core Isolation Cooling (RCIC) system was confirmed operable. The NRC Senior Resident Inspector has been notified.
ENS 52955	8 September 2017 16:30:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Hpci System Inoperable	On September 8, 2017 at 1130 hours CDT, Unit Two High Pressure Coolant Injection (HPCI) Minimum Flow Valve MO 2-2301-14 flow indicating switch (FIS 2-2354) failed to meet the Technical Specification Allowable Value during calibration testing. Technical Specification Table 3.3.5.1-1 Allowable Value (3.f) requires greater than or equal to 634 gpm (3.14 inches water column as required by procedure). HPCI was subsequently declared inoperable. This event is being reported as a condition that could have prevented fulfillment of a safety function in accordance with 10CFR50.72(b)(3)(v)(D). The HPCI system is a single train system and the loss of HPCI could impact the plant's ability to mitigate the consequences of an accident. The Reactor Core Isolation Cooling (RCIC) system was confirmed operable. Note: On September 8, 2017 at 1140 hours CDT, the HPCI Minimum Flow Valve MO 2-2301-14 flow indicating switch (FIS 2- 2354) was successfully recalibrated and HPCI was returned to Operable status. The NRC Senior Resident Inspector has been notified. * * RETRACTION AT 1216 EDT ON 10/19/17 FROM RYAN DECKER TO DONG PARK * * * The purpose of this notification today (10/19/17) is to retract the ENS Report made on September 8, 2017 at 1545 hours CDT (ENS Report #52955). Upon further investigation, it was determined that a surveillance procedure contained an overly restrictive statement that directed operators to immediately declare the High Pressure Coolant Injection (HPCI) system inoperable when the HPCI Minimum Flow Valve MO 2-2301-14 flow indicating switch (FIS 2-2354) fails. This statement was in conflict with existing Technical Specification (TS) 3.3.5.1, Condition E, that allows seven days to restore the HPCI FIS (instrument channel only) to an operable status prior to entry into TS 3.3.5.1, Condition H, which requires declaring HPCI inoperable immediately. Hence, during the period of FIS inoperability (i.e., 10 minutes), the HPCI system was not required to be declared inoperable in accordance with Technical Specifications. Therefore, based on this information, ENS Report # 52955 is being retracted. Note: On September 8, 2017 at 1140 hours CDT, the HPCI Minimum Flow Valve MO 2-2301-14 flow indicating switch (FIS 2-2354) was successfully recalibrated and HPCI was returned to Operable status. The NRC Resident Inspector has been notified. Notified R3DO (Daley).
ENS 52758	16 May 2017 00:18:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Coolant Injection System Declared Inoperable	On May 15, 2017 at 1918 hours (CDT), Unit Two High Pressure Coolant Injection (HPCI) Minimum Flow Valve MO 2-2301-14 failed to open as required by procedure and HPCI was declared inoperable. When the HPCI Turbine was tripped, the Minimum Flow Valve did not open when system flow reduced to the low flow setpoint. This event is being reported as a condition that could have prevented fulfillment of a safety function in accordance with 10CFR50.72(b)(3)(v)(D). The HPCI system is a single train system and the loss of HPCI could impact the plant's ability to mitigate the consequences of an accident. In accordance with Technical Specification 3.5.1 Condition G, the Reactor Core Isolation Cooling (RCIC) system was confirmed operable. This places the plant in a 14-day LCO action statement. The licensee has notified the NRC Resident Inspector.
ENS 52663	4 April 2017 05:10:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Manual Reactor Scram Due to Condensate Leak	At 0010 (CDT), 04/04/2017, the reactor was manually scrammed from approximately 75 (percent) core thermal power due Condensate Storage tank level lowering to 24 feet. All control rods fully inserted and all systems actuated and operated as designed. No safety relief valves actuated. Reactor level and pressure are currently being controlled within normal bands. RCIC (reactor core isolation cooling) was manually initiated for level control. This event is reportable under 10CFR50.72(b)(2)(iv)(B) for the reactor trip and 50.72(b)(3)(iv)(A) for the manual start of the reactor core isolation cooling system. The cause of lowering level was a condensate pipe leak. Decay heat is being removed via steam dumps to the condenser. The electrical grid is stable and supplying plant loads. The licensee has notified the NRC Resident Inspector.
ENS 52648	29 March 2017 23:44:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Manual Scram Initiated During Startup	At 1844 CDT on 3/29/2017, Unit 2 initiated a manual scram due to multiple rods inserting. At 1842 during Unit 2 start-up, Intermediate Range Monitor (IRM) 'G' drifted low. The operator adjusted the range down one position with no immediate reaction. At 1844, a spike on IRM 'G' caused a half scram on Reactor Protection System (RPS) 'A' trip system. The half scram was being reset after evaluating no trip condition was present. As the operator reset groups 2 and 3, a trip signal from IRM 'F' was received on the RPS 'B' trip system, resulting in rod insertion for groups 1 and 4. When the operator identified multiple rods inserting, the actions of procedure 2-AOI-100-1 were followed and a manual scram was inserted. Investigation is ongoing. All safety systems remained in standby readiness configuration. No Emergency Core Cooling System (ECCS) or Reactor Core Isolation Cooling (RCIC) reactor water level initiation set points were reached. Primary Containment Isolations Systems did not receive an actuation signal and performed as designed. This event is reportable within 4 hours per 10 CFR 50.72(b)(2)(iv)(B) 'any event or condition that results in actuation of the RPS when the reactor is critical except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation.' It is also reportable within 8 hours per 10 CFR 50.72(b)(3)(iv)(A) 'any event or condition that results in valid actuation of systems listed in paragraph (b)(3)(iv)(B) Reactor Protection System(RPS) including reactor scram and reactor trip'. This event requires an LER within 60 days per 10 CFR 50.73(a)(2)(iv)(A). The NRC Resident Inspector has been notified.
ENS 52645	31 January 2017 19:25:00	10 CFR 50.73(a)(1), Submit an LER	60-Day Report Due to Invalid Eccs Actuation Signal	The following report is made pursuant to 10 CFR 50.73(a)(2)(iv)(A) due to an unintended initiation signal that occurred on January 31, 2017 with James A. FitzPatrick Nuclear Power Plant (JAF) in Mode 5 at zero (0) percent power. On January 31, 2017 at 1425 (EST) the control room received multiple annunciations associated with the following Systems / Trains: Primary Containment Isolation System (PCIS) / Trains A and B Residual Heat Removal System (RHR) / Trains A and B Core Spray (CS) / Trains A and B Reactor Core Isolation Cooling (RCIC) All four (4) Emergency Diesel Generators (EDG) auto-started with their associated Emergency Service Water pumps operating. RHR and CS both received initiation signals but were defeated per procedure. The HPCI (High Pressure Coolant Injection) auxiliary oil pump was taken to Pull-to-Lock per procedure, and the RCIC steam isolation valve cycled until the breaker was opened to close the valve. An evaluation concluded that the (Emergency Core Cooling System - ECCS) initiation signals were caused by the opening of a portable job box that was stored near sensitive equipment. Upon opening the job box, the lid bumped a reference leg resulting in the initiation signals. All initiation signals were reset and systems restored to normal shutdown lineups. The licensee notified the NRC Resident Inspector. * * UPDATE ON 3/30/17 AT 0840 EDT FROM DUSTIN SCURLOCK TO DONG PARK * * * To the original report, the licensee added, "This condition recurred at 1624 (EDT on 1/31/17). The licensee notified the NRC Resident Inspector. Notified R1DO (Cook).
ENS 52643	27 March 2017 22:25:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Hpci Declared Inoperable Due to Inadvertent Isolation	On March 27, 2017, at 1825 hours EDT, with the reactor at 100 percent core thermal power and steady state conditions, technicians inadvertently caused a High Pressure Coolant Injection (HPCI) System isolation, by testing the incorrect temperature switches in the TIP (Traversing In-core Probe) room. Pilgrim Nuclear Power Station (PNPS) was performing testing on the temperature switches for Reactor Core Isolation Cooling (RCIC), but the HPCI temperature switches were inadvertently actuated causing HPCI to isolate. The Limiting Condition for Operation (LCO) Action Statement 3.5.c.2 has been entered and the planned testing has been secured pending further investigation. PNPS is providing an 8-hour non-emergency notification that the HPCI System was declared inoperable in accordance with 10 CFR 50.72(b)(3)(v)(D), an event or condition that could have prevented fulfillment of a safety function needed to mitigate the consequences of an accident. HPCI was returned to Operable within 40 minutes. The licensee notified the NRC Resident Inspector and the Commonwealth of Massachusetts.
ENS 52543	8 February 2017 16:51:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Coolant Injection System Inoperable Due to Degraded Dc to Ac Inverter	During a control room panel walk down by an on-shift Reactor Operator at approximately 1151 (EST) on 2/8/2017, Unit 1 High Pressure Coolant Injection (HPCI) suction and discharge pressure indicators were noted to be downscale. I & C investigated and found the output of 1E41K603, DC to AC inverter, degraded. This inverter also powers the HPCI flow controller. Without the flow controller HPCI would not auto-start to mitigate the consequences of an accident, thus HPCI was declared inoperable. All other emergency core cooling systems and the Reactor Core Isolation Cooling (RCIC) system remain operable. HPCI is a single train system with no redundant equipment in the same system, thus this failure is reportable as an event or condition that could have prevented fulfillment of a safety function needed to mitigate the consequences of an accident, 10CFR50.72(b)(3)(v)(D). Inverter 1E41K603 was replaced and functionally tested satisfactorily at 1630 on 2/8/2017, restoring HPCI to operable status. The NRC Resident Inspector was notified.
ENS 52442	18 December 2016 19:24:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge	Automatic Scram Due to Load Reject from Substation	On December 18, 2016 at time 1124 PST the plant experienced a full reactor scram. Preliminary investigations indicate that the scram was caused by a load reject from the Bonneville Power Administration (BPA) Ashe substation. Further investigations continue. The following conditions have occurred: Turbine Governor valve closure Reactor high pressure trip +13 inches reactor water level activations E-TR-B (backup transformer) supplying E-SM-7/SM-8 (vital power electrical busses) Complete loss of Reactor Closed Cooling (RCC) E-TR-S (Startup transformer) supplying SM-1/2/3 (non-vital power electrical busses) E-DG-1/2/3 (emergency diesel generators) auto start Low Pressure Core Spray (LPCS) and Residual Heat Removal (RHR) A/B/C initiation signals Main Steam Isolation Valves (MSIV) are closed Reactor Core Isolation Cooling (RCIC) RCIC and High Pressure Core Spray (HPCS) were manually activated and utilized to inject and maintain reactor water level. Pressure control is with Safety Relief Valves (SRV) in, manual. Level control is with RCIC and Control Rod Drive (CRD). RCIC has experienced an over speed trip that was reset so that level control could be maintained by RCIC. This event is being reported under the following: 10 CFR 50.72(b)(2)(iv)(A) which requires a 4 hour notification for Emergency Core Cooling System (ECCS) discharge into the reactor coolant system. 10 CFR 50.72(b)(2)(iv)(B) which requires a 4 hour notification for any event or condition that results in actuation of the Reactor Protection System (RPS) when the reactor is critical. 10 CFR 50.72(b)(3)(iv)(A) which requires an 8 hours notification for actuation of ECCS systems. All control rods fully inserted. The NRC Resident Inspector has been informed. The licensee indicated that no increase in radiation levels were detected.
ENS 52419	9 December 2016 03:37:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Hpci Surveillance Failure	On 12/08/16 at approximately 2237 (EST), the Unit 2 HPCI (High Pressure Coolant Injection) system failed to meet surveillance testing requirements for achieving rated flow at greater than or equal to a minimum test pressure established per the surveillance. Operations declared the HPCI system inoperable and entered Technical Specification 3.5.1 Condition C for HPCI being inoperable. Other standby systems (Reactor Core Isolation Cooling and low pressure emergency core cooling systems) are operable. HPCI is a single train system. Therefore, per NUREG-1022, this condition is being reported pursuant to 10 CFR 50.72(b)(3)(v)(D) as a condition that could have prevented the fulfillment of the safety function of a system required to mitigate the consequences of a design event. This condition has been entered into the Corrective Action program (IR 3951006). Investigation of the exact failure condition is in progress so that repairs can be made. At the surveillance flow of 5,000 gpm, the system was approximately 80 psi below the required pressure of 1,278 psi. Technical Specification 3.5.1, Condition C, is a 14-day Limiting Condition of Operation. The NRC Resident Inspector will be notified. * * RETRACTION AT 1440 EST ON 01/19/17 FROM ELMER KAUFFMAN TO S. SANDIN * * * The licensee provided the following information as the basis for retracting this report: This is a retraction of an event notification made on 12/09/16 at 0529 EST (EN #52419). This event was initially reported pursuant to 10 CFR 50.72(b)(3)(v)(D) as a condition that, at the time of discovery, was believed to have prevented the fulfillment of the High Pressure Coolant Injection (HPCI) system safety function. On 12/08/16 at 2237 EST, the Unit 2 HPCI system was declared inoperable due to failing to meet surveillance testing requirements for achieving rated flow at greater than or equal to a minimum test pressure established per the surveillance. Prompt troubleshooting was performed and it was determined that an adjustment to the HPCI turbine governor control system was required. This adjustment was performed and HPCI was returned to an operable status on 12/09/16. Subsequent to this occurrence, Engineering has completed an evaluation that concluded that HPCI was capable of fulfilling its safety function and that the associated Technical Specification (TS) Surveillance Requirement (SR) 3.5.1.8 was met. The evaluation concluded that HPCI was degraded, but met the threshold for TS operability. The NRC Senior Resident has been informed of this retraction." Notified R1DO (Kennedy).
ENS 52334	31 October 2016 07:39:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Coolant Injection (Hpci) Inoperable	On October 31, 2016, at 0239 hours (CDT), a defect (minor audible through-wall leak) was identified on the steam line drain valve 1-2301-55, HPCI Steam Line Drain Line Steam Trap Outlet Valve. The defect was identified by Operations personnel traversing through the HPCI room as part of normal rounds. HPCI was declared inoperable under Tech Specs 3.5.1, Condition G. The Reactor Core Isolation Cooling (RCIC) system was verified operable. HPCI remains available (but not operable). The leak has been isolated. The 1-2301-55 is a manual valve downstream of the HPCI steam line drain trap. In a standby line-up, this line drains condensation from the HPCI steam supply line to the main condenser. During operation in an accident scenario, this line drains condensation from the HPCI steam supply line to the Torus via a drain pot. The location of the defect is in class 2 safety related piping. HPCI is a single train safety system and this notification is being made in accordance with 10CFR50.72(b)(3)(v)(D). The NRC Resident Inspector has been notified. Technical Specification 3.5.1, condition G requires that HPCI be Operable within 14 days. * * RETRACTION ON 12/05/2016 AT 1505 EST FROM MARK BRIDGES TO STEVEN VITTO * * * The purpose of this notification is to retract the ENS Report made on October 31, 2016, at 0239 hours CDT (ENS Report #52334). Upon further investigation, a pinhole through-wall leak was discovered in the body of the 1-2301-55 valve (HPCI Steam Line Drain Line Steam Trap Outlet Valve). The defect was characterized as a 1/32-inch rounded hole due to a manufacturing defect in the casting located on the downstream side of the valve near the piping connection. A subsequent evaluation performed by Quad Cities Station considering the defect size, location, and characterization, confirmed the Unit 1 High Pressure Coolant Injection (HPCI) system would have performed its safety function when required. Based on this subsequent evaluation, ENS Report 52334 is being retracted. Note: On November 1, 2016, at 1624 hours CDT, the 1-2301-55 valve (HPCI Steam Line Drain Line Steam Trap Outlet Valve) was successfully repaired and HPCI was returned to Operable status. The NRC Resident Inspector has been notified. Notified R3DO (Stone).
ENS 52264	26 September 2016 22:45:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Coolant Injection System Declared Inoperable	On 9/26/16 at approximately 1845 EDT, investigation of an identified water leak on one of the two Unit 3 HPCI turbine exhaust drains to the drain pot determined that there was through wall leakage of approximately 2 drops per minute. Operations promptly declared the HPCI system inoperable and entered Technical Specification 3.5.1 Condition C for HPCI being inoperable. Other standby systems (Reactor Core Isolation Cooling and low pressure emergency core cooling systems) are operable. HPCI is a single train system. Therefore, per NUREG-1022, this condition is being reported pursuant to 10 CFR 50.72(b)(3)(v)(D) as a condition that could have prevented the fulfillment of the safety function of a system required to mitigate the consequences of a design event. This condition has been entered into the corrective action program (IR 2720241). Investigation of the exact flaw location is in progress so that repairs can be made. The NRC resident has been informed of this notification.
ENS 52159	7 August 2016 05:01:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Coolant Injection System Declared Inoperable	HPCI (high pressure coolant injection) governor valve did not respond as expected. During performance of a planned HPCI valve functional test the HPCI governor valve (FD-FV-4879) did not reposition as expected. The HCPI system has been declared inoperable based on the response per Technical Specification 3.5.1 action C.1. All other emergency core cooling systems and the reactor core isolation cooling (RCIC) system remain operable. The unit remains at 100% power. The station has initiated an event response team to identify and correct the cause of the failure. No personnel injuries resulted from the event. The licensee notified the NRC Resident Inspector and the Lower Alloways Creek Dispatch.
ENS 52064	5 July 2016 20:40:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Coolant Injection (Hpci) System Declared Inoperable	On July 5, 2016, at 1640 Eastern Daylight Savings Time (EDT) the Unit 2 HPCI system was declared inoperable due to apparent failure of the HPCI Auxiliary Oil Pump after the 'HPCI Aux Oil Pump Motor Overload' control room annunciator was received. Failure of the HPCI Auxiliary Oil Pump prevents the HPCI system from performing its design safety function. As such, this event is being reported in accordance with 10 CFR 50.72(b)(3)(v)(D) as a condition that at the time of discovery could have prevented the fulfillment of the safety function of a system that is needed to mitigate the consequences of an accident. This event did not result in any adverse impact to the health and safety of the public. The NRC Senior Resident Inspector has been notified. The safety significance of this condition is minimal. All other Emergency Core Cooling Systems and the Reactor Core Isolation Cooling (RCIC) system remain operable. Troubleshooting activities are in progress. The HPCI system will remain inoperable until the cause of the failure has been corrected.
ENS 51715	7 February 2016 18:26:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(a)(1)(i), Emergency Class Declaration 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Manual Scram and Alert Declaration Due to Electrical Fault Resulting in Fire/Explosion	At 1346 EST the licensee reported that at 1326, Brunswick Unit 1 declared an Alert under EAL HA 2.1 due to an explosion/fire in the Balance of Plant 4 kV switchgear bus area. Prior to the Alert declaration, the operators initiated a manual SCRAM due to an unexpected power decrease from 88% to 40%. The licensee has visually verified that there is no ongoing fire and is investigating the initial cause of the event. Offsite power is available to the site, but EDGs 1 and 2 are running and supplying Unit 1 loads. The MSIVs shut and HPCI/RCIC are being used to maintain vessel level. At 1412 EST, NRC decided to remain in Normal Mode. At 1704 EST the licensee reported the following: At 1313 hours Eastern Standard Time (EST) a manual reactor scram was initiated due to loss of both recirculation system variable speed drives as a result of an electrical fault. At this time, a Startup Auxiliary Transformer (SAT) experienced a lockout fault; interrupting offsite power to emergency buses 1 and 2. Emergency Diesel Generators (EDGs) 1, 2, 3, and 4 automatically started and EDGs 1 and 2 synchronized to emergency buses 1 and 2 per design. The power interruption resulted in closure of the Main Steam Isolation Valves, per design. The manual scram also resulted in closure of Group 2, 6, and 6 Containment Isolation Valves. The Reactor Core Isolation Cooling (RCIC) system was manually started and is being used to control reactor water level. The High Pressure Coolant Injection (HPCI) system was manually started and is being used for pressure control. The Plant response to the event was per design. Unit 2 is not directly affected by the event, however, due to the shared electrical distribution system is in a Technical Specification Action statement due to the Inoperable Unit 1 SAT. The public health and safety is not impacted by this event. At 1751 EST, the licensee reported that the emergency declaration had been downgraded to an Unusual Event at 1730 because the plant no longer meets the criteria for an Alert, but does meet the criteria for an Unusual Event due to a "loss of all offsite power to Emergency 4 kV buses E1 (E3) and E2 (E4) for greater than or equal to 15 minutes." The NRC Resident Inspector has been notified. The licensee has notified the State and Local governments. Notified DHS, FEMA, USDA, HHS, DOE, DHS NICC, EPA EOC, FEMA NWC (via email), FDA EOC (via email) and Nuclear SSA (via email). * * UPDATE FROM MARTY IRWIN TO DANIEL MILLS AT 1825 ON 2/07/16 * * * At 1814 EST the emergency declaration was terminated because offsite power was restored. The NRC Resident Inspector has been notified. The licensee has notified the State and Local governments. Notified R2DO (Musser), NRR EO (Morris), IRD MOC (Stapleton), R2RA (Haney), NRR ET (Lubinski), NRR ET (Dean), DHS, FEMA, USDA, HHS, DOE, DHS NICC, EPA EOC, FEMA NWC (via email), FDA EOC (via email) and Nuclear SSA (via email).
ENS 51630	31 December 2015 11:30:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Coolant Injection Inoperable	On 12/31/15, at approximately 0630 hours (EST), during shift turnover panel walk-downs, a licensed Unit 3 reactor operator identified that the High Pressure Coolant Injection (HPCI) flow controller output indicated a downscale condition. The controller was in automatic with the set point at 5000 gpm, which would typically indicate a controller output value of 100%. HPCI was not in operation and is a standby system. Operations promptly declared the HPCI system inoperable and entered Technical Specification Condition C for HPCI being inoperable. Other standby systems (Reactor Core Isolation Cooling and low pressure emergency core cooling systems) are OPERABLE. HPCI is a single train system. Therefore, per NUREG-1022, this condition is being reported pursuant to 10 CFR 50.72(b)(3)(v)(D) as a condition that could have prevented the fulfillment of the safety function of a system required to mitigate the consequences of a design event. This condition has been entered into the Corrective Action program (IR 2606215). Maintenance troubleshooting of the flow controller loop has identified a failed component and repair activities are in progress. The NRC Resident Inspector has been informed of this notification.
ENS 51391	14 September 2015 03:05:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(3)(v)(C), Loss of Safety Function - Release of Radioactive Material	Manual Scram Due to Loss of Turbine Building Closed Cooling Water	At 2305 EDT on September 13, 2015, a manual scram was initiated in response to a loss of all Turbine Building Closed Cooling Water (TBCCW). All control rods fully inserted. The lowest Reactor Water Level (RWL) reached was 137 inches. All isolations and actuations for RWL 3 occurred as expected. Decay heat was initially being removed through the Main Turbine Bypass System to the Main Condenser, however, as a result of the loss of TBCCW, the Main Feed Pumps lost cooling and had to be secured. At 2310, Standby Feedwater was initiated and Main Feedwater was secured. The loss of TBCCW also caused all Station Air Compressors (SACs) to trip on loss of cooling. The loss of SACs caused the Instrument Air header pressure to degrade to the point at which the Secondary Containment isolation dampers drifted closed. This resulted in the Reactor Building vacuum exceeding the Technical Specification limit. At 2325, operators started the Standby Gas Treatment system and manually initiated a Secondary Containment isolation signal. Secondary Containment vacuum was promptly restored to within Technical Specification limits. Additionally, Operators were monitoring for expected MSIV drift due to the degraded Instrument Air header pressure. When outboard MSIVs were observed to be drifting, Operators closed the outboard and inboard MSIVs at 2345. At 2352, Safety Relief Valves (SRVs) reached the Low-Low Setpoint and began cycling to control reactor pressure. RWL is currently being maintained in the normal level band with the Standby Feedwater and Control Rod Drive systems. Reactor Pressure is being controlled with Safety Relief Valves. Operators are currently in the Emergency Operating Procedure for Reactor Pressure Vessel control. Investigation into the loss of TBCCW continues. No safety-related equipment was out of service at the time of the event. All offsite power sources were adequate and available throughout the duration of the event. The NRC resident inspector has been notified. * * UPDATE AT 0555 EDT AT 09/14/15 FROM CHRIS ROBINSON TO JEFF HERRERA * * * At 0409 EDT the Reactor Core Isolation Cooling (RCIC) system was placed in service due to identification of an unisolable leak in the Standby Feedwater System. Reactor water level and pressure is now being controlled though the RCIC system and Safety Relief Valves. This event update is reportable as a valid manual initiation of a specified safety system under 10CFR50.72(b)(3)(iv)(A). The NRC resident inspector has been notified. The leak rate was reported as approximately 5-10 gallons per minute from a weld on the standby feedwater pump header drain valve F326. The licensee reported the leak stopped once RCIC was placed into service. The licensee is still investigating the issue. Notified the R3DO (Pelke), IRD Manager (Grant), NRR EO (Morris). * * UPDATE PROVIDED BY CHRIS ROBINSON TO JEFF ROTTON AT 2135 EDT ON 09/14/2015 * * * At 1847 EDT on September 14, 2015, a valid automatic Reactor Protection System (RPS) actuation occurred due to Reactor Water Level 3 while shutdown in MODE 3. Operators were manually controlling Reactor Pressure Vessel (RPV) level and pressure with Reactor Core Isolation Cooling (RCIC) and Safety Relief Valves (SRV). While operators were cycling SRVs, the RPV level went below the Level 3 setpoint. Operators promptly restored RPV level by manual operation of RCIC. The Level 3 actuation and associated isolations were verified to operate properly. The scram signal has been reset. Fermi 2 remains in MODE 3 controlling RPV Level and Pressure through manual operation of RCIC and SRVs. This is the second occurrence of a valid specified safety system actuation reportable under 10CFR50.72(b)(3)(iv)(A) for this ongoing event. The NRC Resident Inspector has been notified. Notified R3DO (Riemer), IRD Manager (Grant), and NRR EO (Morris) * * UPDATE FROM BRETT JEBBIA TO JOHN SHOEMAKER AT 1446 EST ON 2/27/16 * * * This update provides clarification of the applicable reporting criteria for this Event associated with primary containment isolation actuations. Upon the manual reactor scram at 2305 EDT on September 13, 2015, Reactor Protection System (RPS) Level 3 actuated and Primary Containment Isolation System (PCIS) Groups 4, 13 and 15 actuated as expected. The applicable reporting criterion for these actuations is 10 CFR 50.72(b)(3)(iv)(A). The applicable reporting criterion for the manual closure of the inboard and outboard main steam isolation valves at 2345 EDT on September 13, 2015, is also 10 CFR 50.72(b)(3)(iv)(A). In addition, the manual closures of all MSIV lead to a loss of condenser vacuum which resulted in the actuation of PCIS Group 1 at 0001 EDT on September 14, 2015, as expected. The applicable reporting criterion for this actuation is also 10 CFR 50.72(b)(3)(iv)(A). Upon reaching Level 3 at 1847 EDT on September 14, 2015, PCIS Groups 4, 13 and 15 actuated as expected. The applicable reporting criterion for this actuation is 10 CFR 50.72(b)(3)(iv)(A). The licensee informed the NRC Resident Inspector. Notified the R3DO (Stone).
ENS 50956	5 April 2015 19:37:00	10 CFR 50.72(a)(1)(i), Emergency Class Declaration	Alert Declared Due to Fire in Motor Control Center	An Alert was declared due to a fire in a Unit 2 Division 2 Safeguard (250 volt) DC Motor Control Center. This has made the High Pressure Core Injection system inoperable and unavailable. The fire is out. The emergency response organization has been activated and investigation / repair planning will commence. Unit 2 is stable with no other system affects. The fire was extinguished by on-site personnel. No off-site responders were required. The Reactor Core Isolation Cooling system remains operable. A Fire Watch has been stationed to monitor for fire reflash. There were no injuries resulting from this event. There was no effect on Unit 1. The licensee notified the NRC Resident Inspector and State and local government agencies. Notified the following organizations: DHS SWO, DOE Ops Center, FEMA Ops Center, HHS Ops Center, NICC Watch Officer, USDA Ops Center, EPA EOC, FDA EOC, FEMA NWC, and Nuclear SSA. * * UPDATE FROM DAN BOYLAN TO DONALD NORWOOD AT 1812 EDT ON 04/05/15 * * * The Alert was terminated at 1742 EDT. The licensee notified the NRC Resident Inspector and State and local government agencies. Notified R1DO (Kennedy), IRD (Gott), and NRR EO (Morris). Notified the following organizations: DHS SWO, DOE Ops Center, FEMA Ops Center, HHS Ops Center, NICC Watch Officer, USDA Ops Center, EPA EOC, FDA EOC, FEMA NWC, and Nuclear SSA.
ENS 50816	12 February 2015 18:36:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Hpci Declared Inoperable During Weekly Inspection	EVENT DESCRIPTION: On February 12, 2015, at 1336 Eastern Standard Time (EST) the Unit 1 High Pressure Coolant Injection (HPCI) system was declared inoperable due to a failure of the HPCI Auxiliary Oil Pump. During performance of a routine HPCI weekly inspection, the auxiliary oil pump was started and subsequently experienced a loss of discharge oil pressure. The HPCI Auxiliary Oil Pump provides hydraulic pressure required to open the HPCI Turbine Stop Valve and the HPCI Turbine Control Valve during initial HPCI startup. Failure of the HPCI Auxiliary Oil Pump prevents the HPCI system from performing its design safety function. As such, this event is being reported in accordance with 10 CFR 50.72(b)(3)(v)(D) as a condition that at the time of discovery could have prevented the fulfillment of the safety function of a system that is needed to mitigate the consequences of an accident. This event did not result in any adverse impact to the health and safety of the public. INITIAL SAFETY SIGNIFICANCE EVALUATION: The safety significance of this condition is minimal. All other Emergency Core Cooling Systems and the Reactor Core Isolation Cooling (RCIC) system remain operable (per the requirements of 14-day LCO (Limiting Condition of Operation) 3.5.1). CORRECTIVE ACTIONS: Troubleshooting activities are in progress. The HPCI system will remain inoperable until the cause of the failure has been corrected. The NRC Resident Inspector has been notified.
ENS 50771	27 January 2015 14:48:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Loss of High Pressure Coolant Injection	On Tuesday, January 27, 2015, at 0948 EST, with the Reactor Mode Select Switch (RMSS) in the Shutdown position and Pilgrim Nuclear Power Station (PNPS) at 0% core thermal power, the High Pressure Coolant Injection (HPCI) system was isolated by the main control room operating crew and declared INOPERABLE. HPCI had been in service for reactor pressure control following the automatic reactor scram experienced during winter storm 'Juno' reported in EN# 50769. It appears there was a malfunction of the HPCI turbine gland seal condenser blower or associated condensate pump. Reactor pressure control was transitioned to the safety relief valves and the reactor cooldown was continued. The plant is stable. The Emergency Diesel Generators are powering the safety related 4KV buses and reactor water level is being maintained by the Reactor Core Isolation Cooling (RCIC) system. HPCI is required to be OPERABLE in accordance with Technical Specification 3.5.C.1. Since HPCI is a single train system, the INOPERABILITY is reportable in accordance with 10CFR50.72(b)(3)(v)(D). The cause of the HPCI malfunction is not known at this time and troubleshooting continues. This event had no impact on the health and/or safety of the public. The USNRC Senior Resident Inspector has been notified. Shutdown cooling is in service.
ENS 50769	27 January 2015 09:02:00	10 CFR 50.72(b)(2)(xi), Notification to Government Agency or News Release 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Automatic Reactor Scram on Turbine Trip Due to Loss of Offsite Power	On Tuesday January 27, 2015 at 0402 hours, with the Pilgrim Nuclear Power Station (PNPS) Reactor Mode Select Switch (RMSS) in Run and reactor power approximately 52% an automatic reactor scram signal was received due to the automatic trip of the main turbine that was initiated by the opening of the main generator breaker, ACB-104. The event occurred during winter storm 'Juno.' Prior to the event off-site transmission Line 355 was de-energized due (to) weather conditions and its associated PNPS switchyard breakers (ACB-105, a main generator breaker and ACB-102), were open. Per station procedures, reactor power was being lowered, a reactor protection system bus had been placed onto a back-up power supply, the Emergency Diesel Generators had been started and were powering the associated safety related 4 KV buses. The second off-site transmission Line 342 de-energized and the associated PNPS switchyard breakers (ACB-104 main generator breaker and ACB-103) opened. The Shutdown Transformer off-site power supply has remained available throughout this event. All control rods were verified to be fully inserted. Per plant design, Primary Containment Isolation System (PCIS) Group lI sampling systems, Group VI Reactor Water Clean-up (RWCU) system and Reactor Building Isolation System (RBIS) isolations occurred. Currently, the EDG's are powering the safety related 4KV buses, reactor water level is being maintained by the Reactor Core Isolation Cooling (RCIC) system and reactor pressure is being maintained by High Pressure Coolant Injection (HPCI) system. The station is conducting a plant cool down at this time. All systems responded as designed with the exception of a non-safety-related diesel air compressor, K-117 that failed to start. The licensee will notify the State and local governments and plans on issuing a press release. The NRC Resident Inspector has been informed.
ENS 50675	12 December 2014 21:00:00	10 CFR 50.72(b)(3)(ii)(B), Unanalyzed Condition	Unanalyzed Condition with Reactor Core Isolation Cooling	Engineering identified fuse and breaker coordination issues with Reactor Core Isolation Cooling (RCIC) valves operated at the Remote Shutdown Panel (RSDP). The coordination issues are such that, given a fire in the main control room, it is possible that RCIC valve power supply breakers could trip prior to tripping control power fuses. Operation of RCIC from the RSDP could be impaired in this scenario without compensatory actions to reset breakers. RCIC is the single credited source of makeup to the reactor pressure vessel during this scenario. The current licensing basis (Fire Protection Report) does not identify the compensatory actions required to reset breakers prior to RCIC operation at the RSDP. This condition is applicable to Unit 1 and Unit 2. This report is being made pursuant to 10CFR50.72(b)(3)(ii)(B), 'Event or Condition that results in an unanalyzed condition that significantly degrades plant safety'. Actions are being taken to amend the appropriate operating procedures to take the required steps to ensure proper operation of RCIC in the postulated scenario. The licensee has notified the NRC Resident Inspector.
ENS 50601	7 November 2014 13:47:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge	Automatic Reactor Scram Due to Loss of Feedwater	The Perry Nuclear Power Plant experienced an automatic reactor scram due to a loss of feedwater, which resulted in receiving valid reactor vessel water Level 3 and Level 2 initiation signals. The High Pressure Core Spray system and the Reactor Core Isolation Cooling system started and injected. Reactor water level and pressure have been stabilized in the required bands. The motor feed pump automatically started and is being used to control reactor vessel water level. The High Pressure Core Spray and Reactor Core Isolation Cooling systems have been returned to the standby mode. As a result of receiving a reactor vessel water Level 2 signal a Balance of Plant containment isolation signal was received. All systems isolated as required and the plant is restoring isolated systems in accordance with plant procedures. During the scram, all rods fully inserted into the core. Decay heat is being removed via turbine bypass valves to the main condenser. The electrical grid is stable and is supplying plant loads. An emergency diesel generator (Division 3 High Pressure Core Spray) started, as designed, as a result of the reactor vessel water Level 2 signal. No safety relief valves lifted as a result of the transient. The plant is stable with cooldown and depressurization to Mode 4 in progress. The cause of the loss of feedwater is under investigation. The NRC Resident Inspector has been notified. The State of Ohio and local officials will be notified.
ENS 50551	20 October 2014 06:18:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge	Automatic Reactor Scram on Loss of Feedwater	The Perry Power Plant experienced a reactor scram during a shift of non-essential vital power supply to the alternate source. Feedwater was lost resulting in receiving a valid level 3 and level 2 signal. High Pressure Core Spray and Reactor Core Isolation Cooling started and injected. Reactor level and pressure have been stabilized to required bands. The motor feed pump has been started and is controlling level. High Pressure Core Spray and Reactor Core Isolation Cooling have been returned to standby. During the scram, all rods fully inserted into the core. Decay heat is being removed via the steam dumps to the condenser. The electrical grid is stable and supplying plant loads. An emergency diesel generator started, as designed, as a result of the level 2 signal but did not load. No safety valves lifted as a result of the transient. The cause of the loss of feedwater is under investigation. The licensee will be notifying the State of Ohio and Perry Township and has notified the NRC Resident Inspector. * * UPDATE FROM DOUG SHORTER TO HOWIE CROUCH AT 0933 EDT ON 10/20/14 * * * The plant is currently in Mode 3, stable with cooldown and depressurization to Mode 4 in progress. Level control is being provided by the motor feedwater pump. Troubleshooting of the cause of the scram and loss of feed water is on-going. The initial notification identified 10CFR50.72(b)(3)(iv)(A), 'Specified System Actuation', as a reporting criteria. The specific system that actuated was not provided. As a result of receiving a reactor vessel water level 2 signal a containment/BOP isolation signal was received. All systems isolated as required and the plant is restoring isolated systems in accordance with procedure. The licensee will be notifying the State of Ohio and Perry Township and has notified the NRC Resident Inspector. Notified R3DO (Pelke).
ENS 50546	17 October 2014 08:03:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Automatic Reactor Scram on High Average Power Range Monitor Flux	At 0303 (CDT), River Bend Nuclear Station sustained a reactor scram due to high Average Power Range Monitor (APRM) flux, suspected due to a malfunction of the Electrohydraulic Control System. Reactor recirculation pump 'B' tripped, reactor recirculation pump 'A' responded appropriately. All other systems responded appropriately except for loss of feed water due to low suction pressure trip from isolating the condensate demineralizers. Reactor water level did not get out of level band. Condensate demineralizers and feedwater were restored to service. Level 3 (isolation) was initiated due to scram. (One) system, Suppression Pool Cooling isolated accordingly due to level 3 signal. Currently the plant is in mode 3, hot shutdown. Plant will remain in mode 3 until investigation of scram is complete. During the scram, all rods inserted into the core. No relief valves lifted as a result of the transient. All safety equipment is available although reactor core isolation cooling is functional but inoperable due to an earlier issue discovered during a surveillance test. The reactor is at normal pressure and temperature for Mode 3. The cause of the high APRM flux and the identified anomalies are under investigation. The licensee has notified the NRC Resident Inspector. * * UPDATE FROM DANIEL PIPKIN TO DANIEL MILLS AT 1043 EDT ON 10/17/2014 * * * The licensee is updating the notification to include an 8 hour notification for a specified system actuation due to the Level 3 isolation signal. Licensee is proceeding to cold shutdown to troubleshoot the EHC system. The licensee will notify the NRC Resident Inspector. Notified R4DO (Haire).
ENS 50404	26 August 2014 22:30:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Turbine Generator Neutral Overvoltage Causes a Reactor Scram	At 1730 CDT on August 26, 2014, Browns Ferry Unit 1 experienced a turbine trip resulting in an automatic reactor scram. The cause of the turbine trip was a control valve fast closure signal that was generated by a turbine trip on generator neutral over voltage signal. The Main Steam Isolation Valves (MSIVs) remained open with the main turbine bypass valves controlling reactor pressure. The Reactor Feedwater Pumps are in service to control reactor water level. Primary Containment Isolation Systems (PCIS) Groups 2, 3, 6, and 8 isolation signals were received. Upon receipt of these signals, all required components actuated as required with the exception of Standby Gas Treatment (SBGT) train A, which is under a clearance for planned maintenance. Neither High Pressure Coolant Injection (HPCI) nor Reactor Core Isolation Cooling (RCIC) initiation signals were received. Initially, three Main Steam Relief Valves (MSRVs) opened to control the pressure surge and subsequently reclosed. This event requires a 4 hour report per 10 CFR 50.72(b)(2)(iv)(B), 'Any event or condition that results in actuation of the reactor protection system (RPS) when the reactor is critical except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation.' This event also requires an 8 hour report per 10 CFR 50.72(b)(3)(iv)(A), 'Any event or condition that results in valid actuation of any of the systems listed in paragraph (b)(3)(iv)(B), (1) Reactor protection system (RPS) including reactor scram or reactor trip, and (2) General containment Isolation signals affecting containment isolation valves in more than one system or multiple main steam isolation valves (MSIVs).' The NRC Resident Inspector has been notified. Service Request 926468 was initiated in the Corrective Action Program. The plant is in its normal shutdown electrical lineup. The licensee is investigating the cause of the generator neutral overvoltage signal. There was no impact on units 2 and 3.
ENS 50346	5 August 2014 22:34:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Automatic Reactor Scram	This notification is being provided pursuant with SAF 1.6 10CFR50.72(b)(2)(iv)(B) and SAF 1.7 10CFR50.72(b)(3)(iv)(A). At 1734 CDT on August 5, 2014, LaSalle Unit 2 automatically scrammed due to an RPS actuation. The MSIVs isolated on a Group 1 signal, the cause is under investigation. The reactor water cleanup system isolated during the transient. The plant is stable with Reactor Pressure Control being maintained by the Reactor Core Isolation Cooling System and SRVs and level being controlled by the Low Pressure Core Spray System. The plant is planned to remain in hot shutdown pending investigation of the trip." The Unit 2 electric plant is in a normal shutdown lineup. All control rods inserted fully on the scram. Unit 1 was not affected by the Unit 2 transient. The licensee notified the NRC Resident Inspector. * * UPDATE PROVIDED BY MICHAEL FITZPATRICK TO JEFF ROTTON AT 1650 EDT ON 8/6/2014 * * * The initial notification to the NRC stated that the reactor water cleanup system had isolated during the transient. The actual status is being corrected to state that the reactor water cleanup pump tripped during the transient. The licensee has notified the NRC Resident Inspector. Notified R3DO (Stone).
ENS 50210	18 June 2014 19:45:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Loss of Hpci Room Cooling	At 1545 (EDT), while testing of the Emergency Service Water system (ST-8Q) was being performed at the James A. FitzPatrick Nuclear Power Plant (JAF), two of five unit coolers (66UC-22H and 66UC-22K) in the East Crescent were found with indicated flow of 0 gpm. The other three unit coolers in the East Crescent Area were found with sufficient flow. At least four unit coolers are required to support the functionality of the East Crescent Area Ventilation Subsystem (TRO 3.7.C). The East and West Crescent Area Ventilation Subsystems support the Operability of the Emergency Core Cooling Systems (ECCS) and Reactor Core Isolation Cooling (RCIC) system by removing heat from the areas, in the event that ECCS and RCIC were used to mitigate the consequences of an accident. The West Crescent Area Ventilation Subsystem remained functional. The accident mitigating function of the division of ECCS and RCIC located in the West Crescent Area were unaffected by this condition. However, this condition could have prevented the function of one division of the ECCS, including the single train of High Pressure Coolant Injection (HPCI), located in the East Crescent. Therefore, this condition could have prevented fulfillment of the safety function of HPCI and it is being reported under 10 CFR 50.72(b)(3)(v)(D). As part of the testing, the throttle valves to the unit coolers (66UC-22H and 66UC-22K) were cycled and normal flow was restored. This condition no longer exists. The licensee is investigating the loss of flow to the "H" and "K" unit coolers and the restoration of flow by cycling the unit cooler supply throttle valves. The licensee will be notifying the NRC Resident Inspector. * * RETRACTION FROM DAVID CALLEN TO DANIEL MILLS AT 1506 EDT ON 8/13/2014 * * * FitzPatrick is retracting EN # 50210 made on June 18, 2014 at 2120 EDT. The plant was at 86% power at the time. The ENS notification was an 8-Hr non-emergency notification to 10 CFR 50.72(b)(3)(v)(D) when it was discovered that two of five unit coolers in the East Crescent (66UC-22H and 66UC-22K) were found with indicated flow of 0 gpm while testing. The other three unit coolers in the East Crescent (66UC-22B, 66UC-22D, 66UC-22F) were found with sufficient flow. At least four unit coolers are required to support the functionality of the East Crescent Area Ventilation subsystem (TRO 3.7.C). The East and West Crescent Area Ventilation subsystems support the Operability of the Emergency Core Cooling Systems (ECCS) and Reactor Core Isolation Cooling (RCIC) system by removing heat from these areas in the event that ECCS and RCIC are used to mitigate the consequences of an accident. As part of testing, throttle valves to unit coolers 66UC-22H and 66UC-22K were cycled and normal flow was restored. The West Crescent Area Ventilation subsystem remained functional. The accident mitigating function of the division of the ECCS and RCIC located in the West Crescent Area were unaffected by this condition. Initial review of this condition determined that it could have prevented the function of one division of the ECCS, including the single train of High Pressure Coolant Injection (HPCI), located in the East Crescent. Therefore, this condition was initially reported under 10 CFR 50.72 (b)(3)(v)(D) as a condition that could have prevented fulfillment of the Safety function of HPCI. This EN# 50210 is being retracted based upon a subsequent engineering analysis that determined that there is reasonable assurance that the three unit coolers with sufficient flow (66UC-22B, 66UC-22D, and 66UC-22F) would have been capable of removing accident heat loads as a function of time to maintain East Crescent area temperatures at a value which ensures operability of supported equipment. The analysis considered unit cooler heat transfer capability at the modified design condition flow of 22 gpm for historically observed lake temperatures and for flow at tested conditions. Additional margin in flow at the tested condition provided increased heat removal capability and provided added assurance that accident heat load would have been removed. The East Crescent Area Ventilation subsystem was, therefore, functional with three unit coolers (functionality never was lost) and the supported ECCS remained Operable. The Operability determination for the condition has subsequently been revised based upon the engineering analysis, to state the condition was not immediately reportable per 10 CFR 50.72. The licensee has notified the NRC Resident Inspector Notified R1DO (Kennedy)
ENS 49928	19 March 2014 03:52:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Reactor Scram Due to Failure to Control Main Turbine Moisture Separator Level	At 2252 on 03/18/2014, the Unit 3 reactor automatically scrammed due to a turbine trip from a high Main Turbine moisture separator level. Initial indications show the level controller for 3B2 Moisture Separator failed to adequately maintain level. Additionally local manual control attempts failed to restore moisture separator level. Main Steam Isolation Valves remained open with main turbine bypass valves controlling reactor pressure. Reactor feedwater pumps are in service to control reactor water level. Primary Containment Isolation System Groups 2, 3, 6 and 8 containment isolation and initiation signals were received. Upon receipt of these signals all required components actuated as required. Neither High Pressure Coolant Injection nor Reactor Core Isolation Cooling initiation signals were received. The reactor had been operating near 35% power during scheduled power ascension. This event is reportable within 4 hours per 10CFR 50.72(b)(2)(iv)(B) 'any event or condition that results in actuation of the reactor protection system (RPS) when the reactor is critical except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation.' It is also reportable within 8 hours per 10CFR 50.72(b)(3)(iv)(A) and requires an LER within 60 days per 10CFR 50.73(a)(2)(iv)(A). NRC Resident Inspector has been notified.
ENS 49920	17 March 2014 10:14:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Manual Reactor Scram Due to Steam Leak in Low Pressure Turbine Line	On 3/17/2014 at 0514 (CDT) the reactor was manually scrammed from approximately 41% core thermal power due to a steam leak in the turbine building. All control rods fully inserted and all systems actuated and operated as designed. All Main Steam Isolation Valves were manually shut. The Reactor Core Isolation Cooling System was manually initiated to assist in level control and pressure control. No safety relief valves actuated automatically. Manual cycling of safety relief valves and Reactor Core Isolation Cooling are being used to maintain reactor water level and pressure within normal bands. Group 2 and 3 RHR isolation signals were received; however no valve movement occurred since the affected valves are normally closed. This event is reportable under 10CFR50.72(b)(2)(iv)(B) for the reactor trip and 50.72(b)(3)(iv)(A) for the manual start of the reactor core isolation cooling system. The licensee informed the NRC Resident Inspector.
ENS 49888	10 March 2014 20:28:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation	Reactor Scram Due to Actuation of the Alternate Rod Insertion System	At 1628 EDT Nine Mile Point (NMP) Unit 2 experienced an actuation of the Alternate Rod Insertion (ARI) system which resulted in a reactor scram. Coincident with the scram, the Reactor Core Isolation Cooling (RCIC) system initiated. Prior to the event, maintenance personnel were working in the vicinity of a reactor vessel level instrumentation rack and may have agitated the common drain line of the transmitters. A prompt investigation is underway to investigate the incident. The actuation signal for the RCIC system was invalid because reactor vessel level did not reach level two and the actuation was not in response to actual plant conditions or parameters. The reactor scram is reportable in accordance with 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 event has been entered into the NMP corrective action program as CR-2014-001963. The NRC Resident Inspector has been notified. The licensee has notified the State of New York. The reactor is shutdown with all rods inserted. Decay heat is being rejected to the condenser and reactor water level is being maintained by condensate, feedwater, reactor water clean up, and control rod drive systems.
ENS 49407	4 October 2013 01:45:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Unit 2 High Pressure Coolant Injection (Hpci) Inoperable Due to Drain Line Leak	On October 3, 2013, at 2045 (CDT) hours, a defect (pinhole through-wall leak) was identified on the drain line for the LS 2-2365, HPCI TURBINE INLET DRAIN POT LEVEL SWITCH. The defect was identified during investigation of leakage near LS 2-2365. The LS 2-2365, HPCI TURBINE INLET DRAIN POT LEVEL SWITCH, is provided to detect a failure of the HPCI steam trap during standby line-up. The location of the defect, is in Class 2 Safety related piping. HPCI is a single train safety system and this notification is being made in accordance with 10CFR50.72(b)(3)(v)(D). The instrument isolations for LS 2-2365 have been close and the leak has been isolated. There is no increase to plant risk and RCIC (Reactor Core Isolation Cooling) is available. The licensee will inform the NRC Resident Inspector. * * RETRACTION ON 11/7/13 AT 1412 EST FROM JEFFERY JACOBSON TO DONG PARK * * * The purpose of this notification is to retract the ENS report made on October 4, 2013, at 0212 EDT (ENS Report # 49407). Upon further investigation the pinhole through-wall leak discovered in the Unit 2 HPCI room was in a weld at a 'Tee' downstream of the Unit 2 HPCI turbine inlet drain pot level switch (LS 2-2365) on drain line 2-2386B-1-B. The defect was characterized as a 1/16-inch rounded hole due to gas porosity (with no evidence of cracking). A subsequent evaluation performed by Quad Cities Station considering the defect size, location, and characterization confirmed the Unit 2 High Pressure Coolant Injection (HPCI) system would have performed its safety function when required. Based on this subsequent evaluation, ENS Report # 49407 is being retracted. Note: On October 3, 2013, at 1155 CDT the Unit 2 HPCI drain line leak was isolated and HPCI was declared operable. The licensee has notified the NRC Resident Inspector. Notified R3DO (Lipa).
ENS 49296	22 August 2013 11:55:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge	Reactor Protection Actuation (Scram)	On Thursday, August 22, 2013 at 0755 hours (EDT), with the reactor critical at approximately 98% core thermal power, and the mode switch in RUN, a manual reactor scram was inserted due to lowering reactor water level. The cause of the lowering reactor water level was due to the trip of all three Feedwater Pumps. The cause of the Feedwater Pump trip event is currently under investigation. Following the reactor scram, all control rods were verified to be fully inserted. All 4kV busses transferred to the Startup Transformer as designed. Following the scram the reactor water level lowered to +12 inches initiating the Primary Containment Isolation System (Group II, Reactor Building Isolation System (RBIS); and Group VI - Reactor Water Cleanup System) automatically as per design. Reactor water level lowered to -46 inches initiating Primary Containment Isolation System Group I - Main Steam Isolation Valves (MSIVs); Emergency Core Cooling Systems (ECCS) actuated which included automatic start and injection of the High Pressure Coolant Injection (HPCI) System and the Reactor Core Isolation Cooling (RCIC) System and an automatic start of the Emergency Diesel Generators as designed. Reactor water level was promptly restored to normal level. Currently a cooldown is in progress with reactor pressure is being maintained by the HPCI System operating in the pressure control mode and reactor water level is being maintained by the RCIC System. Reactor Water Clean-up System and normal reactor building ventilation have been restored. Off-site power is being supplied to the station by the Start-up Transformer (normal power supply for shutdown operations). This event had no impact on the health and/or safety of the public. The USNRC Senior Resident Inspector has been notified. This 4-hour notification is being made in accordance with 10 CFR 50.72 (b)(2)(iv)(A) and (B). The plant is transferring from decay heat removal to the torus to decay heat removal to the main condenser. Reactor pressure is 371 psig. Initial indications are that a main feedwater power supply breaker tripped.
ENS 49225	30 July 2013 19:32:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Reactor Scram Due to Turbine Generator Trip	Actuation of Reactor Protection System with reactor critical. Reactor Scram occurred at 1432 CDT on 7/30/2013 from 100% Power. The cause of the scram appears to be a Turbine Generator trip. 05-S-01-EP-2, 'Reactor Pressure Vessel Control,' 05-1-02-I-1, 'Reactor Scram Off Normal Event Procedure,' and 05-1-02-I-2, 'Turbine and Generator Trip Off Normal Event Procedure,' were entered to mitigate the transient. No Loss of Off-site Power occurred. No Emergency Core Cooling System or Diesel Generator initiation occurred. Reactor Core Isolation Cooling initiated and injected. The lowest reactor water level reached was -36 inches wide range (RCIC initiation set point is -41.6 inches wide range). Main Steam Isolation Valves remained open and no Safety Relief Valves actuated. Currently, Main Turbine Bypass valves are controlling reactor pressure to the Main Condenser and Condensate and Feedwater is controlling reactor water level in the normal band and removing decay heat. There are no challenges to Primary or Secondary Containment. The NRC Senior Resident Inspector was notified. * * * UPDATE FROM CHRIS ROBINSON TO PETE SNYDER AT 1841 EDT ON 7/30/13 * * * The first out recorder indicated that RPS actuation signal was due to high reactor pressure as a result of the turbine control valves going shut. Notified R4DO (Farnholtz).
ENS 49084	2 April 2013 13:46:00	10 CFR 50.73(a)(1), Submit an LER	6O-Day Optional Telephone Notification for an Invalid Specified System Actuation	This 60-day telephone notification is being made per the reporting requirements specified in 10CFR50.73(a)(2)(iv)(A) and 10CFR50.73(a)(1) to describe an invalid actuation signal affecting containment isolation valves in more than one system. On April 2, 2013, Nine Mile Point 2 (NMP2) received a Division 2 reactor building area high ambient temperature isolation signal when lifting a lead for trip unit E31-N638B while performing surveillance N2-IPS-LDS-Q010, Reactor Building General Area Temperature Instrumentation Channel Functional Test. The isolation signal provided a closure signal to two Reactor Core Isolation Cooling System (RCIC) valves, and three Residual Heat Removal (RHR) system containment isolation valves. As a result of the isolation signal one of the RCIC containment isolation valves, 2ICSMOV128 closed. The other four valves were already in their normal closed position. The RHR system valves are associated with the RHR Shutdown Cooling System and second RCIC isolation valve is used to warmup and place the RCIC system in standby following an isolated condition. All affected isolation valves responded as designed. As a result of 2ICSMOV128 closing the RCIC system was declared inoperable. Technical Specification 3.5.3, RCIC System, Condition A was entered. Action A.1 required verifying the High Pressure Core Spray System (HPCS) was operable immediately. Action A.2 requires restoring RCIC to operable within 14 days. After the instrumentation system was restored to normal, the RCIC system was subsequently restored to available later that day at 1205 (EDT) and operable at 1500 (EDT). The actuation signal was not valid because it resulted from maintenance activities when leads were lifted, and the trip unit had not been bypassed as required by the procedure. There were no isolation logic signals in response to actual plant conditions or parameters. This event was entered into the corrective action system as Condition Report (CR) 2013-002461. There were no actual safety consequences or impact on the health and safety of the public as a result of this event. The licensee notified the NRC Resident Inspector and the State.
ENS 48977	28 April 2013 02:24:00	10 CFR 50.72(b)(2)(i), Tech Spec Required Shutdown 10 CFR 50.72(b)(3)(ii)(A), Seriously Degraded	Technical Specification Required Plant Shutdown	This notification is being provided in accordance with 10CFR50.72(b)(2)(i), Plant Shutdown required by Technical Specifications, and 10CFR50.72(b)(3)(ii)A, Degraded or Unanalyzed Condition. At 2245 CDT on 04/27/13, LaSalle Unit 1 commenced a Technical Specification required plant shutdown, due to identification of pressure boundary leakage. At 2124 CDT on 04/27/13, a through-wall leak was identified in the body of 1E51-F076, Reactor Core Isolation Cooling system steam supply inboard isolation bypass warmup valve. This qualifies as pressure boundary leakage, which requires entry into Technical Specification 3.4.5, Reactor Coolant System Operational Leakage, Required Action C, to be in Mode 3, Hot Shutdown, by 0924 (CDT) on 04/28/13, and Mode 4, Cold Shutdown, by 0924 (CDT) on 04/29/13. This leakage is significantly less than 10 gpm and therefore does not meet the threshold for entry into the Emergency Action Plan. At the time of discovery, Unit 1 was in startup mode following a forced outage. A unit shutdown has been initiated. A repair plan is being prepared at this time, and the unit will remain in Cold Shutdown until repairs are complete. The leak is located inside the primary containment and was visually identified during a containment walk-down. The licensee has notified the NRC Resident Inspector.
ENS 48969	26 April 2013 01:19:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation	Manual Reactor Scram Following Trip of Circ Water Pumps	This report is being made pursuant to 10CFR50.72(b)(2)(iv)(B), RPS Actuation (scram). At 2019 CDT on April 25, 2013, LaSalle Unit 2 was manually scrammed due to a loss of Condenser Circulating Water. The Unit was manually scrammed after the condenser circulating water pumps tripped due to high level in the turbine building condenser pit. The high level in the condenser pit was caused by a leak on the upper manway of the condenser water box during a maintenance activity. MSIV's were isolated due to loss of heat sink. The safety relief valves were used in pressure control mode. Current plant status: reactor level is stable and reactor pressure is stable. The condenser water box manway leak has been isolated. The plant will remain in hot shutdown pending investigation and repairs. Reactor Core Isolation Cooling (RCIC) is being used in the pressure control mode. The licensee has notified the NRC Resident Inspector.
ENS 48939	17 April 2013 20:11:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(a)(1)(i), Emergency Class Declaration 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge	Notification of Unusual Event Declared Due to Loss of Offsite Power from a Lightning Strike	LaSalle Unit 1 and LaSalle Unit 2 have both experienced an automatic reactor scram, in conjunction with a loss of offsite power. This was caused by an apparent lightning strike in the main 345kV/138kV switchyard during a thunderstorm. 138kV line 0112 has been inspected in the field, and heavy damage has been noted on the insulators on two of the three phases on a line lightning arrestor line side. The plant systems have all responded as expected. All five diesel generators started, and have loaded on to their respective buses as designed. All rods went full in on both units during the respective scrams. HPCS (High Pressure Core Spray) system was started on each unit and automatically aligned for injection for initial level control. The MSIVs (Main Steam Isolation Valves) are shut on both units with decay heat being removed via the safety relief valves. Suppression pool cooling is in progress. The licensee will notify the NRC Resident Inspector and has notified the State. Notified DHS, FEMA, USDA, HHS, DOE, NICC, EPA, and Nuclear SSA via email. * * UPDATE FROM DON PUCKETT TO VINCE KLCO AT 2113 EDT ON 4/17/2013 * * * In addition to information (previously provided), LaSalle Unit 2 received a high drywell pressure signal (1.77 psig) due to loss of containment cooling from the loss of power. At the time of this high drywell pressure signal, high pressure core spray pump and 2B residual heat removal (RHR) pump was already in operation, the low pressure core spray system and 2A residual heat removal system was secured and (placed) in pull to lock. When the signal was satisfied the ECCS (Emergency Core Cooling Systems) signal was processed but only the 2C RHR pump would have started. In this case, the 2C RHR pump tripped when the signal was received. There is no evidence of reactor coolant leakage. There was no additional ECCS systems discharging into the RCS (Reactor Coolant System). As (initially stated), level was controlled using High Pressure Core Spray and level control is now being maintained using the Reactor Core Isolation Cooling (RCIC) systems. The 2C RHR pump trip is under investigation. Due to the initial loss of offsite power for both Unit 1 and Unit 2 reported at 1511 (CDT), multiple containment isolation valves isolated and closed as expected. Once initial containment isolations were verified, two Unit 2 primary containment vent and purge valves were opened to vent the Unit 2 containment. Once Unit Two containment pressure reached 1.77 (psig), these two vent valves isolated as expected. Due to the loss of offsite power, the Station Vent Stack Wide Range Gas Monitor (WRGM) and the Standby Gas Treatment Wide Range Gas Monitor (VGWRGM) also lost power. Manual sampling has been implemented and power is restored to the VGWRGM, however the VGWRGM has not been declared operable yet. Normal radiation levels have been reported from the manual sampling. (This is being reported in accordance with 10CFR50.72(b)(3)(xiii).) The licensee notified the NRC Resident Inspector and the State of Illinois. Notified the R3 IRC, NRR EO(Skeen), IRD MOC (Grant). * * UPDATE AT 0057 EDT ON 04/18/13 FROM MIKE LAWRENCE TO S. SANDIN * * * After the Unit 2 primary containment vent and purge system isolated on the Unit 2 containment High Pressure signal, Venting of the Unit 1 primary containment was commenced. At 2005 CDT, Unit 1 primary containment pressure reached the Group 2 primary containment isolation system setpoint (1.77 PSIG) causing the primary containment vent and purge valves being used to vent the Unit 1 containment to isolate. Unit 1 primary containment venting was being performed through the Standby Gas Treatment system which is a filtered system. In addition to the primary containment isolation signal on high drywell pressure, an ECCS initiation on high drywell pressure also occurred. The ECCS signal resulted in an auto start of the 1C RHR system. The 1B RHR system was already running in suppression pool cooling mode. 1A RHR and LPCS had been secured to prevent overloading the common diesel generator for division 1. The common diesel generator supplies both Unit 1 and Unit 2 division 1 ESF busses. The licensee informed the NRC Resident Inspector. Notified NRR EO (Skeen), IRD MOC (Grant) and R3IRC (Louden). * * UPDATE AT 0947 EDT ON 04/18/13 FROM JUSTIN FREEMAN TO PETE SNYDER * * * LaSalle has terminated the unusual event which was initiated at 1511 on 4/17/13 and reported under EN 48939. This unusual event has been terminated based on meeting the following established criteria. This report is being made in accordance with 10CFR50.72.(c)(1)(iii). 1) Off-site power has been restored to all ESF busses 2) Fuel Pool Cooling has been restored on both units 3) Primary Containment Chillers have been restored on both units 4) Drywell pressure is less than ECCS initiation setpoint 5) ECCS signals cleared to allow diesels to be placed in stand by Recovery of remaining plant systems will be managed through the Outage Control Center (OCC)." The licensee informed the NRC Resident Inspector. Notified R3DO (Orth), NRR EO (Chernoff), IRD (Grant), DHS, FEMA, USDA, HHS, DOE, NICC, EPA, and Nuclear SSA via email. * * UPDATE AT 1711 EDT ON 4/21/2013 FROM GREG LECHTENBERG TO MARK ABRAMOVITZ * * * In addition to the 10 CFR 50.72 Sections initially identified, the Loss of Offsite Power was also reportable under 10 CFR 50.72(b)(3)(v)(D) as an event or condition that could have prevented the fulfillment of the safety function of systems needed mitigate the consequences of an accident. This event is considered a safety system functional failure for both Units 1 and 2. The licensee will notify the NRC Resident Inspector. Notified the R3DO (Orth).
ENS 48904	11 February 2013 11:13:00	10 CFR 50.72(b)(3)(iv)(A), System Actuation	Manual Initiation of Reactor Core Isolation Cooling System	On February 11, 2013, at 0613 hours (CDT), the Reactor Core Isolation Cooling (RCIC) system was manually started during a planned Unit 3 reactor shutdown. A Reactor Feedwater recirculation piping separation resulted in the loss of condenser vacuum and subsequent unavailability of the Main Turbine Bypass Valves. The RCIC system was manually started at 9.2" of condenser vacuum in order to control reactor water level in anticipation of loss of Reactor Feedwater Pumps (RFPs) which occurs at 7" of condenser vacuum. Safety Relief Valves (SRVs) were manually operated to maintain reactor pressure. The reactor water level was controlled in the normal band by RCIC, and Reactor Pressure was controlled with a combination of Reactor Core Isolation Cooling (RCIC) system and SRV manual operation. All systems operated as designed and Reactor water level was maintained in the prescribed band. No Emergency Core Cooling System (ECCS) or Reactor Core Isolation Cooling (RCIC) reactor water level initiation set points were reached. RCIC operation was secured at 1449 (CDT) on 2/11/2013. This event is reportable within 8 hours per 10CFR50.72(b)(3)(iv)(A). During a review of operating logs it was identified that this event met reporting requirements and had not been reported. Therefore, this report does not comply with the 8 hour requirement. This condition has been entered into the corrective action program. Additionally, an LER is required within 60 days per 10CFR50.73(a)(2)(iv)(A). The NRC Resident Inspector has been notified.
ENS 48897	8 April 2013 15:15:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Hpci Declared Inoperable During Surveillance Testing	On April 8, 2013 at 0908 (EDT), the High Pressure Coolant Injection System (HPCI) was declared inoperable as part of planned Controls Functional Testing. At 1115 (EDT), during the performance of scheduled testing, an initiation signal for the HPCI system was provided and the HPCI Auxiliary Oil Pump failed to start as expected. The HPCI Auxiliary Oil Pump provides the motive force to open the HPCI Turbine Stop and Governor valves during system startup. The inability of the HPCI Turbine Stop and Governor valves to open prevents the HPCI system from fulfilling its design safety function. The HPCI system will remain inoperable until the cause of the failure has been corrected. All other Emergency Core Cooling Systems and the Reactor Core Isolation Cooling (RCIC) system remain operable. The unit remains at 100% power. The station has initiated an Event Response Team to identify and correct the cause of the failure. No personnel injuries resulted from the event. The NRC Resident Inspector and Lower Alloways Creek Township will be notified.
ENS 48782	25 February 2013 19:13:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(i), Tech Spec Required Shutdown	Automatic Scram Due to a Turbine Trip from a Loss of Condenser Vacuum	At 1313 (CST) on 02/25/2013, the Unit 3 reactor automatically scrammed due to actuation of the Reactor Protection System from a turbine trip. Preliminary indications show the turbine tripped on low condenser vacuum. Cause of loss of condenser vacuum has been identified as Reactor Feedwater recirculation piping separation. Main Steam Isolation Valves (MSIVs) were manually closed to isolate the leak. None of the Safety Relief Valves (SRVs) automatically cycled during the transient, and one Safety Relief Valve (SRV) was manually operated to maintain Reactor Pressure due to the Main Turbine Bypass Valves unavailability because of loss of condenser vacuum. All systems responded as expected to the turbine trip. No Emergency Core Cooling System (ECCS) or Reactor Core Isolation Cooling (RCIC), reactor water level initiation set points were reached. Reactor water level is being controlled by the RCIC system and Reactor Pressure is being controlled with the High Pressure Coolant Injection (HPCI) system. All expected containment isolation and initiation signals (Groups 2, 3, 6, and 8) were received. Upon receipt of these signals all required components actuated, with the exception of one valve in Group 6. Drywell Continuous Air Monitor (CAM) Inboard Return Isolation Valve 3-FSV-90-257 did not have indication following isolation signal and was not able to be verified locally. Indication was subsequently restored following restoration of containment isolation signals, and the Drywell CAM was manually isolated at 1422 (CST) with positive indication of isolation, and isolation valves deactivated at time 1514 (CST) to satisfy TS LCO 3.6.1.3 required actions. This event is reportable within 4 hours per 10CFR50.72(b)(2)( iv)(B), 'Any event or condition that results in actuation of the reactor protection system (RPS) when the reactor is critical except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation'. It is also reportable within 8 hours per 10CFR 50.72(b)(3)(iv)(A) and requires an LER within 60 days per 10CFR 50.73(a)(2)(iv)(A). At 1415 (CST), Suppression Pool Water level exceeded -1 inch due to operation with HPCI in pressure control mode, and required entry into TS LCO 3.6.2.2 condition A to restore level within 2 hours. Efforts are being made to lower suppression pool water level within limits. At 1615 (CST), water level remains above -1 inch requiring entry into TS LCO 3.6.2.2 condition B requiring action to be in MODE 3 in 12 hours and MODE 4 within 36 hours. This event is reportable within 4 hours per 10CFR 50.72(b)(2)(i), 'The initiation of any nuclear plant shutdown required by the plant's Technical Specifications.' The NRC Resident Inspector has been notified. All control rods fully inserted and electrical offsite power is in a normal shutdown configuration. Residual Heat Removal is aligned for suppression pool cooling. There was no impact on either Unit 1 or 2.
ENS 48736	9 February 2013 03:00:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(a)(1)(i), Emergency Class Declaration	Unusual Event Declared Due to Loss of Offsite Power	Pilgrim Station scrammed on a loss of offsite power. All systems performed as designed. Groups I, II, VI went to completion. Reactor Core Isolation Cooling (RCIC) is injecting to the vessel controlling level. High Pressure Coolant Injection is in pressure control and slowly cooling down. Offsite power was lost multiple times. The Startup Transformer has been declared inoperable. The Unusual Event was declared under EAL SU 1.1 based on loss of offsite power greater than 15 minutes (at 2200 EST). The licensee originally experienced an automatic reactor scram at 2117 EST due to a load reject with a turbine trip/reactor scram due to loss of power. Offsite power availability has been fluctuating in and out to the site. The licensee states that all systems are functioning as required. All rods fully inserted and the reactor is stable in Mode 3. Both Emergency Diesel Generators are providing power to the safety related buses. The loss of offsite power is believed to be weather related. The licensee has notified the State and local authorities and the NRC Resident Inspector. Notified DHS SWO, FEMA, USDA, HHS, DOE, DHS NICC, EPA, and NuclearSSA via email. * * UPDATE FROM PAUL GALLANT TO VINCE KLCO AT 2/10/13 AT 1108 EST* * * Pilgrim terminated the Unusual Event and has transitioned to recovery effective at 10:55 AM on 02/10/2013. Offsite power has been restored to safety-related and non-safety-related electrical buses through the station Startup Transformer via a single 345 KV line. The other two offsite power sources remain out of service. The emergency diesel generators have been secured and are in standby. Residual heat removal is in shutdown cooling mode maintaining the reactor in cold shutdown. Fuel Pool Cooling is in service with fuel pool coolant temperatures trending down. The licensee notified State, local authorities and the NRC Resident Inspector. Notified R1 RA (Dean), R1DO (Powell), NRR DIR(Leeds) NRR EO (Evans) and NSIR IRD (Marshall). Notified DHS SWO, FEMA, USDA, HHS, DOE, DHS NICC, EPA, and NuclearSSA via email.
ENS 48696	23 January 2013 20:16:00	10 CFR 50.72(b)(3)(v)(A), Loss of Safety Function - Shutdown the Reactor 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Concurrent Loss of High Pressure Reactor Makeup Systems Capability	On 1/23/2013 at 1516 (EST), Nine Mile Point 2 (NMP2) had a failure of a Reactor Building General Area temperature trip unit occur resulting in the closure of an isolation valve on the Reactor Core Isolation Cooling (RCIC) system steam supply line. Concurrent with this failure, the High Pressure Core Spray (HPCS) system was inoperable for planned surveillance testing. With both the RCIC and HPCS systems inoperable, NMP2 entered a Technical Specification Required Action to be in Mode 3 within 12 hours. At 1550, the HPCS system was restored to OPERABLE. Based on the concurrent loss of the high pressure reactor makeup capability of these two systems, it was determined that the condition is reportable under section 50.72(b)(3)(v) as the following safety functions were impacted: (A) Shutdown the reactor and maintain it in a safe shutdown condition; and (D) Mitigate the consequences of an accident. NMP2 remains in a stable condition at rated power. The offsite grid is stable with no restrictions or warnings in effect. The licensee notified the NRC Resident Inspector.
ENS 48688	22 January 2013 08:32:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge	Automatic Reactor Protection System Actuation	On January 22, 2013, at approximately 0332 hours (EDT), an automatic Reactor Protection System (RPS) actuation occurred at the Perry Nuclear Power Plant, Unit 1. At the time of the event, the plant was in Mode 1 at 100% power. All control rods are inserted into the reactor core and the plant is currently stable in Mode 3 (Hot Shutdown) with reactor pressure and level being maintained in the normal shutdown range. The RPS actuation was initiated by a low reactor water level (Level 3 - 178") signal. In response to the RPS actuation and subsequent reactor Level 2 (130") signal, the High Pressure Core Spray (HPCS) system and Reactor Core Isolation Cooling (RCIC) system both actuated and injected to maintain reactor coolant level. The reactor level is currently being maintained in its normal band by the feedwater system and decay heat is being removed by (turbine bypass valves to) the condenser (both HPCS and RCIC have been returned to standby). The plant is in a normal electrical line-up with all three Emergency Diesel Generators operable and available, if needed. The Containment Isolation Valves (responded to the Level 2 and 3) isolation signals as designed. The cause of the RPS actuation is under investigation. The NRC Resident Inspector has been notified.
ENS 48623	22 December 2012 17:52:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Automatic Reactor Scram Due to Loss of Power to the Reactor Protection System	On 12/22/2012 at 1152 CST, the Unit 2 reactor automatically scrammed due to actuation of the Reactor Protection System (RPS) from loss of power to RPS. At 1134 CST, the D 4kV Shutdown Board unexpectedly de-energized during performance of post-maintenance testing for the 3D Diesel Generator paralleling circuitry, resulting in loss of power to the 2B RPS subsystem. Primary Containment Isolation System (PCIS) groups 2, 3, 6, and 8 isolations were received along with automatic initiation of A, B, and C Standby Gas Treatment subsystems and A Control Room Emergency Ventilation subsystem due to loss of power to the 2B RPS subsystem. While attempting to reenergize the 2B RPS subsystem, the 2A RPS subsystem was inadvertently de-energized resulting in Unit 2 reactor automatic scram. All affected safety systems responded as expected for the loss of RPS and reactor scram. Due to the loss of RPS, the Main Steam Isolation Valves (MSIVs) closed. Reactor pressure did not rise to the automatic initiation set point for Safety Relief Valve (SRV) actuation. Reactor Core Isolation Cooling System (RCIC) and High Pressure Coolant Injection System (HPCI) reactor water level initiation set point of -45" was reached and RCIC and HPCI automatically initiated as designed to restore water level above the initiation set point. Both Recirculation Pumps also tripped on reactor water level of -45". Reactor pressure control was established by manually operating one SRV and water level control established with RCIC. HPCI was returned to standby readiness. The scram was reset, MSIVs were opened, and the Main Condenser was established as a heat sink. The scram event from critical is reportable within 4 hours per 10 CFR 50.72(b)(2)(iv)(B). It is also reportable within 8 hours per 10 CFR 50.72(b)(3)(iv)(A) and requires an LER within 60 days per 10 CFR 50.73(a)(2)(iv)(A). The NRC Resident Inspector was notified. The 2A and 2B RPS subsystems were returned to service. The electrical grid is stable and supplying shutdown loads on Unit 2. Unit 1 and Unit 3 were unaffected and continue to operate at 100% power.
ENS 48570	12 October 2012 14:12:00	10 CFR 50.73(a)(1), Submit an LER	Temperature Switch Failure Causes Division I Isolation Signal	This 60-day telephone notification is being made per the reporting requirements specified in 10 CFR 50.73(a)(2)(iv)(A) and 10 CFR 50.73(a)(1) to describe an invalid actuation signal affecting containment isolation valves in more than one system. On October 12, 2012, Nine Mile Point Unit 2 (NMP2) received a Division I primary containment isolation signal which resulted in the closure of Group 5, 6, and 10 primary containment isolation valves (PCIVs) in the following systems: Group 5 PCIVs: Residual Heat Removal System (RHS); Shutdown Cooling (SDC); Group 6 PCIVs: Reactor Water Cleanup System (WCS) supply outside isolation valve; and Group 10 PCIVs: Reactor Core Isolation Cooling (RCIC) System. All affected PCIVs responded as designed. The Division I isolation signal was generated due to the failure of a temperature switch unit. The Division I and II temperature switch units were both reading within limits when the Division I unit failed. Since the isolation signal was not initiated in response to actual plant conditions or parameters satisfying the requirements for initiation, the isolation signal was determined to be invalid. The event was entered into the corrective action program as Condition Report CR-2012-009380. There were no safety consequences and no impact to the health and safety of the public as a result of this event. The licensee notified the New York State Public Service Commission and the NRC Resident Inspector.
ENS 48479	5 November 2012 02:53:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation	Automatic Reactor Scram from Full Power Following Turbine Trip	The reactor was scrammed on a valid reactor protection system activation caused by a main turbine trip. The cause of the main turbine trip is under investigation. All control rods fully inserted. All isolations and initiations occurred as designed. High Pressure Coolant Injection (HPCI) and Reactor Core Isolation Cooling (RCIC) initiated as expected. RCIC injected into the reactor coolant system, HPCI did not, as expected. This scram was characterized as uncomplicated and the reactor is stable in Mode 3. The plant is in a normal post shutdown electrical lineup. All systems functioned as required. The NRC Resident Inspector has been notified.
ENS 48341	25 September 2012 15:44:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Automatic Reactor Scram During Maintenance on 4160V Bus 12 Ammeter	During maintenance on 4160V Bus 12 ammeter, a Bus 12 lockout occurred. The station power was from 1R Reserve transformer for work on the 2R Auxiliary transformer. Net effect was Bus 12 locked out, removing power from 12 Reactor Feed Pump and 12 Reactor Recirculation pump. Reactor level lowered to +23 inches then began to rise. With both Main Feed Reg Valves in AUTO, the level transient reached +48 inches, the Reactor Water Level Hi Hi setpoint. The Main Turbine and 11 Reactor Feed Pump tripped as designed, and a Reactor SCRAM occurred. Reactor water level began to drop, and C.4.A Abnormal Procedure for SCRAM was used to restart 11 Reactor Feed Pump and recover water level. Minimum water level reached was -26 inches. Reactor Low Level SCRAM signal and Group 2 Primary Containment isolation occurred at +9 inches as designed, No Safety Relief valves lifted during this transient. High Pressure Coolant Injection (HPCI) and Reactor Core Isolation Cooling (RCIC) did not receive an initiation signal due to not reaching their setpoints. There were no Emergency Core Cooling Systems initiation setpoints reached. Prior to the event, both divisions of Standby Liquid Control were inoperable as part of planned maintenance. All control rods fully inserted. Decay heat is being removed through the turbine bypass to the main condenser. The plant is in a normal shutdown electrical lineup and stable in Mode 3. The licensee has notified the NRC Resident Inspector and will notify the State and local governments.
ENS 48270	3 September 2012 06:25:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Hpci Inoperable Due to Erroneous Indication on Flow Indicating Controller	At 0225 EDT on September 3, 2012, with the James A. Fitzpatrick Nuclear Power Plant (JAF) operating at 93% reactor power, High Pressure Coolant Injection (HPCI) was declared inoperable due to abnormal indication on the HPCI Flow Indicating Controller (FIC). The FIC was found to be indicating a HPCI System flow rate of 700 gpm while the system was in the standby lineup. Under these conditions, the capability of the system to achieve the required flow rate cannot be assured. This failure meets NRC 8 hour reporting criterion 10CFR50.72(b)(3)(v)(D). Reactor Core Isolation Cooling (RCIC) and other Emergency Core Cooling Systems (ECCS) remain operable. The NRC Resident Inspector has been notified. * * UPDATE AT 1418 EDT ON 9/4/12 FROM DeFILLIPPO TO HUFFMAN * * * The improper HPCI flow indication was determined to be due to minor air intrusion following restoration of the system after maintenance. The flow transmitter for the HPCI system was repeatedly vented with no air observed. The HPCI system has been restored to a normal standby line-up and is OPERABLE as of 9/4/2012 at 1415 EDT. The NRC Resident Inspector has been notified. R1DO (Conte) notified.
ENS 48258	30 August 2012 16:15:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Hpci Inoperable Due to Failed Pressure Control Valve	At 1215 EDT on August 30, 2012, with the James A. FitzPatrick Nuclear Power Plant (JAF) operating at 95% reactor power, High Pressure Coolant Injection (HPCI) was declared inoperable due to the failure of a pressure control valve on the HPCI oil cooling system. The failure of this pressure control valve results in a safety-valve lifting and releasing approximately 75 gallons per minute to the reactor building equipment drain tank. There was no release to the environment. This failure meets NRC 8 hour reporting criterion 10CFR50.72(b)(3)(v)(D). Reactor Core Isolation Cooling (RCIC) and other Emergency Core Cooling System (ECCS) systems remain operable. The NRC Resident Inspector has been notified.
ENS 47972	29 May 2012 08:31:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Automatic Reactor Scram Due to Main Generator Load Reject Signal	On 5/29/2012 at 0331 (CDT) the Unit 3 reactor scrammed due to turbine control valve fast closure initiated by a load reject signal on the Main Generator. The cause of the load reject signal is Main Transformer differential relay 387T. Reactor power at the time of the SCRAM was approximately 75%. All systems responded as expected to the load reject signal. Main Steam Isolation Valves remained open and reactor pressure is being controlled on the Main Turbine Bypass Valves. No Main Steam Relief Valves lifted during the transient. No Emergency Core Cooling System (ECCS) or Reactor Core Isolation Cooling (RCIC) reactor water level initiation setpoints were reached. Primary Containment Isolation Signals (PCIS) Groups 2, 3, 6 and 8 were received. The lowest reactor water level observed was -41 inches. Reactor water level was restored to and is being controlled by the Feedwater system in the normal band. This event is reportable within 4 hours per 10CFR50.72(b)(2)(iv)(B), 'any event or condition that results in actuation of the reactor protection system (RPS) when the reactor is critical except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation.' It is also reportable within 8 hours per 10CFR50.72(b)(3)(iv)(A) and requires an LER within 60 days per 10CFR50.73(a)(2)(iv)(A). This event is documented in the station corrective action program on SR# 557947. The NRC Resident Inspector has been notified. All control rods inserted into the reactor core. Electrical power is being back fed from offsite power through the 161 KV feeder line. The reactor is being cooled down within the Technical Specification rates.
ENS 47960	24 May 2012 18:48:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(3)(xiii), Loss of Emergency Preparedness	Manual Reactor Scram Due to a Loss of Feed as Result of a Loss of Switchgear	At 1348 CDT on 5/24/12 with the Reactor at 33% power, River Bend Station operators inserted a manual reactor scram based on loss of high pressure feed to the reactor following a loss of a 13.8 Kv switchgear. The Control Room team observed an electrical transient in the Control Room concurrent with the start of Reactor Feed Pump "B". The crew identified that no high pressure feed was aligned to the reactor and inserted a manual scram. Based on the configuration of the electrical plant during startup, all circulating water and Normal Service Water (NSW) was supplied from NPS-SWG1B. MSIVs were closed based on loss of circulating water and Standby Service Water (SSW) initiated automatically based on loss of NSW. EOP-0001, 'RPV Control' was entered on reactor high pressure and reactor low water level. EOP-0002, 'Primary Containment Control' was entered based on primary containment pressure high and suppression pool level high. EOP-0003, 'Secondary Containment Control', was entered on annulus pressure high. Reactor water level control is being maintained with Reactor Core Isolation Cooling (RCIC). High pressure core spray was manually started but was not required and was subsequently shut down. Pressure control is via RCIC and Safety Relief Valves (SRVs). Safety related busses are aligned to offsite power as normal. They were not affected by the electrical transient. Immediately after the scram at 1350, a report from the Turbine Building indicated smoke was seen around the Reactor Feed Pump 'B' termination cabinet. The Fire Brigade was activated. At 1358, the Fire Brigade reported that there was no fire. A review of the Emergency Action Levels (EALs) was performed. No emergency declaration was required. Initial investigation shows damage to cabling and circuit boards associated with Reactor Feedpump 'B' in the Turbine Building, but no fire was ever observed. In addition, the Technical Support Center (TSC) and Operations Support Center (OSC) lost power. At the time, both facilities continued to be in a state of readiness and emergency functions could be performed. At 1526, power was restored to both facilities, including the ventilation systems. All rods inserted into the core. The unit is stable at 230 psi and 391 degrees F. Reactor pressure is maintained by RCIC and decay heat removal via safety relief valves to the suppression pool. The unit is in a technical specification for suppression pool high level. There were no safety system failures. There is one non safety related 13.8 switchgear out of service due to this event and NNS-Switchgear 2A out of service from an event three days ago. Offsite assistance was not required. The NRC Resident Inspector has been notified.
ENS 47955	24 May 2012 11:39:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Reactor Scram During Startup	At 0639 CDT on 5/24/2012. Unit 3 initiated a manual scram due to multiple rods inserting. At 0637 CDT during Unit 3 start-up Intermediate Range Monitor (IRM) 'H' was ranged down instead of up resulting in half scram on Reactor Protection System (RPS) 'B' trip system. The half scram was being reset after IRM 'H' was properly ranged. The operator placed the scram reset switch in Group 2/3 position. As the operator reset groups 2 and 3, a spike on IRM 'A' was received on the RPS 'A' trip system, resulting in rod insertion for groups 1 and 4. When the operator identified multiple rods inserting, the actions of procedure 3-AOI-l00-1 were followed and a manual scram was inserted. Investigation is ongoing. All safety systems remained in standby readiness configuration. No Emergency Core Cooling System (ECCS) or Reactor Core Isolation Cooling (RCIC) reactor water level initiation set points were reached. Primary Containment lsolations Systems did not received actuation signals and performed as designed. This event is reportable within 4 hours per 10 CFR 50.72(b)(2)(iv)(B) 'any event or condition that results in actuation of the RPS when the reactor is critical except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation.' It is also reportable within 8 hours per 10 CFR 50.72(b)(3)(iv)(A) 'any event or condition that results in valid actuation of systems listed in paragraph (b)(3)(iv)(B) 'Reactor Protection System (RPS) Including reactor scram and reactor trip.' This event requires an LER within 60 days per 10 CFR 50.73(a)(2)(iv)(A). The NRC Resident Inspector has been notified.
ENS 47942	22 May 2012 07:49:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Automatic Scram Due to Reactor Protection System Being De-Energized	At 0249 CDT on 5/22/2012, Unit 3 reactor automatically scrammed due to de-energization of Reactor Protection System (RPS) from actuation of 3A Unit Station Service Transformer (USST) differential relay 387SA, which resulted in a loss of 500KV power to Unit 3. This relay was picked up during a transfer of 4KV Unit Board 3C from alternate power (161KV) to normal power (3A USST). Investigation is in progress as to the cause of relay actuation. 500KV power was restored through the alternate feeder breakers from 161KV to all Unit 3 4KV Unit Boards successfully. 161KV remained available during the entire event. Loss of 500KV power lasted less than 30 seconds and power has been restored to all safety related boards. All Unit 3 diesel generators successfully started and tied to their respective 4KV Shutdown Boards. All safety systems responded as expected to the loss of 500KV power. No Emergency Core Cooling System (ECCS) or Reactor Core Isolation Cooling (RCIC) reactor water level initiation set points were reached. RCIC was manually started to control reactor water level. Primary Containment Isolation System (PCIS) and PCIS initiation signals for groups 1, 2, 3, 6 & 8 were received as designed. At the time of the scram, High Pressure Coolant Injection (HPCI) system was tagged out for removal of temporary instrumentation following planned maintenance. This event is reportable within 4 hours per 10CFR 50.72(b)(2)(iv)(B) 'any event or condition that results in actuation of the reactor protection system (RPS) when the reactor is critical except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation'. It is also reportable within 8 hours per 10CFR 50.72(b)(3)(iv)(A) and requires an LER within 60 days per 10CFR 50.73(a)(2)(iv)(A). The NRC Resident Inspector has been notified.
ENS 47940	21 May 2012 19:52:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation	Automatic Reactor Scram Resulting from a Low Condenser Vacuum-Turbine Trip	At 1452 CDT on 5/21/2012 with the reactor at 100% power, River Bend Station experienced a reactor scram resulting from an RPS actuation. Following the scram, reactor water level briefly lowered below level 3. The reactor is stable with pressure and temperature being controlled by the feed water system and main steam bypass valves, respectfully. The cause of the scram was due to a turbine trip/low condenser vacuum. The low vacuum condition resulted from a loss of non-safety related 4160V switchgear that powers two of four circulating water pumps. A suspected spurious Division II isolation of Reactor Core Isolation Cooling (RCIC) was observed. Restoration of RCIC to standby is in progress. A report of a fire in a manhole was received shortly after the scram . Fire Brigade was dispatched and noted a small active fire in a cable tray. The fire was extinguished with fire extinguishers. Power cables are routed through this manhole. The plant is conducting causal investigations to fully understand the cause of the turbine trip. As information becomes available, River Bend Station will provide additional information. All rods are inserted, and the plant is in a normal shutdown electrical lineup with the exception of NNS-Switchgear 2A being deenergized. Offsite assistance was not required to extinguish the fire. The licensee notified the NRC Resident Inspector.
ENS 47893	2 May 2012 21:58:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Coolant Injection Inoperable Due to Erratic Governor Operation	On 5/2/2012 at 1758 EDT, the Unit 1 High Pressure Coolant Injection (HPCI) System was declared inoperable in accordance with Technical Specification 3.5.1 due to the flow controllers inability to maintain stable system flow and discharge pressure. This failure was discovered during the high steam pressure operability run (i.e., within 48 hours of achieving adequate test pressure following a scheduled refueling/maintenance outage) required by Technical Specification Surveillance 3.5.1.7 following refueling outage B119R1. This report is being made in accordance with 10 CFR 50.72(b)(3)(v)(D), as a condition that at the time of discovery could have prevented the fulfillment of the safety function of systems that are needed to mitigate the consequences of an accident. The safety significance of this event is considered minimal. The Reactor Core Isolation Cooling (RCIC) system, Automatic Depressurization System (ADS) and Low Pressure Emergency Core Cooling Systems (ECCS) remain operable at this time. Actions have been taken to protect redundant safety systems. The NRC Resident Inspector has been notified.
ENS 47745	15 March 2012 00:34:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Hpci Inoperable Due to Failure of Turbine Governor Valve	On March 14th, 2012 at 2034 EST the High Pressure Coolant Injection System (HPCI) was declared inoperable due to a failure of the turbine governor valve to respond as expected to demanded position. With the HPCI system flow controller output signal at zero percent demand the governor valve traveled to the mid position and did not remain closed as expected when the oil system auxiliary pump was started. With this unexpected response the speed and flow control system for the turbine is inoperable. The failure was discovered as part of a planned evolution for oil sampling. All other Emergency Core Cooling Systems and the Reactor Core Isolation Cooling (RCIC) system remain operable. The unit remains at 100% power. The station has initiated an Event Response Team to identify and correct the cause of the failure. No personnel injuries resulted from the event. The NRC Resident Inspector and Lower Alloway Creek Township will be notified.
ENS 47690	23 February 2012 04:19:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Manual Reactor Scram Due to High Delta-P Across Circulating Water Pump Traveling Screens	At 2319 hours EST, a manual Reactor Protection System (RPS) actuation was inserted on Unit 1 in anticipation of a loss of condenser vacuum. Shortly before the manual RPS actuation, Circulating Water Intake Pump (CWIP) 1B tripped due to high delta-pressure across the intake traveling screen. This caused the trip of the remaining pumps. Previously, at 1859 hours, balance of plant (BOP) bus Common C unexpectedly de-energized. This caused loss of power to the CWIP traveling screen motors which, in turn, lead to the high delta-pressure across the traveling screen(s). All control rods inserted properly. As a result of the scram, reactor water level reached the Low Level 1 actuation set point and Primary Containment (i.e., Group 6) isolation occurred. All systems functioned as designed. The High Pressure Coolant Injection (HPCI) system is being used, as needed, for pressure control. The Reactor Core Isolation Cooling (RCIC) system is being used, as needed, for level control. No Safety/Relief Valves (SRVs) actuated as a result of the manual RPS actuation. The manual RPS actuation is reportable in accordance with 10CFR50.72(b)(2)(iv)(B) and 10CFR50.72(b)(3)(iv)(A). The actuation of the HPCI and RCIC systems and the Group 6 isolation are reportable in accordance with 10CFR50.72(b)(3)(iv)(A). The unit is currently in Mode 3 with a cooldown in progress. The licensee notified the NRC Resident Inspector. Notified R2DO (Ernstes). * * UPDATE FROM STEWART BYRD TO CHARLES TEAL AT 0741 EST ON 2/23/12 * * * At 2319 hours EST, a loss of all Circulating Water Intake Pumps caused a lowering vacuum on Unit 1. As previously reported (i.e. Event Notification 47690), a manual Reactor Protection System (RPS) actuation was inserted on Unit 1 at this time. In addition, a valid actuation of the RPS, High Pressure Coolant Injection (HPCI), Reactor Core Isolation Cooling (RCIC), and a Group 6 isolation was reported in accordance with 10CFR50.72(b)(3)(iv)(A). At 2342, Main Condenser vacuum was 15 in. Hg and lowering. All Main Steam Isolation Valves were slow closed in anticipation of Group 1 isolation at this time. This follow-up notification is being made to report the manual actuation of the Group 1 isolation valves in accordance with 10 CFR 50.72(b)(3)(iv)(A). The Group 1 isolation was discussed with the NRC during initial notification of EN 47690, and this follow-up is providing written notification of the MSIV closure. The NRC Resident Inspector has been notified. Notified R2DO (Ernstes).
ENS 47687	23 February 2012 01:14:00	10 CFR 50.72(b)(2)(i), Tech Spec Required Shutdown	Technical Specification Required Shutdown Due to Inoperability of Emergency Core Cooling Systems	At 1859 hours EST, the Brunswick site experienced a loss of balance of plant (BOP) bus Common C. As a result, makeup pumps to the ECCS discharge line keepfill systems lost power. At 1905 on Unit 1, 'A' loop of the Core Spray (CS) system received a low discharge pressure alarm and was declared inoperable. At 1916 hours, 'B' loop of the Residual Heat Removal (RHR) system received a low discharge pressure alarm and was declared inoperable. With the loss of the second low pressure ECCS system, Condition J of Technical Specification 3.5.1, 'ECCS Operating,' was entered, which requires the Unit 1 to enter LCO 3.0.3 immediately. At 1931 hours, 'A' loop of RHR was declared inoperable due to low discharge pressure. Power reduction of Unit 1 was initiated at 2014 hours. At 2055 hours on Unit 2, 'A' loop of the Residual Heat Removal (RHR) system received a low discharge pressure alarm and was declared inoperable. At 2128 hours, 'B' loop of the Core Spray (CS) system received a low discharge pressure alarm and was declared inoperable. With the loss of the second low pressure ECCS system, Condition J of Technical Specification 3.5.1, 'ECCS Operating,' was entered, which requires the Unit 2 to enter LCO 3.0.3 immediately. Power reduction of Unit 2 was initiated at 2219 hours. This event reportability is in accordance with 10CRF50.72(b)(2)(i), Technical Specification Required Shutdown, due to inoperability of ECCS systems. The initial safety significance of this event is minimal. Offsite power and the Emergency Diesel Generators are operable. The High Pressure Coolant Injection (HPCI) system remains operable on both Unit 1 and Unit 2. The Reactor Core Isolation Cooling (RCIC) system remains operable on Unit 1 and is being restored following maintenance on Unit 2. Troubleshooting activities to determine the loss of the BOP Common C bus are in progress. Efforts are in progress to install temporary power to the keepfill makeup pumps. The licensee will notify the NRC Resident Inspector. * * UPDATE FROM CURTIS DUNSMORE TO DONALD NORWOOD AT 0223 EST ON 2/23/2012 * * * Unit 1 - At 2315 hours, temporary power was provided to the ECCS keepfill makeup pump and the ECCS systems were restored. LCO 3.0.3 was exited on Unit 1 at 0041 hours with restoration of the 'A' and 'B' loops of the RHR systems. The 'A' loop of the Core Spray system was restored at 0058 hours on 2/23/2012. During the shutdown, Unit 1 was manually scrammed due to high delta-pressure across the Circulating Water Pump traveling screens. See EN #47690 for details. Unit 2 - At 2315 hours, temporary power was provided to the ECCS keepfill makeup pump and the ECCS systems were restored. LCO 3.0.3 was exited on Unit 2 at 2354 hours with restoration of 'B' loop of the RHR system. The 'A' loop of the Core Spray system was restored at 0039 hours. Unit 2 was at 96% of Rated Thermal Power when the shutdown was terminated. The licensee notified the NRC Resident Inspector. Notified R2DO (Ernstes).
ENS 47679	20 February 2012 01:04:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Manual Reactor Scram During Shutdown Due to Lowering Reactor Vessel Water Level (Rvwl)	On 2/19/2012 at 1904 hrs (CST) the reactor was manually scrammed from approximately 23% core thermal power due to lowering reactor water level. All control rods fully inserted and all systems actuated and operated as designed. The Reactor Core Isolation Cooling System was manually initiated to assist in level control. No safety relief valves actuated. Reactor level and pressure are currently being controlled within normal bands. Group 2 and 3 RHR Isolation signals were received, however no valve movement occurred since the affected valves are normally closed. This event is reportable under 10CFR50.72(b)(2)(iv)(B) for the reactor trip and 50.72(b)(iv)(A) for the manual start of the core isolation cooling system. The lowest Reactor Vessel Water Level (RVWL) observed was -38 inches WR (Wide Range). RVWL was restored by placing the "A" Reactor Feed Pump (RFP) in service. The "B" RFP which had been operating was secured for troubleshooting. The Unit was in the process of shutting down for its scheduled Refueling Outage #18. The NRC Resident Inspector was in the control room at the time of the transient.
ENS 47585	12 January 2012 03:15:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Coolant Injection System Declared Inoperable	On January 11, 2012 at 22:15 (EST), the High Pressure Coolant Injection System (HPCI) was declared inoperable due to a failure of the turbine governor valve to respond to demanded position. When demanded to travel to the full closed position, the governor valve remained full open rendering the speed and flow control system for the turbine inoperable. The failure was discovered as part of a planned maintenance evolution. All other Emergency Core Cooling Systems and the Reactor Core Isolation Cooling (RCIC) system remain operable. The unit remains at 100% power. The station has initiated an Event Response Team to identify and correct the cause of the failure. No personnel injuries resulted from the event. The NRC Resident Inspector (has been notified) and Lower Alloway Creek Township will be notified. The unit is in a 14-day LCO for HPCI inoperability. * * RETRACTION FROM JAMES PRIEST TO VINCE KLCO ON 1/13/12 AT 1644 EST * * * The following is a retraction of ENS Notification #47585: On January 11, 2012, Hope Creek Generating Station reported to the NRC that High Pressure Coolant Injection System (HPCI) was declared inoperable due to a failure of the turbine governor valve to respond to demanded position. This condition was discovered when obtaining an oil sample from the HPCI system. According to the procedure, the HPCI flow controller automatic setpoint was lowered to zero. The procedure set the manual controller setpoint by having the operator lower the demand for a time period rather than verifying the setpoint at zero. The HPCI Auxiliary Oil Pump is then started. The governor valve was expected to start to open (intermediate position) and then close. Instead the valve went to the full open position and did not respond to attempts to close the valve from the flow controller. Accordingly, Control Room personnel conservatively initiated ENS reporting under 10CFR50.72(b)(3)(v) in response to the apparent loss of safety function for Unit 1. Subsequent technical evaluation concluded that the performance and response of the HPCI turbine governor control valve was as expected based on the manual controller demand being at 35% when the HPCI Auxiliary Oil Pump was started to collect a HPCI oil sample. The Engineering review concluded that there are no problems with the HPCI turbine governor control valve response to controller demand. Operating procedures have been revised to provide guidance on verifying manual controller demand at 0% before placing the HPCI Auxiliary Oil Pump in service under standby conditions for oil sampling or similar evolutions. Since January 11th, 2012, HPCI has remained available to perform its required safety functions and only became inoperable during planned evolutions to either obtain oil samples or to investigate HPCI turbine governor control valve performance. On this basis, the HPCI system was capable of performing its function to mitigate the consequences of an accident and the issue described in Event #47585 is not reportable under 10 CFR 50.72(b)(3)(v). The NRC Resident Inspector and Lower Alloway Creek Township will be notified of this retraction. Notified R1DO (Trapp).
ENS 47549	23 December 2011 12:10:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation	Automatic Reactor Scram Due to a Turbine Trip	At 0610 CST on 12/23/2011 with the reactor at 100% power, River Bend Station experienced an (automatic) reactor scram resulting from a RPS actuation. Following the scram, reactor water level briefly lowered below level 3, resulting in the automatic closure of containment isolation valves in the suppression pool cooling system. This isolation was confirmed to have occurred as designed. The reactor is stable with pressure and temperature being controlled by the feed water system and main steam bypass valves, respectively. The cause of the scram was due to a turbine trip. Initial indications are that the turbine tripped due to a loss speed sensor. All control rods inserted and Reactor Core Isolation Cooling was manually operated for approximately 1 minute and secured, The plant is conducting causal investigations to fully understand the cause of the turbine trip. As information becomes available River Bend Station will provide additional information. This event is being reported in accordance with 10CFR50.72(b)(iv)(B) as an automatic RPS actuation with the reactor critical. The safety relief valves momentarily lifted immediately following the scram. The plant electrical distribution system is in a normal shutdown configuration. The scram was uncomplicated. The licensee notified the NRC Resident Inspector.
ENS 47547	8 November 2011 03:31:00	10 CFR 50.73(a)(1), Submit an LER	Invalid Specified System Actuation Due to a Possible Faulty Temperature Switch	This 60-day telephone notification is being made per the reporting requirements specified in 10 CFR 50.73(a)(2)(iv)(A) and 10 CFR 50.73(a)(1) to describe an invalid actuation signal affecting containment isolation valves in more than one system. On November 7, 2011, Nine Mile Point Unit 2 (NMP2) received a Division 2 reactor building pipe chase high ambient temperature isolation signal, which resulted in closure of isolation valves in the reactor water cleanup (RWCU) system, the reactor core isolation cooling (RCIC) system, and the residual heat removal (RHR) system (isolation valve groups 5, 6, 7, and 10). All affected isolation valves responded as designed. The Division reactor building pipe chase high ambient temperature isolation signal was generated by a new NUS/Scientech ambient temperature indicating switch that had recently been installed as a replacement for the original Riley temperature switch, which is no longer being manufactured. Two temperature switches (one for Division 1 and one for Division 2) monitor the reactor building pipe chase area to detect a rise in area temperature, which is indicative of a leak in the RWCU, RCIC, or RHR system piping that exists in the area. At the time of the event, operations personnel confirmed that conditions requiring isolation of the RWCU, RCIC, and RHR systems did not exist, based on a check of the Division 1 reactor building pipe chase high ambient temperature channel and area radiation monitors. Therefore, the isolation signal was determined to be invalid. The NUS/Scientech temperature switch was subsequently removed and the original Riley temperature switch was re-installed. The apparent cause for generation of the trip signal from the new temperature indicating switch was determined to be the presence of signal noise that was not adequately filtered. This event was entered into the (Nine Mile Point) corrective action system as Condition Report (CR) 2011-010062. There were no safety consequences or impact on the health and safety of the public as a result of this event. The licensee notified the NRC Resident Inspector.
ENS 47515	9 December 2011 23:35:00	10 CFR 50.72(b)(3)(v)(B), Loss of Safety Function - Remove Residual Heat	Part 21 Issue with Seismic Clips on Rcic System Controllers Results in System Inoperability	On December 7, 2011, a 10 CFR 21 report (reference NRC EN No. 47498) was received from a vendor for a defect with NUS Controllers. The defect involves spring clips that form part of the seismic restraints for the controllers. The controllers referenced in the report are installed for the Reactor Core Isolation Cooling (RCIC) system in the control room and remote shutdown panel. Based on initial information provided by the vendor, it was determined that the RCIC system remained operable. On December 9, 2011, additional information provided by the vendor did not support the immediate operability determination and the RCIC system was declared inoperable for Technical Specification (TS) Limiting Condition for Operation (LCO) 3.5.3 Condition A at 1835 hours (EST). At 1932 hours (EST), the High Pressure Core Spray system was verified operable per TS LCO 3.5.3 Required Action A.1. TS LCO 3.5.3 Required Action A2 requires restoration of the RCIC system to operable status within 14 days. Qualified spring clips have been obtained and will be installed on the controllers. This condition is being reported in accordance with 10 CFR 50.72(b)(3)(v)(B) as a condition that at the time of discovery could have prevented the fulfillment of the safety function of a system needed to remove residual heat. The NRC Resident Inspector has been notified. * * UPDATE FROM CHARLES ELBERFELD TO JOHN KNOKE AT 1415 EST ON 12/10/11 * * * As a follow-up to the condition reported above, we have replaced the affected seismic clips on the controllers and the Reactor Core Isolation Cooling system is now operable as of 0734 on December 10, 2011. The NRC Resident Inspector has been notified." R3DO (Skokowski) notified. * * RETRACTION FROM LLOYD ZERR TO CHARLES TEAL ON 2/6/12 AT 1504 EST * * * The vendor provided a seismic report to the station. This report showed that the seismic clips holding the Reactor Core Isolation Cooling (RCIC) controller meet the Operating Basis Earthquake (OBE) test requirements and design requirements for a Safe Shutdown Earthquake (SSE) for Perry. Based on this review, it was determined that the spring clips would function properly during and OBE and SSE. Because the condition reported in Event Number 47515 would not have prevented the fulfillment of the safety function of a system needed to remove residual heat, the condition is not reportable, and this notification is being retracted. The evaluation for this condition is documented in condition report 2011-06531. The NRC Resident Inspector has been informed." Notified R3DO (Giessner) and Part 21 Group via email.
ENS 47341	13 October 2011 14:00:00	10 CFR 50.72(b)(3)(ii)(B), Unanalyzed Condition	Fire Related Unanalyzed Condition That Could Impact Equipment Credited in Safe Shutdown Analysis	In preparation for converting from 10 CFR 50, Appendix R, to NFPA (National Fire Protection Association) 805, a review of the Brunswick Steam Electric Plant (BSEP) Safe Shutdown Analysis identified conditions that may not ensure a protected train of equipment remains available under certain postulated fire scenarios. The analysis determined that a postulated fire in specific fire areas could cause spurious actuation of critical components, potentially resulting in loss of equipment required for Safe Shutdown. A fire in one of the specified fire areas could potentially adversely affect the following; Suppression Pool level instrument 2-CAC-LT-2602, Residual Heat Removal net positive suction head (i.e., Drywell Containment Overpressure), Reactor Core Isolation Cooling (RCIC), Emergency bus E-1, and Emergency bus E-3. The initial safety significance of this event is minimal. Fire watches have been established for the affected portions of fire areas RB2-01, RB1-01, TB1, CB-02, and CB-23E. Additionally, fire detection and suppression equipment in the affected areas is fully functional. Fire watches have been established for the affected portions of fire areas RB2-01, RB1-01, TB1, CB-02, and CB-23E. This condition has been entered Into the Corrective Action Program (i.e., CR 493784). This is reportable as an unanalyzed condition that significantly degrades plant safety in accordance with 10 CFR 50.72(b)(3)(ii)(B). Compensatory measures have been established to provide an hourly fire watch for the affected fire areas. The licensee has notified the NRC Resident Inspector.
ENS 47328	6 October 2011 15:40:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Coolant Injection System Inoperable	On 10/06/2011 the control room was notified of an oscillation occurring on the output of Unit 2 High Pressure Coolant Injection (HPCI) pump electronic governor. These oscillations are occurring while the system is in standby and is an early indication of potential governor failure. The governor oscillations were discovered on 10/06/2011 at 1140 EDT by the system engineer while performing system trending analysis via plant computer points. HPCI was declared inoperable and LCO 3.5.1 was entered at 1140 EDT on 10/06/2011. An investigation is in progress. Unit 1 HPCI and both Unit 1 and Unit 2 RCIC (Reactor Core Isolation Cooling) systems are unaffected as the electronic governor outputs for this equipment is stable and trending as expected. This is being reported as a loss of an entire safety function condition in accordance with 10CFR50.72(b)(3)(V)(D). The licensee notified the NRC Resident Inspector.
ENS 47299	28 September 2011 09:14:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Automatic Reactor Scram Due to a Turbine Trip	At 0414 (CDT) on 9/28/2011, the Unit 3 reactor automatically scrammed due to actuation of the Reactor Protection System (RPS) from a turbine trip. Preliminary indications show the turbine tripped on a generator trip with generator neutral overvoltage (359GN) relay actuation. Cause of relay actuation is under investigation. Seven Safely Relief Valves (SRVs) cycled due to the reactor pressure transient with reactor pressure automatically controlled by the Main Turbine Bypass Valves. All systems responded as expected to the turbine trip. No Emergency Core Cooling System (ECCS) or Reactor Core Isolation Cooling (RCIC) reactor water level initiation set points were reached. Primary containment isolation and initiation signals for groups 2, 3, 6 & 8 were received as expected. Reactor water level is being automatically controlled by the feedwater system. This event is reportable within 4 hours per 10 CFR 50.72(b)(2)(iv)(B) 'any event or condition that results in actuation of the RPS when the reactor is critical except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation.' It is also reportable within 8 hours per 10 CFR 50.72(b)(3)(iv)(A) and requires an LER within 60 days per 10 CFR 50.73(a)(2)(iv)(A). The NRC Resident Inspector has been notified. All control rods fully inserted. The plant is being supplied from offsite power and is in a normal shutdown configuration. The MSIVs are open with decay heat being removed via steam to the main condenser using the bypass valves. There was no impact on Units 1 or 2.
ENS 46880	30 March 2011 19:43:00	10 CFR 50.73(a)(1), Submit an LER	60-Day Telephonic Notification of Invalid Rps Signal Due to Loss of Variable Leg of Level Transmitter	This 60-day telephone notification is being made per the reporting requirements specified by 10 CFR 50.73(a)(2)(iv) and 10 CFR 50.73(a)(1) to describe an invalid RPS (SCRAM) actuation. On March 30, 2011, at 1443 hours Central Daylight Time (CDT), during a refueling outage, Browns Ferry Unit 2 received an invalid Common Accident Signal (CAS) as a result of maintenance activities. The CAS caused a full Unit 2 Reactor SCRAM and associated system initiations. The CAS was initiated due to invalid indications on both Channels A and B of low-low-low reactor water level, which did not exist; therefore, the actuation was invalid. The affected equipment responded as designed. All four Unit 1/2 Emergency Diesel Generators auto started and all four Unit 3 Emergency Diesel Generators auto started. Unit 2 received a full Reactor SCRAM and Core Spray Pumps A, B, C, and D auto started and injected into the reactor. Unit 2 Division I Residual Heat Removal (RHR) System was in Shutdown Cooling with only the C pump in service. The 'A' RHR pump auto started and Shutdown Cooling flow increased, as expected. Unit 2 Division II RHR System had been tagged out for maintenance and did not respond. High Pressure Coolant Injection and Reactor Core Isolation Cooling received auto initiation signals; however, their steam isolation valves were tagged closed and the systems did not start. The Inboard Main Steam Isolation Valves (MSIVs) isolated as a result of the CAS signal. The outboard MSIVs had been previously closed and tagged for refueling outage purposes. This event was entered in the Corrective Action Program as Service Request (SR) 346544, which generated Problem Evaluation Report (PER) 346568. There were no safety consequences or impact on the health and safety of the public as a result of these events. The NRC Senior Resident Inspector has been notified. The shutdown reactor water level transmitters share a common variable leg. When maintenance unrelated to the transmitters was performed, the variable leg was lost causing the low-low-low reactor water level SCRAM signal to be generated.
ENS 46793	27 April 2011 22:01:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(a)(1)(i), Emergency Class Declaration 10 CFR 50.72(b)(3)(xiii), Loss of Emergency Preparedness	Notification of Unusual Event Due to Loss of Offsite Power	At 1701 CDT, the licensee declared a Notification of Unusual Event under Emergency Action Level 5.1U due to loss of offsite power for >15 minutes. The loss of offsite power occurred at 1635 CDT and was due to severe weather and winds in the vicinity. When offsite power was lost, all 3 units automatically scrammed. The units are currently stable in Mode 3 with their respective 4KV busses being supplied by the onsite Emergency Diesel Generators(EDG). The 161KV Athens line is the only offsite power source energized. All onsite safe shutdown equipment is available with the exception of the Unit 3 "B" EDG which was out of service for planned maintenance. * * UPDATE FROM BILL BAKER TO HOWIE CROUCH AT 1942 EDT ON 4/27/11 * * * The system actuations that occurred during the loss of offsite power were actuations of the Reactor Protection System, Primary Containment Isolation System (PCIS) and Emergency Diesel Generators. All primary containment valves actuated by the PCIS operated as expected. Unexpectedly, the Unit 3 "B" Main Steam Isolation Valve indicates intermediate. Unit 1 High Pressure Coolant Injection actuated when reactor water level reached -45". Reactor Core Isolation Cooling (RCIC) was already initiated at the time. * * UPDATE FROM BILL BAKER TO S. SANDIN AT 2153 EDT ON 4/27/11 * * * Following the loss of offsite power only 12 of the required 100 offsite emergency sirens are operable. The licensee will inform both state/local agencies and the NRC Resident Inspector. Notified R2IRC (Wert) of this update. * * UPDATE FROM BILL BAKER TO HOWIE CROUCH AT 2303 EDT ON 4/27/11 * * * As a result of the loss of offsite power, the Diesel-driven Fire Pump auto-started. While the pump was running, the licensee discovered that approximately one quart of oil had leaked from the fire pump into the cold water channel which discharges into navigable waterways. The licensee confirmed this at 1950 CDT by visually identifying a sheen in the channel. The licensee notified the National Response Center of the spill and, in accordance with their site discharge permit, notified the State of Alabama. This constitutes an Offsite Notification in accordance with 10CFR50.72(b)(2)(xi). The licensee notified the NRC Resident Inspector. Notified NRC R2IRC (Wert). * * UPDATE FROM BILL BUTLER TO HOWIE CROUCH AT 2338 EDT ON 4/27/11 * * * At 2120 CDT, operators on Unit 1 were controlling reactor water level between 2 and 51 inches when RCIC became sluggish and water level dropped to +2" causing a valid RPS Scram signal as well as PCIS signals 2, 3, 6, and 8. All valves operated as expected and all isolations were completed. The licensee notified the NRC Resident Inspector. Notified NRC R2IRC (Wert). * * * UPDATE FROM WILLIAM BAKER TO CHARLES TEAL AT 2338 EDT ON 4/28/11 * * * At 1635 CDT following offsite power grid oscillations (due to inclement weather), and a subsequent Unit 1 power reduction from 100% to 75% to attempt to correct the condition, BFNP experienced a complete loss of the 500kV offsite power system. This resulted in an automatic turbine trip and reactor scram of Units 1, 2 and 3. One 161 kV offsite power system (Athens) remains available. This condition is reportable IAW 10CFR50.72(b)(2)(iv)(B) - Any event or condition that results in actuation of the reactor protection system (RPS) when the reactor is critical except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation (4-hour notification). This notification was reported to NRC (Crouch) at 1723 CDT. At 1701 CDT, a NOUE was declared (EAL Designator 5.1-U) due to loss of normal and alternate voltage to all 4kV SD (Shutdown) Boards for greater than 15 minutes and at least two Diesel Generators supplying power to unit specific 4kV SD Boards. This condition is reportable IAW 10CFR 50.72(a)(1)(i) - The declaration of any of the emergency classes specified in the licensee's emergency plan (1-hour notification). This notification was reported to NRC (Crouch) at 1723 CDT. Following the initial scrams, there were valid actuation signals for RPS (U1/2/3), Containment Isolation Groups 2, 3, 6 and 8 (U1/2/3), HPCI (U1 only), and Emergency Diesel Generators A, B, C, D, 3A, 3C and 3D (EDG 3B is out of service for maintenance). MSIV's (U1 and 3) closed on loss of A and B RPS power, and the U3 B inboard MSIV is indicating 'double lit' (not fully closed) at this time. All other systems responded as expected. This condition is reportable IAW 10CFR50.72(b)(3)(iv)(A) - Any event or condition that results in the valid actuation of any of the systems listed in paragraph (b)(3)(iv)(B), except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation (8-hour notification). The systems with a valid actuation were RPS, Containment Isolation, HPCI and Emergency Diesel Generators. This was reported in an EN# 46793 update to NRC (Crouch) at 1842 CDT. At 1820 CDT a determination was made that offsite emergency notification sirens did not meet the minimum required number operable. Seventy of the one hundred sirens are required to be operable and twelve of the sirens are operable at this time. This condition is reportable IAW 10CFR50.72(b)(3)(xiii) - Any event that results in a major loss of emergency assessment capability, offsite response capability, or offsite communications capability (e.g., significant portion of control room indication, emergency notification system, or offsite notification system) (8-hour notification). This was reported in an EN# 46793 update to NRC (Crouch) at 2053 CDT. Following auto-start of the diesel driven fire pump, subsequent to the loss of offsite 500kV power system, approximately one quart of oil leaked from the drain plug in the diesel engine of the pump to the plant cold water channel (waters of the United States). This oil produced a "sheen" on the water (confirmed at 1950 CDT) that required a response to the National Response Center IAW 40CFR112.7(a)(4). This condition was reported to the National Response Center at 2055 CDT and assigned spill number 974232. In addition, IAW the BFNP NPDES (National Pollution Discharge Elimination System) permit, the State of Alabama was notified at 2100 CDT of the spill and subsequent notification of the National Response Center. The notification of these outside agencies is reportable IAW 10CFR50.72(b)(2)(xi) - Any event or situation, related to the health and safety of the public or onsite personnel, or protection of the environment, for which a news release is planned or notification of other government agencies has been or will be made. Such an event may include an onsite fatality or inadvertent release of radioactive contaminated materials (4 hour notification). This was reported in an EN# 46793 update to NRC (Crouch) at 2203 CDT. At 2120 CDT, Unit 1 received a low reactor water level scram due to reactor water level lowering to +2 inches following sluggish RCIC response at low reactor pressure. At the time of this event RCIC and CRD were injecting to the vessel and the reactor level band specified was +2 to +51 inches. A valid Containment Isolation signal was received and groups 2, 3, 6 and 8 isolated as expected. Water level was immediately restored to within the specified band (RCIC). This condition is reportable IAW10CFR 50.72(b)(3)(iv)(A) - Any event or condition that results in the valid actuation of any of the systems listed in paragraph (b)(3)(iv)(B), except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation (8-hour notification). The systems with valid actuations were RPS and Containment Isolation. The Emergency Diesel Generators were already running at the time of the event. This was reported in an EN# 46793 update to NRC (Crouch) at 2238 CDT. The NRC resident has been notified of these 1, 4 and 8 hour reports and EN#46793 updates. These conditions and notifications will be captured in the licensee's Corrective Action Program. * * UPDATE FROM GIVENS TO HUFFMAN AT 2200 EDT ON 5/2/11 * * * At 2050 CDT, on 05/02/2011, the previously declared and reported NOUE (EAL Designator 5.1U) due to loss of normal and alternate voltage to all 4kV SD Boards for greater than 15 minutes and at least two Diesel Generators supplying power to unit specific 4kV SD Boards was terminated due to the conditions requiring entry being resolved. At this time, offsite power has been restored from two 161kV sources (Athens and Trinity), all eight 4kV SD boards are being powered from offsite sources, and six of eight Emergency Diesel Generators (B, C, D, 3A, 3C, 3D) are operable and in standby readiness. Emergency Diesel Generators A and 3B are not operable but are available at this time. All three units remain shutdown, in Mode 4, pending return of the 500 kV grid system. A timeline for return of the 500 kV grid system is yet to be finalized. In addition, the previous 8-hour notification of offsite emergency sirens not meeting the minimum required is being updated to reflect current conditions. As of 1015 CDT, on 05/02/2011, repair activities have resulted in 92 of 100 sirens being in operable status, thereby meeting the minimum requirement of 70 operable. The licensee has notified the NRC Resident Inspector and the State of Alabama. Notified R2DO (Seymour), NRR EO (Nelson), IRD (Grant), DHS (Daly), and FEMA (Dennis).
ENS 46763	17 April 2011 02:52:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Hpci Inoperable Due to Lube Oil Pressure Low Out of Band	Event Description: On 4/16/2011 at 2252 (EDT), the Unit 2 High Pressure Coolant Injection (HPCI) System was declared inoperable due to the determination that its Lube Oil System was not providing adequate lube oil pressure and flow to the HPCI Turbine/Pump bearings. This was determined following the high steam pressure operability run (i.e., within 48 hours of achieving adequate test pressure following a scheduled refueling/maintenance outage) as required by Technical Specification Surveillance Requirement 3.5.1.7. The HPCI system is inoperable in accordance with Technical Specification 3.5.1. This report is being made in accordance with 10 CFR 50.72(b)(3)(v)(D), as a condition that at the time of discovery could have prevented the fulfillment of the safety function of systems that are needed to mitigate the consequences of an accident. Initial Safety Significance Evaluation: The safety significance of this event is considered minimal. The Reactor Core Isolation Cooling (RCIC) system, Automatic Depressurization System (ADS). and Low Pressure Emergency Core Cooling systems (ECCS) remain operable at this time. Actions have been taken to protect redundant safety systems. Corrective Actions: The HPCI system remains inoperable pending further troubleshooting of the low lube oil pressure condition. The NRC Resident Inspector has been notified. * * RETRACTION FROM LEE GRZECK TO HOWIE CROUCH AT 2051 EDT ON 4/17/11 * * * Upon further review, it has been determined that the HPCI system was not rendered inoperable as a result of the condition identified on April 16, 2011. During performance of 0PT-09.2, the Control Room received a HPCI turbine bearing oil pressure low alarm. Following 0PT-09.2, preventive maintenance procedure 0PM-TRB507, 'High Pressure Coolant Injection (HPCI) Operational Inspection', was performed. During performance of 0PM-TRB507, the turbine governor end oil pressure was found indicating 8.5 psig. The procedure specifies a normal value of 10-12 psig. Due to the above condition, HPCI was conservatively declared inoperable at 2252 (EDT) on April 16, 2011. Subsequent Engineering evaluation has determined that HPCI could have run long enough to complete its intended safety function (24 hrs.). Pressure outside of the normal band specified in 0PM-TRB507 is a condition that requires correction, but is not detrimental to the bearing itself. The critical characteristic of proper bearing lubrication is to assure a film of oil between the tilting pads and the rotating shaft of the HPCI turbine. Bearing outlet temperatures are recorded during each performance of 0PT-092 for trending and no abnormal temperatures were noted during the last performance of 0PT-09.2 on April 16, 2011. This indicates there was a film of lubrication between the rotating shaft and the tilting pads of the journal bearing. The two hour turbine operation of the most recent 0PT-09.2 performance resulted in higher oil temperature, which can result in lower oil pressure. Adjustments can be made to the ball valve of the HPCI governor end bearing to attain the specified supply pressure to each bearing. These adjustments are not unexpected, as discussed in the Electric Power Research Institute (EPRI) maintenance guide for HPCI turbines. A slight adjustment was made to the HPCI governor end bearing on April 17, 2011 to establish pressure at 11.5 psig. At 1009 hrs. on April 17, 2011, 0PT-09.2 was performed satisfactorily, with the HPCI governor end oil bearing supply pressure verified to be within the 10-12 psig range at 2100 rpm and 4100 rpm. Oil flow to and from the bearing is required only for lubrication and cooling and does not provide any lift or other force to assist the bearing in performing its function. The oil flow during this event was still adequate to provide sufficient lubrication and cooling of the bearings. Therefore, the slight decrease in oil pressure to the HPCI governor end bearing did not indicate degradation in performance. On this basis, the HPCI system was capable of performing its safety function to mitigate the consequences of an accident and this issue is not reportable under 10 CFR 50.72(b)(3)(v)(D). Investigation of this condition is documented in the corrective action program in Nuclear Condition Report (NCR) 460134. The NRC Resident Inspector was notified of this retraction. Notified R2DO (O'Donohue).
ENS 46605	10 February 2011 00:04:00	10 CFR 50.72(b)(2)(i), Tech Spec Required Shutdown 10 CFR 50.72(b)(3)(ii)(A), Seriously Degraded	Pressure Boundary Leakage	At 1830 CST on 02/09/11, LaSalle Unit 1 commenced a Technical Specification required plant shutdown, due to identification of pressure boundary leakage. At 1804 CST on 02/09/11, it was identified that 1E51-F076, Reactor Core Isolation Cooling System Steam Supply Inboard Isolation Bypass Warmup Valve, had a one inch crack in a weld on the pressure seal joint. This qualifies as pressure boundary leakage, which requires entry into Tech Spec 3.4.5, RCS Operational Leakage, Required Action C, to be in Mode 3, Hot Shutdown, by 0604 on 02/10/11, and Mode 4, Cold Shutdown, by 0604 on 02/11/11 . At the time of discovery, Unit 1 was in startup mode following a forced outage. A repair plan is being prepared at this time and the Unit will remain in cold shutdown until repairs are complete. This is an unisolable leak. Reactor pressure is 913 psig. The licensee notified the NRC Resident Inspector.
ENS 46521	5 January 2011 06:20:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Reactor Core Isolation Cooling Declared Inoperable	On January 5, 2011, at 0120 hours, with the reactor at 100% thermal power and steady state conditions, Pilgrim Nuclear Power Station (PNSP) declared the Reactor Core Isolation Cooling (RCIC) system inoperable due to the RCIC suction isolation valve from the Torus/Suppression Pool (RCIC-26) failing to go fully closed during planned surveillance testing. The RCIC-26 is a motor-operated valve (MOV) and its normal position is closed. The RClC-26 valve is redundant to the RCIC-25 valve, and is not the credited containment isolation valve. The RCIC-26 valve has a safety function to be (manually) opened during certain event mitigation scenarios requiring a transfer of suction sources from the Condensate Storage Tank (CST) to the Torus. Based on the valve failing to fully close during MOV stroke time testing per PNPS Procedure 8.5.5.4, the RCIC system was declared inoperable at 0120 hours and the appropriate LCO was entered. The RCIC-26 was subsequently returned to a full open position, caution tagged and the RCIC system was declared operable. The LCO was exited at 0200 hours. An investigation of the event is underway and continuing. This event had no impact on the health and/or safety of the public. The NRC Resident Inspector is on-site and has been notified. This is an 8-hour notification made in accordance with 50.72(b)(3)(v)(D). The licensee will notify the State of Massachusetts. * * RETRACTION FROM JOSEPH LYNCH TO JOHN KNOKE AT 1946 EST ON 3/4/11 * * * Event Notification 46521 was conservatively made to ensure that the Eight-Hour Non-Emergency reporting requirements of 10 CFR 50.72 were satisfied pending the evaluation of RCIC System operability. On 01/05/11, at 0120 hours the RCIC System was declared inoperable due to uncertainty of RCIC System Operability when the Torus/Suppression Pool Suction Valve (RCIC-26) failed to go fully closed during planned surveillance testing. The valve was restored to the full open position and the valve was declared operable based on capability to meet the required safety function to fully open when RCIC pump suction from the suppression pool is required. The apparent cause evaluation concluded that valve failure was the result of high relay contact resistance in the closing control circuit components of the valve breaker. This failure prevented the valve from fully closing but had no affect on capability to open the valve. Surveillance testing verified that capability to open the valve was not affected. Corrective action was completed to clean or replace the control circuit relay contacts. Post work testing confirmed capability to open and close the valve. An extent of condition for similar breaker control circuit components was also performed. All relevant technical information is documented in the corrective action system. The failure observed did not affect the valve's required safety function and did not impact RCIC System operability. Thus there was no impact on nuclear safety. This event is not reportable pursuant to 10 CFR 50.72(b)(3)(v)(D) . Event Number 46521, made on 01/05/2011, is being retracted. The licensee has notified the NRC Resident Inspector. Notified R1DO (Anthony Dimitriadis)
ENS 46355	23 October 2010 04:45:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Hpci Declared Inoperable Due to Power Supply Failure	The High Pressure Coolant Injection (HPCI) system was declared inoperable due to an instrument power supply failure. The cause of the failure is under investigation. All other ECCS, Emergency Diesels, and Reactor Core Isolation Cooling (RCIC) are operable. The licensee has notified the NRC Resident Inspector.
ENS 46220	26 July 2010 23:19:00	10 CFR 50.73(a)(1), Submit an LER	60-Day Telephonic Notification in Lieu of a Written Licensee Event Report of Invalid Actuation	On July 26, 2010, at 1819 hours (CDT), with Unit 1 in Mode 1 (Run), the Division 1 Diesel Generator Cooling Water Pump (DGCWP) restarted after being secured. The DGCWP provides the Emergency Service Water to the 1A Residual Heat Removal (RHR) pump room area cooler and the Reactor Core Isolation Cooling (RCIC) water pump/Low Pressure Core Spray (LPCS) pump room area cooler. The apparent cause of the restart was the momentary interruption of the DGCWP run logic. The Division 1 DGCWP was in operation to support cooling of the Unit 1 RCIC/LPCS pump room area (run logic satisfied). When the Operator placed the Division 1 DGCWP control switch to the normal-after-stop position, the DGCWP feed breaker opened. The Operator reset the DGCWP feed breaker trip by returning the control switch to the normal-after-stop position and, because the run logic for the DGCWP was still satisfied (due to elevated room temperatures), the DGCWP restarted. This invalid start signal from the Division 1 DGCWP breaker being reset resulted in the automatic actuation of the Division 1 DGCWP. The Division 1 DGCWP responded satisfactorily. This report is being made in accordance with 10CFR50.73(a)(1), which states that in the case of an invalid actuation reported under 10CFR73(a)(2)(iv)(A), other than an actuation of the Reactor Protection System (RPS) when the reactor is critical, the licensee may provide a telephone notification to the NRC Operations Center with 60 days after discovery of the event instead of submitting a written LER. The licensee has notified the NRC Resident Inspector.
ENS 45990	9 June 2010 08:31:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Reactor Scram Due to Closure of Main Steam Isolation Valves	At 0331 CDT on 6/9/10, the Unit 2 reactor automatically scrammed due to closure of the Main Steam Isolation Valves (MSIVs). Operating Instruction 2-OI-99 section 8.1, Reactor Protection System (RPS) Bus B Transfer from Motor Generator to Alternate, was in progress for planned maintenance. The MSIVs closed during the RPS power transfer. The cause of the closure of the MSIVs is under investigation. All systems responded as expected to the reactor scram. Safety Relief Valves (SRVs) opened automatically as designed to limit the pressure transient. No Emergency Core Cooling System (ECCS) or Reactor Core Isolation Cooling system (RCIC) reactor water level initiation set points were reached and all expected containment isolation and initiation signals were received. Reactor pressure control was established by manually operating one SRV then maintained using the Main Steam Line Drain Valves. RCIC and the High Pressure Coolant Injection system (HPCI) were manually initiated to control reactor water level. The scram was reset, MSIVs were opened, and the Main Condenser was established as a heat sink. Reactor water level control was established with the Reactor Feedwater System and RCIC and HPCI were returned to standby readiness. At 0408 CDT on 6/9/10, a full scram signal was received when 2F Intermediate Range Monitor (IRM) spiked momentarily followed by a spike on 2C IRM. The reactor was stable and operating in Mode 3, Hot Shutdown. No ECCS or RCIC initiation set points were reached. No additional containment isolation signals or initiation set points were received. The cause of the 2C and 2F IRM spikes is under investigation. The scram event from critical is reportable within 4 hours per 10CFR 50.72(b)(2)(iv)(B), 'any event or condition that results in actuation of the reactor protection system (RPS) when the reactor is critical except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation.' It is also reportable within 8 hours per 10CFR 50.72(b)(3)(iv)(A) and requires an LER within 60 days per 10CFR 50.73(a)(2)(iv)(A). The scram received at 0408 CST is reportable within 8 hours 10CFR 50.72(b)(3)(iv)(A), 'any event or condition that results in valid actuation of any of the systems listed in paragraph (b)(3)(iv)(B), except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation,' and requires an LER within 60 days per 10CFR 50.73(a)(2)(iv)(A). The NRC Resident Inspector was notified. All rods fully inserted as a result of the first reactor scram. The plant is currently in a normal, post-trip electrical line-up. All SRVs did reseat. There was no impact to the other two units. * * * UPDATE FROM BILL BAKER TO PETE SNYDER ON 6/10/10 AT 1749 EDT * * * Additional review of available data and inspection results revealed that Safety Relief Valves (SRVs) did not lift automatically during the scram. The only operations of SRVs were performed manually to control reactor pressure until the Main Steam Isolation Valves (MSIVs) were reopened. All other details described in the original event notification remain as stated. The licensee notified the NRC Resident Inspector. Notified R2DO (Nease).
ENS 45979	6 June 2010 06:38:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(a)(1)(i), Emergency Class Declaration	Automatic Reactor Scram Due to Partial Loss of Offsite Power	Reactor shutdown. All control rods inserted. Maintaining reactor vessel level with reactor core isolation cooling. Maintaining reactor vessel pressure with reactor core isolation cooling. (Automatic) Reactor scram due to loss of division 2 offsite power. Classification code: Unusual Event (HU1) Natural Destruction Phenomena Affecting the Protected Area. The licensee declared a Notification of Unusual Event at 0253 EDT. All rods fully inserted and decay heat is being removed by the main condensers. Division 1 buses are being powered by 1 of 3 offsite feeds and division 2 buses are being powered by the Emergency Diesel Generators. The licensee has notified the NRC Resident Inspector. * * UPDATE FROM JEFF GROFF TO DONG PARK AT 0425 EDT ON 6/6/2010 * * * Division 2 power provided by Emergency Diesel Generators number 13 and 14. Classification Alert Code: (HA1) Natural Destruction Phenomena Affecting the Plant Vital Area. Main condenser is the heat sink. The licensee declared an Alert at 0417 EDT. The reactor remains stable in Mode 3. Physical damage to the auxiliary and the turbine buildings were noticed after an initial inspection. The licensee has notified the NRC Resident Inspector. Notified R3RA (Satorius), NRR (Grobe), IRD (Morris), R3DO (Pelke), NRR EO (Galloway), DHS (Doyle), FEMA (Guy), DOE(Morrone), USDA (Ussery), HHS (Standifer), and CNSC (Gdesnryxrs). * * UPDATE FROM JEFF GROFF TO DONG PARK AT 0603 EDT ON 6/6/2010 * * * At 0238 (EDT), severe weather caused a loss of 345KV (switchyard power). Reactor scrammed from a turbine trip. Plant is stabilized with RPV (Reactor Pressure Vessel) water level in normal band and RPV pressure at 820 psig. RPV Pressure is being controlled on turbine BPV (By Pass Valve). Division 2 EDG's (Emergency Diesel Generator) are supplying power to division 2 buses. Plant is currently in Alert due to physical damage to plant due to severe weather. The NRC Senior Resident Inspector is on-site. Notified IRD (Morris), R3DO (Pelke), NRR EO (Galloway). * * UPDATE FROM ED KOKOSKY TO DONG PARK AT 0247 EDT ON 6/7/2010 * * * There is no release of radiological materials. No further potential exists for uncontrolled release of radioactive materials to the environment. The Reactor is shut down. Reactor pressure and temperature are within normal bands. Offsite electrical feeds to the site have been restored. An overall damage assessment has been prepared and reviewed to ensure no conditions exist that would create an entry condition to the Emergency Plan. Plant repairs will be accomplished through site processes. At 0220 EDT on 6/7/10, the licensee has terminated from the Alert classification. The licensee has notified the NRC Resident Inspector. Notified R3RA (Satorius), NRR (Grobe), IRD (Grant), R3DO (Pelke), NRR EO (Galloway), DHS (Doyle), FEMA (Blankenship), DOE(Bailey), USDA (Ussery), HHS (Peagler), and CNSC (Gdesnryxrs).
ENS 45902	5 May 2010 15:44:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Automatic Reactor Scram Due to Reactor Feed Pump Trip	On May 5, 2010, at 1144 hours Eastern Daylight Time (EDT), an automatic reactor scram occurred on Unit 1 following a trip of the 1B Reactor Feed Pump (RFP). Following the 1B RFP trip, the reactor recirculation pumps did not run back as expected. The resulting water level shrink caused level in the Reactor Pressure Vessel (RPV) to drop to Low Level 1, causing the activation of the Reactor Protection System (RPS) and the Primary Containment Isolation System (PCIS). All control rods properly inserted. PCIS Group 2 (i.e., Drywell Equipment and Floor Drain, Residual Heat Removal (RHR) Discharge to Radwaste, and RHR Process Sample), Group 6 (i.e., Containment Atmosphere Control/Dilution, Containment Atmosphere Monitoring, and Post Accident Sampling Systems), and Group 8 (i.e., RHR Shutdown Cooling) isolation signals were received on Low Level 1. Actuations of the Primary Containment Isolation Valves (PCIVs) were completed and the affected equipment responded as designed. Due to the expected RPV level reduction following a reactor scram, water level in the RPV momentarily reached Low Level 2. This initiated the High Pressure Coolant Injection (HPCI) System, the Reactor Core Isolation Cooling (RCIC) System, and a partial Group 3 PCIS (i.e., RWCU) isolation. The HPCI and RCIC systems did not inject. The 1-G31-F001 isolated (i.e., inboard isolation) but 1-G31-F004 (i.e., outboard isolation) did not automatically isolate. Based on a preliminary assessment, this response appears to be in accordance with plant design. Further assessments of plant response are on-going to validate plant response. The licensee has notified the NRC Resident Inspector. The scram was uncomplicated. No SRVs lifted. Decay heat removal is via the 'A' feed water pump via the turbine bypass valves to the condenser. The electrical line-up of Unit 1 is normal. Brunswick Unit 2 was not affected.
ENS 45879	28 April 2010 18:00:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Rcic Declared Inoperable Due to Oil Leak on Governor System	On 04/28/10, at 1400 EDT, with the reactor at 100% power, the Reactor Core Isolation Cooling (RCIC) system was declared inoperable by the Shift Manager (SM) due to an oil leak on the RCIC governor control oil system that could have impacted the system performance during the accredited 24 hour mission time. The fitting where the oil leakage was observed was tightened and the machine was placed in service with no leakage identified. Currently the system is operable and in its normal standby lineup. The system was available for use during this time. At no time was there an impact to the health and safety of the public. The licensee has notified the NRC Resident Inspector. * * RETRACTION FROM JOHN WHALLEY TO HOWIE CROUCH @ 1300 EDT ON 5/28/10 * * * On April 28, 2010, at 1940 hours, Pilgrim Nuclear Power Station (PNPS) made an 8-hour non-emergency 50.72 notification, Event Notification EN# 45879. The notification was made in accordance with 50.72 (b)(3)(v)(D), Accident Mitigation. Earlier on April 28, 2010, at 1400 hours, a minor oil leak had been identified on the Reactor Core Isolation Cooling (RCIC) system at a lubricating oil vent fitting. The leak was immediately repaired by properly tightening the fitting, then running RCIC to verify no active leak existed. However in the interim, the Shift Manager conservatively declared RCIC inoperable when the high standard for operability could not be assured by initial system engineering judgment for the impact of the oil leak on RCIC system performance in consideration of mission time. Subsequent engineering evaluation concluded that the observed leak, conservatively assumed to be one drop per 3 minutes, would not have impacted RCIC operability for the duration of its required 24 hour mission time. All relevant technical information is documented in the PNPS corrective action system. Therefore PNPS is retracting the event notification EN# 45879. The USNRC Resident Inspector Office has been notified of this retraction. Notified R1DO (Dwyer).
ENS 45866	22 April 2010 14:51:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Reactor Scram on Low Reactor Vessel Water Level During Feedwater Integrated Control System Testing	At 10:51 on 4/22/10, Susquehanna Unit 1 experienced an automatic reactor SCRAM on reactor low level, +13", during the initial testing of the Feedwater Integrated Control System. Following the SCRAM, reactor water level dropped to approx. -30", and the Reactor Core Isolation Cooling system initiated and injected into the vessel. Level was recovered by the Feedwater System and the RCIC system. Division 2 Alternate Rod Insertion unexpectedly initiated during the level transient. Due to scheduled maintenance activities, the 11B Aux Bus did not transfer to the off site power supply post SCRAM. The 11B Aux bus was restored at 12:17. There were no ECCS initiations and no challenges to containment. This event is a Reactor Protection System (RPS) actuation when the reactor is critical, and is reportable as a four hour ENS Notification under 10 CFR 50.72(b)(2)(iv)(B). This event is also an unplanned actuation of a system used to mitigate the consequences of a significant event and is reportable as an eight hour ENS notification under 10CFR50.72(b)(3)(iv)(A). The scram was described as uncomplicated. All rods fully inserted and all systems functioned as required. The initiation of the alternative rod insertion should not occur unless level drops below -38" but the initiation did not result in any complications. The offsite supply breaker to Aux bus 11B was under maintenance when the scram occurred and so the loss of power was expected. This bus supplies some balance of plant loads which were lost (recirculation pump, condensate pump, and circulating water pump) but the loss of these components had no impact on the transient. The NRC Resident Inspector has been notified. The licensee will notify State authorities and also plans a press release.
ENS 45815	6 April 2010 02:50:00	10 CFR 50.72(b)(3)(v)(C), Loss of Safety Function - Release of Radioactive Material	Loss of Safety Function to Control the Release of Radioactive Material	At 2145 (EDT) hours on April 5, 2010, a loss of electrical power to the Division 1 Loss of Coolant Accident (LOCA) initiation logic occurred. Control room annunciators for 'Residual Heat Removal (RHR) Out of Service', 'Reactor Core Isolation Cooling (RCIC) Out of Service', and 'RCIC/RHR D2 to D1 00 File Power Loss' were received. At 2250 hours, the Control Room staff determined a loss of isolation function existed. The operators entered Technical Specification (TS) action statements for Emergency Core Cooling System Instrumentation (TS 3.3.5.1), RCIC Instrumentation (TS 3.3.5.2), and Primary Containment and Drywell Isolation Instrumentation (TS 3.3.6.1). The power loss was caused by a blown fuse which occurred during surveillance testing. The surveillance test was suspended and plant personnel commenced troubleshooting and investigation efforts. A recovery plan is being developed to back out of the surveillance test and replace the fuse to re-energize the logic, while ensuring the plant does not experience an undesirable actuation of the logic. The power loss caused five containment isolation valves to lose automatic isolation function. These valves have no associated inboard automatic isolation valve powered by Division 2. As a result of the power loss, the valves cannot automatically close on demand to isolate and therefore cannot perform their automatic function to isolate the containment. This event is being reported in accordance with 10 CFR 50.72(b)(3)(v)(C) as an 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 control the release of radioactive material. The NRC Resident Inspectors have been notified. The licensee entered a 12-hour shutdown action statement for the loss of containment isolation function as a result of the power failure. * * * RETRACTION FROM LLOYD ZERR TO PETE SNYDER ON 6/4/2010 AT 1126 * * * On April 6, 2010, at 0611 hours, notification was made to NRC Operations Center of an event that at the time of discovery, could have prevented the fulfillment of the safety function of structures or systems that are needed to control the release of radioactive material (10 CFR 50.72(b)(3)(v)(c)). A blown fuse during surveillance testing caused a loss of electrical power to the Division 1 Loss of Coolant Accident initiation logic. The power loss caused five containment isolation valves to lose their automatic isolation function. These valves have no associated inboard automatic isolation valve powered by Division 2. As a result of the power loss, the valves could not automatically close on demand and therefore, could not perform their automatic function to isolate containment. Following further evaluation, it was determined that a loss of safety function of structures or systems that are needed to control the release of radioactive material did not occur. Based on review of valve leak rate test history and compliance with 10 CFR 50, Appendix A, General Design Criteria, the penetrations and Containment were capable of performing their intended design function. The associated inboard valves and/or water seals were capable of automatically isolating containment. Additionally, all required Technical Specifications Limiting Conditions for Operation were complied with for the identified issue, and therefore, no operation or condition prohibited by the plant's Technical Specifications existed. Since the event or condition reported in Event Notification 45815 would not have prevented the fulfillment of the safety function needed to control the release of radioactive material, this event or condition is not reportable and the notification is retracted. Additionally, based on not meeting any 10 CFR 50.73 reporting criteria, no Licensee Event Report is required. The evaluation (i.e., Reportability Determination) for this event or condition is documented in Condition Report 10-74904. The NRC Resident Inspector has been notified. Notified the R3DO (Pelke).
ENS 45732	27 February 2010 06:58:00	10 CFR 50.72(b)(3)(iv)(A), System Actuation	Reactor Core Isolation Cooling (Rcic) System Manually Started to Maintain Reactor Pressure Vessel Level Following a Pre-Planned Reactor Scram	On February 27, 2010, at 0116 hours, as part of a pre-planned sequence of events, Unit 1 control room operators manually inserted a Reactor Protection system trip to shut down the reactor from approximately 21 percent of rated thermal power to begin a planned refuel outage. At 0158 hours, the Reactor Core Isolation Cooling (RCIC) system was manually started to maintain reactor pressure vessel (RPV) coolant level after the 1A Reactor Feedwater Pump (RFP) was shutdown due to high turbine casing drain level, and the 1B Reactor Feedwater Pump (RFP) had been removed from service and isolated to support maintenance activities. The Reactor Core Isolation Cooling (RCIC) system started and maintained reactor pressure vessel (RPV) coolant level until the 1B Reactor Feedwater Pump (RFP) could be returned to service at 0248 (hours). The Reactor Core Isolation Cooling (RCIC) system was shutdown at 0306 (hours). The safety significance of this occurrence is considered minimal. The RCIC system is designed to operate either automatically or manually following RPV isolation, accompanied by a loss of normal coolant flow from the Reactor Feedwater system, to provide adequate core cooling, and control of the RPV coolant level. The function of the RCIC system is to respond to transient events by providing makeup coolant to the reactor. For this event, the RPV was not isolated, but there was a loss of normal coolant flow from the Reactor Feedwater System. The RCIC system was manually started and successfully controlled RPV coolant level for approximately 68 minutes until Reactor Feedwater system flow could be restored to the RPV. All emergency core cooling systems were operable and ready for use, if needed, during this event. This transient is bounded by the analyses in the Updated Final Safety Analysis Report. RPV level remained in the normal post-shutdown band of 170-200 inches during the transient. The licensee informed the NRC Resident Inspector.
ENS 45541	5 December 2009 15:59:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Hpci Out of Service Due to the Loss of the Suction Auto-Swap Function	On 12-04-09 at 16:00, condensate storage tank (CST) level switch (2E41 N002), was declared inoperable due to not actuating at the correct set point. A RAS (Required Action Statement) was entered to align high pressure coolant injection (HPCI) suction to the suppression pool within 24 hours as required by Tech Spec (Technical Specification) action statement 3.3.5.1.D 2.2. The switch was found stuck and was freed up after manual manipulation and tripped correctly during a functional test. It was decided on 12-05-09 to perform a calibration on the level switch prior to declaring it operable. During performance of calibration procedure 57CP-CAL-012-2 at 1059 EST on 12-05-09, a jumper was installed that rendered the HPCI and reactor core isolation cooling (RCIC) auto-transfer suction swap from CST to suppression pool inoperable. This is a loss of function for the initiation capability of HPCI and RCIC CST low level suction swap instrumentation. This loss of function was not discovered until 1330 on 12-05-09, at which time TS (Technical Specification) 3.3.5.1.D was entered for HPCI and TS 3.3.5.2.D for RCIC, until HPCI and RCIC suction were manually aligned to the suppression pool which allowed the plant to exit the required actions to declare HPCI and RCIC inoperable within 1 Hour. HPCI and RCIC were aligned to the suppression pool at 1341 EST. The RCIC suction was realigned to the suppression pool as required by the Tech Specs in order to restore its operability. It should be noted that no credit is taken for RCIC in the safety analysis nor is this system considered an ESF system. For this reason there are no reporting requirements associated with the inoperability of RCIC. HPCI was declared inoperable in accordance with the instrumentation Tech Specs, but during this time frame HPCI was capable of performing its safety function. However- additional review will be needed to confirm that HPCI could have operated for the duration of its mission time of 4 hours while aligned to the condensate storage tank. Absent that information this report is being made due to HPCI being declared inoperable until its suction was realigned to the suppression pool. This assumed loss of function for HPCI is being reported in accordance with 10CFR50.72(b)(3)(v)(D) since a final determination has not been made that HPCI would have continued to perform its safety function for the required mission time while aligned to the CST. The licensee notified the NRC Resident Inspector.
ENS 45433	15 October 2009 10:37:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation	Manual Reactor Scram Due to Reactor Recirculation Pump Trip	At 0537 hours on October 15, 2009, the 'B' Reactor Recirculation pump tripped. The reactor mode switch was placed in shutdown due to rising reactor water level (approx. 49 inches) prior to the Level 8 automatic scram setpoint (52 inches). All controls rods inserted as a result of the manual scram. All systems performed as expected. Reactor water level is being controlled by the motor driven feedwater pump. Main steam isolation valves were manually closed and decay heat was initially controlled through the main steam line drains to the main condenser via the main turbine bypass valves. Reactor Core Isolation Cooling (RCIC) was manually placed into service (tank-to-tank) to assist in RPV pressure control. RCIC is currently being used for decay heat removal. Investigation is underway to determine the cause of the Reactor Recirculation pump trip. The licensee will be contacting the state, and issuing a press release. The NRC Senior Resident Inspector has been notified.
ENS 45375	21 September 2009 18:46:00	10 CFR 50.72(b)(3)(iv)(A), System Actuation	Reactor Protection System and Primary Containment Isolation System Actuation After Placing Hpci System Inservice	On September 21, 2009, at 14:46 EDT, Unit 1 received valid actuations of the Reactor Protection System (RPS) and the Primary Containment Isolation System. Unit 1 was non-critical, operating in Mode 3, when a RPS actuation occurred. Operators were placing the High Pressure Coolant Injection (HPCI) system in service for reactor pressure control, when a resulting water level shrink caused level in the Reactor Pressure Vessel to drop to Low Level 1 causing the actuation of RPS and the Primary Containment Isolation system. The HPCI system was secured, and level stabilized in the normal band. Primary Containment Isolation system Group 2 (i.e., Drywell Equipment and Floor Drain, Residual Heat Removal (RHR) Discharge to Radwaste, and RHR Process Sample), Group 6 (i.e., Containment Atmosphere Control/Dilution, Containment Atmosphere Monitoring, and Post Accident Sampling Systems), and Group 8 (i.e., RHR Shutdown Cooling) isolation signals were received. RHR was not in shutdown cooling at the time of the isolation signal. Actuations of the Primary Containment Isolation Valves (PCIVs) were completed and the affected equipment responded as designed, with the following exceptions: Two Group 2 valves (1-G16-F003 and 1-G16-F019) and two Group 6 valves (1-CAC-V6 and l-CAC-V9) did not automatically isolate and were manually isolated from the control panel. Investigation is under way to determine why these valves did not automatically close. Unit 1 was non-critical, in Mode 3, with all rods inserted at the time of the event. The four primary containment isolation valves that did not automatically close did not create an unisolated primary containment penetration. The Emergency Core Cooling System (ECCS), along with Reactor Core Isolation Cooling (RCIC), were operable and available. The licensee has notified the NRC Resident Inspector.
ENS 45284	23 August 2009 21:50:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Unplanned Inoperability of the High Pressure Core Spray System	A momentary alarm for loss of HPCS system DC control power was received in the NMP2 control room. Troubleshooting has determined that a loose connection existed at a fuse block in the DC control power circuitry. The HPCS system was declared inoperable and Technical Specification 3.5.1, Condition B, was entered at 1715. In accordance with Condition B, the Reactor Core Isolation Cooling (RCIC) system was verified to be operable. Repairs were subsequently completed and the HPCS system has been declared operable as of 2046. The licensee has notified the NRC Resident Inspector
ENS 45264	14 August 2009 23:58:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Hpci Inoperable Due to Automatic Closure of Inboard Isolation Valve	On 8/14/2009 at 19:58, the Unit 1 High Pressure Coolant Injection (HPCI) System inboard isolation valves automatically isolated. Inboard isolation was caused by an inadvertent high ambient temperature signal from the HPCI steam leak detection module. Local temperatures were confirmed to be normal and no steam leak was identified. With the HPCI system steam supply isolated, the HPCI system is inoperable in accordance with Technical Specification 3.5.1. HPCI is a single-train safety function system. The initial safety significance of this condition is considered to be minimal. The Reactor Core Isolation Cooling (RCIC) system, Automatic Depressurization System (ADS), and Low Pressure Emergency Core Cooling systems (ECCS) remain operable at this time. Actions have been taken to protect redundant safety systems. Unit 1 risk condition is currently yellow due to the concurrent inoperability of a single loop of Residual Heat Removal (RHR) Service Water for system maintenance. The HPCI system remains isolated and inoperable pending further troubleshooting of the inboard isolation. The NRC resident has been notified.
ENS 45092	25 May 2009 21:50:00	10 CFR 50.72(b)(3)(ii)(B), Unanalyzed Condition	Inoperable Rcic Primary Containment Isolation Valves	The Reactor Core Isolation Cooling (RCIC) system tripped on high turbine exhaust discharge pressure during surveillance testing on May 24, 2009. Following the surveillance it was identified that the containment (torus) inboard stop check valve in the RCIC turbine exhaust line could not be closed, necessitating the shutdown of Unit 1 to perform repairs on this inboard isolation valve. At 1650 hours on May 25, 2009, with the unit shutdown, inspections revealed that the inboard isolation valve could not close due to (the presence of) valve material originating from the containment (torus) outboard swing check isolation valve in the turbine exhaust line. Given the inspection findings it has been concluded that neither the inboard stop check valve or the outboard swing check valve in the RCIC turbine exhaust line would have performed their primary containment isolation function while the unit was at power, (thus) impacting containment integrity. As a result, this event is being reported in accordance with 10 CFR 50.72 (b)(3)(ii) for a degraded or unanalyzed condition. The inboard and outboard containment isolation valves in the RCIC turbine exhaust line will be repaired prior to unit startup. The NRC Resident Inspector has been notified of this condition.
ENS 44860	18 February 2009 09:51:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Turbine Trip Due to Power Load Unbalance Signal on Main Generator Resulting in Reactor Scram	At 0351 on 2/18/09, the Unit 1 reactor automatically scrammed due to actuation of the Reactor Protection System from a turbine trip due to a power load unbalance signal on the main generator. The cause of the power load unbalance signal was due to a generator neutral over voltage condition of which the cause is unknown and the investigation is continuing. All systems responded as expected to the turbine trip. One Safety Relief Valve (SRV) opened due to the reactor pressure transient, and then reactor pressure was automatically controlled by the Main Turbine Bypass valves. No Emergency Core Cooling System (ECCS), or Reactor Core Isolation Cooling (RCIC) reactor water level initiation set points were reached, all expected containment isolation and initiation signals were received, and reactor water level is being automatically controlled by the feedwater system. This event is reportable within 4 hours per 10CFR 50.72(b)(2)(iv)(B) for any event or condition that results in actuation of the reactor protection system (RPS) when the reactor is critical except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation. It is also reportable within 8 hours per 10CFR 50.72(b)(3)(iv)(A) and requires an LER within 60 days per 10CFR 50.73(a)(2)(iv)(A). The NRC Resident Inspector has been notified. All control rods fully inserted. The plant electrical system is in normal shut down alignment. No Diesel Generators started as a result of this event. There was no ECCS injection to the reactor vessel. * * * UPDATE FROM RICKY GIVENS TO JOHN KNOKE AT 1828 0N 02/21/09 * * * * Review of available data indicates that no Main Steam safety/relief valves (MSRVs) opened in response to the Unit 1 reactor scram on 02/18/2009. There were no indications of an open MSRV on any discharge tailpipe thermocouple or acoustic monitor. Initial indications of the discharge tailpipe thermocouples for MSRV (1-PCV-1-30) did indicate a slight increase in temperature (approximately 36 degrees F) as reactor pressure decreased, which resulted in the initial assumption of an SRV opening. However, this behavior is a classical indication of slight main seat leakage and system engineering believes this seat leakage is what the post scram data indicates. Utilizing multiple reactor pressure instrumentation responses, the peak reactor pressure was determined to be approximately 1130 psig which is 15 psi below MSRV 1-PCV-1-30 setpoint. Additionally, the rise in tailpipe temperature did not coincide with the peak pressure but was after pressure had lowered. Based upon a thorough review of this data and a better understanding of the timing of the temperature rise, it is now believed that the MSRVs performed as designed during the reactor pressure transient event. The initial determination that concluded an MSRV opened will be further investigated within the corrective action program; reference PER 164114." The licensee has notified the NRC Resident Inspector. Notified R2 DO (Charlie Payne)
ENS 44821	2 February 2009 00:00:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Manual Reactor Scram Due to Loss of Condenser Cooling	(The licensee manually inserted a reactor scram) due to imminent loss of heat sink (condenser). Circulating water to the condenser suffered an unisolable break resulting in loss of suction source to pumps with cavitation. (The) plant was stabilized per emergency operating procedures. Containment isolations signals operated per design with Groups 2, 3, and 4 received. Plant response (was) complicated with (an) unexpected loss of one 161 KV bus in the switchyard. This was caused by a breaker failure lockout of the bus caused by signal from the output breaker. This output breaker did open. Cause of the breaker failure being investigated. (The) power loss (of the 161 KV bus) had minor plant effect. One power supply to essential service offsite transformer 1X3 (was) lost due to the bus lockout. (The) transformer and offsite circuit remained available. (The) plant did sustain a temporary loss of spent fuel pool cooling system. Cooling has been restored with no level or temperature complications. Essential power (remained) available with both onsite SBDG's (Standby Diesel Generators) and offsite circuits (current source). All ECCS available. All safety related equipment operat(ed) as designed, except Reactor Core Isolation Cooling (RCIC) turbine which had difficulty in automatic control. Manual control (of RCIC) was effective. This is not unexpected during the conditions it was operating (low flow). The licensee was shutting down to enter a refueling outage as the time of the event. Circulating water to one cooling tower had been isolated when a riser on the second cooling tower ruptured and resulted in loss of supply to the circwater pumps. All systems functioned as required except for the lockout of the 161KV bus and RCIC automatic control. Rods fully inserted. The plant is in a normal electrical configuration except for the loss of the 161 KV bus which does not supply any safety related busses. No safety relief valves lifted during the transient. Cooling is currently via HPCI and RCIC to the torus with torus cooling via essential service water. The plant is currently stable at 600 psi and being cooled-down to cold shutdown. The NRC Resident Inspector has been notified.
ENS 44810	28 January 2009 01:07:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Unit 2 Hpci System Inoperable for Two Hours Due to Condensate in Exhaust Line	On January 27, 2009 at approximately 2007, the Unit 2 High Pressure Coolant Injection (HPCI) System was declared inoperable due to a sustained high level in the HPCI Exhaust Line Drain Pot. This sustained high level was caused by a failure of the HPCI Barometric Condenser Condensate Pump, which prevented the removal of the accumulated condensate. An alternate drain path was established and the exhaust line drain pot high level condition was cleared at 2202. However, due to this condition existing for approximately two hours, it cannot be assured that HPCI would have been able to perform its designed function under all conditions. The potential of HPCI system component damage or isolation from an exhaust line failure due to water hammer during a system initiation could not be positively eliminated. Initial safety significance: Minimal. The Reactor Core Isolation Cooling (RCIC) System, Automatic Depressurization (ADS) System, and Low Pressure Emergency Core Cooling Systems (ECCS) - two Loops of Core Spray and two Loops of Low Pressure Coolant Injection (LPCI) - remain operable. Manual actions have been taken to drain the HPCI Exhaust Line Drain pot and have been successful. Determination of the cause of the failure of the HPCI Barometric Condenser Condensate Pump and restoration to service are in progress. The NRC Resident Inspector has been notified.
ENS 44737	20 December 2008 15:45:00	10 CFR 50.72(b)(3)(iv)(A), System Actuation	Momentary Loss of 345Kv Offsite Power	At approximately 1045 hours on Saturday, December 20, 2008, while in a Hot Shutdown condition, Pilgrim Station experienced a momentary loss of all 345kV off-site power to the Startup Transformer (SUT). As a result, the following safety system actuations occurred: automatic Reactor Protection System (RPS) actuation (all control rods were previously inserted), automatic start of both Emergency Diesel Generators (EDG) and loading of their respective emergency buses, automatic actuation of Primary Containment Isolation Systems (PCIS) Groups I, II, VI and Reactor Building Ventilation, manual initiation of the High Pressure Coolant Injection (HPCI) system for reactor pressure control, and manual initiation of the Reactor Core Isolation Cooling (RCIC) system for reactor level control. All systems functioned as designed and expected. Because power from an off-site source remained available from the 23kV Shutdown Transformer, the criteria for declaration of an Unusual Event were not met (Pilgrim EAL 6.3.2.1). 345kV power was automatically restored to the Startup Transformer via breaker reclose logic. Restoration of normal on-site power to all 4kV buses is complete and efforts to return systems to normal shutdown alignments are in progress. Current plans are in place to maneuver the plant to a Cold Shutdown condition as necessary to support recovery actions. The NRC Resident was on-site at the time of the event and has been notified. There was no threat to the health or safety of the public as a result of this event. The loss of power was caused by a breaker icing in the onsite switchyard. The switchyard breakers were inspected for icing. The licensee notified the State of Massachusetts.
ENS 44647	9 November 2008 16:08:00	Other Unspec Reqmnt 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Manual Reactor Scram Due to Spurious Srv Opening	One hour reportable event based on a safety relief valve (SRV) failure to close (NUREG 0626 and NUREG 0660). On 11/09/08 at approximately 11:08 with Unit 2 at 100% steady state power SRV 2-B21-F013H spuriously failed full open with no operator action or testing in progress. The valve's control switch was cycled as required by Abnormal Operating Procedure AOP-30 with no success. At 1113 the valve was successfully closed by pulling the associated fuses. At 1117, a manual reactor scram was inserted based on a Torus temperature of 109.8 degrees F (Technical Specifications require a scram to be inserted at 110 degrees F). All control rods (fully) inserted from the manual scram signal. Reactor water level lowered to Low Level 2 resulting in Primary Containment Isolation System (PCIS) isolations of Groups 2, 3, 6, and 8. In addition, this resulted in a Reactor Core Isolation Cooling (RCIC) system actuation and injection into the reactor. The High Pressure Coolant Injection (HPCI) system actuated but did not inject because reactor water level recovered. An Alternate Rod Insertion signal was received, the Standby Gas Treatment (SBGT) system initiated, and the Reactor Recirculation Pumps tripped as designed. Plant safety systems responded as designed to the transient. (Licensee) investigations are underway to determine the cause of the SRV failure. Reactor decay heat is being removed through the main turbine bypass valves to the condenser. Reactor make-up is being maintained by the normal feedwater system. The plant is in its normal shutdown electrical lineup supplied by offsite power. The diesel generators are available for service to the plant The Licensee notified the NRC Resident Inspector.
ENS 44595	23 October 2008 12:20:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Automatic Reactor Scram with Manual Rcic Initiation	'A' Reactor Feed Pump speed decreased to zero with no trip signal evident in the Control Room for the 'A' Reactor Feed Pump. The reactor scrammed due to loss of feedwater flow on a Level 3 (11.4") RPS scram signal as designed. Operators implemented appropriate off normal event procedures to mitigate the transient with all systems responding as designed. Lowest reactor water level observed was -35" wide range. All withdrawn control rods fully inserted to position '00'. The Reactor Core Isolation Cooling System was manually initiated and was used to restore water level to within the normal band. No ECCS initiations were received and all systems responded as designed. Additionally, no SRVs lifted as a result of this event. Level 3 is also a setpoint for Group 2 (RHR to Radwaste) and Group 3 (Shutdown Cooling Isolation) automatic isolation. No valves isolated in these systems due to them being in their normally CLOSED position prior to the event. Currently, reactor water level is being maintained by the condensate system in normal level band and reactor pressure is being controlled to limit cool down. The licensee has notified the NRC Resident Inspector.
ENS 44593	22 October 2008 16:17:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Rcic Declared Inoperable Due to Aging Concern of Several Flow Controller Components	On October 22, 2008, at 1217 hours, with the reactor at 100% core thermal power and steady state conditions, Pilgrim Nuclear Power Station (PNPS) conservatively declared the Reactor Core Isolation Cooling System (RCIC) inoperable in response to a concern regarding the reliability of aged capacitors that are installed in the RCIC flow controller. As background, the RCIC flow controller was calibrated and successfully tested on October 7th, 2008 as part of normal surveillance activities, however several of the capacitors installed in the controller were noted to be between 21 to 30 years of age. Industry recommended replacement interval for the capacitors is typically between 7 to 10 years of age. PNPS engineering review in conjunction with Entergy fleet consultation concluded today (10/22) that there was no definitive technical bases to provide a reasonable expectation that the RCIC flow controller function can be assured throughout it's mission time due to the capacitor aging concern. Therefore, RCIC was declared inoperable and a 14 day limiting condition for operability action statement was entered in accordance with TS 3.5.D.1. A replacement controller is being prepared for installation, with post maintenance testing projected to be completed by 2100 hours this evening. Ultimately the suspect controller will be the subject of further evaluation and this notification will be updated as appropriate. This notification has no impact on the health and safety of the public. The NRC Senior Resident Inspector is onsite and has been notified. This is an 8 hour notification made in accordance with 50.72(b)(3)(v)(D). * * RETRACTION AT 1435 EST ON 12/12/2008 FROM JOHN WHALEY TO DONALD NORWOOD * * * Basis for Retraction: Event Notification 44593 was conservatively made to ensure that the eight-hour non-emergency reporting requirements of 10 CFR 50.72 were satisfied pending the evaluation of RCIC System operability. On 10/22/08, RCIC flow controller FIC-1340-1 was declared inoperable due to engineering uncertainty for controller operability. The controller's electrolytic capacitors appeared to be aged beyond the expected useful life, and the resultant degrading power supply voltage indicated that the controller may not operate for the required FSAR mission time of eight hours. The controller was replaced on 10/23/08 with a refurbished controller and subsequent post-maintenance RCIC system flow testing demonstrated RCIC system operability. The controller that was removed from service was evaluated. Controller bench testing was performed on 11/6 and 11/7, 2008. This testing demonstrated that the controller could provide a full demand output signal for a minimum of 15 continuous hours. During this testing, it was also determined that the power supply output voltage was not degrading. Based on this post-service controller testing, and the successful in-service RCIC flow controller calibration and system performance test conducted on 10/07/08, the controller was operable when installed. The RCIC system was capable of performing its intended safety functions and would have started and supplied design basis flow to the reactor vessel under design basis conditions. Thus there would have (been) no impact on nuclear safety. Therefore, this event was not reportable pursuant to 10CFR50.72(b)(3)(v)(D). Event Number 44593, made on 10/22/2008, is being retracted. The licensee notified the NRC Resident Inspector. Notified R1DO (Bellamy).
ENS 44545	7 October 2008 02:24:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Unexpected Reactor Core Isolation Cooling Isolation During Test	During performance of PNPS Procedure 8.M.2-2.6.3 Attachment 1 step (65) the RCIC System isolated on a Group 5 signal when relay contact blocking devices (boots) were removed. All isolations went to completion. This isolation was not part of the planned evolution. The Group 5 isolation was reset and RCIC was placed in stand by line-up at 2327 on 10/6/2008. Investigation is continuing. The licensee notified the NRC Resident Inspector.
ENS 44540	5 October 2008 03:08:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Reactor Scram Following Reverse Power Signal on Main Generator	On 10/04/08 at 2008 (CDT) the Unit 2 reactor scrammed due to turbine generator reverse power signal on the Main Generator. The cause of the reverse power signal is unknown and the investigation is continuing. All systems responded as expected to the generator reverse power signal. Reactor pressure was automatically controlled by the Main Turbine bypass valves. No Emergency Core Cooling System (ECCS), nor Reactor Core Isolation Cooling (RCIC) reactor water level initiation set points were reached, and reactor water level is being automatically controlled by the feedwater system. This report is being made as required by 10 CFR 50.72(b)(2)(iv)(B) and 10 CFR 50.72(b)(3)(iv)(A). The licensee characterized the scram as uncomplicated. All control rods fully inserted. No safety valves lifted during the transient. All safety systems were available at the time of the scram. There were no impacts on Units 1 or 3. The licensee has notified the NRC Resident Inspector.
ENS 44484	12 September 2008 03:47:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(v)(B), Loss of Safety Function - Remove Residual Heat 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Reactor Scram and Isolation Due to Transformer Lockout	While the 1R transformer was out of service for maintenance, the 2R transformer experienced a lockout resulting in a loss of normal offsite power, a reactor scram, and a Group 1, 2 and 3 isolation. All rods fully inserted as expected. The cause of the 2R transformer lockout is unknown at this time. After initiation, the high pressure coolant injection (HPCI) system would not trip at the high reactor water level set point +48", as required. The operators then manually isolated the HPCI steam lines. Plant decay heat removal is with the reactor core isolation cooling (RCIC) system and the safety relief valves. Torus cooling is in service. The vital electrical busses are being supplied by the 1AR transformer. Efforts are underway to restore the 1R transformer to service, and subsequently the non-vital busses. The licensee notified the NRC Resident Inspector. * * UPDATE PROVIDED BY KIM HOFFMAN TO JASON KOZAL AT 0655 ON 09/12/08 * * * The HPCI system was declared inoperable and isolated due to failure to automatically trip at +48" Reactor Water Level. The HPCI steam supply valves were automatically closed to remove HPCI from service. In addition, the HPCI turbine trip failed to trip with the turbine trip push button. The cause of the trip failure is unknown at this time. The licensee is continuing to investigate. HPCI did automatically start as designed and injected to the reactor vessel as designed. However, HPCI failed to trip at High Reactor Water Level as required. Additionally, the Automatic Depressurization System (ADS) timer showed erratic indication following the event. The ADS timer was inhibited to prevent automatic action. ADS is inoperable, but manual steam relief valve operation remains available. The licensee will notify the NRC Resident Inspector. Notified R3DO (Passehl), NRR EO (Ross-Lee), and IRD (McMurtray). * * UPDATE PROVIDED BY SCHREIFELS TO CROUCH AT 1656 EDT ON 09/12/08 * * * A (second) Group 2 isolation signal was received when reactor water level lowered below +9 (inches) (while pumping drywell sumps). All Group 2 valves except the drywell sump isolation valves were closed due to a previously reported Group 2 signal. The drywell sump valves had been opened to allow manual pumpdown of the sumps. The sump valves closed as expected. Licensee notified the NRC Resident Inspector. Notified R3DO (Passehl).
ENS 44290	12 June 2008 04:40:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Coolant Injection (Hpci) System Identified Inoperable During Surveillance	Unit 2 HPCI was declared inoperable during the performance of a scheduled surveillance test. HPCI failed to develop the required discharge pressure to meet its design function." Reactor Core Isolation Cooling (RCIC) is available. The licensee notified the NRC Resident Inspector. * * UPDATE FROM DAVE FOSS TO JOHN KNOKE AT 0954 ON 06/17/08 * * * The purpose of this notification is to retract a previous report made on 6/12/08 at 0549 hours (EN# 44290). On 6/12/08, the High Pressure Coolant Injection (HPCI) system was declared inoperable as a result of the performance of a routine Surveillance Test (ST). During the ST, the HPCI pump discharge pressure did not achieve the acceptance criteria of greater than or equal to 1258 psig. The highest indicated pressure achieved during the ST was approximately 1230 psig. Therefore, notification of this issue to the NRC on 6/12/08 as a loss of the HPCI safety function was initially made as a result of the belief that the HPCI system was inoperable due to inadequate discharge pressure. HPCI was maintained in an available status as troubleshooting began. During subsequent troubleshooting on 6/12/08, it was determined that the Main Control Room HPCI discharge pressure indicator (i.e., the pressure indicator used during the ST) was reading approximately 65 psig low. Therefore, the pressure indicator used during the ST indicated a low value for discharge pressure. Based on this, the actual HPCI discharge pressure during the ST was acceptable. The pressure indicator was recalibrated and the HPCI ST was re-performed successfully. HPCI was declared operable by 1805 hours on 6/12/08. Based on the above, there were no unplanned loss of the safety function for the HPCI system. Therefore, the initial ENS notification is being retracted. " Licensee has notified NRC Resident Inspector. Notified R1DO (Schmidt)
ENS 44284	11 June 2008 22:03:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Hpcs Declared Inoperable	This report is being made pursuant to 10CFR50.72(b)(3)(v)(D), Event or condition that could have prevented fulfillment of a safety function needed to mitigate the consequences of an accident. During steady state operations, a Division 3 AC ground alarm was received, followed by a trip of the 2VD05C Division 3 switchgear room / Core Standby Cooling System (CSCS) Pump Room Supply Fan. Division 3 supplies power to the High Pressure (Core Spray) (HPCS), which is a single-train system. Although the system remained functional and capable of vessel injection following the failure, the HPCS system and its associated power supplies were declared inoperable based on long-term temperature considerations. At 1703, the circuit breaker for the HPCS injection valve, which is a Primary Containment Isolation Valve (PCIV), was opened and the valve deenergized in the closed position to comply with Technical Specifications. Disabling the injection valve affects the safety function of the system (HPCS), and this is reportable as an 8-hour ENS notification. The cause of the ventilation fan motor trip has been determined to be a motor fault. Replacement of the fan motor is in progress. This event places the plant in a 14-day LCO per Technical Specification 3.5.1. Repairs are expected to be completed by 0700 on 6/12/08. The Reactor Core Isolation Cooling (RCIC) system is operable. The licensee notified the NRC Resident Inspector.
ENS 44245	28 May 2008 21:30:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Core Spray Inoperable	On May 28, 2008, at 1730 hours, control room operators determined after testing, that the Emergency Service Water (ESW) Division 3 subsystem was inoperable due to a condition that will not allow the subsystem to maintain 'keep-fill' pressure in the event of a loss of offsite power. Technical Specification (TS) Limiting Condition for Operation (LCO) 3.7.2 requires that the High Pressure Core Spray (HPCS) System (a single train safety system) be declared inoperable immediately when the ESW Division 3 Subsystem is inoperable. The plant immediately entered TS LCO 3.5.1 Condition B, HPCS System inoperable. TS LCO 3.5.1, Required Action B.1, verify by administrative means that the Reactor Core Isolation Cooling System is operable within one hour, was completed at 1730 hours. Required Action B.2 requires that the HPCS System be restored to operable status within 14 days. Maintenance/troubleshooting activities are in progress to determine the cause of the ESW Division 3 Subsystem condition. This event is being reported as a condition that could have prevented the safety function of structures or systems required to mitigate the consequences of an accident. The resident inspector has been notified.
ENS 44179	30 April 2008 03:13:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Coolant Injection (Hpci) System Inoperable Due to Seal Leak	On 04/29/08 at approximately 2313 during testing of the Unit 1 HPCI system, a main pump seal developed a leak requiring the HPCI system to be secured. HPCI testing was in progress per OPT 09.2, HPCI System Operability Test, following recent Unit 1 refueling outage. At the time of discovery, the Unit 1 HPCI system had been declared inoperable due to surveillance testing activities which removed HPCI from the standby lineup. When the pump seal leak developed, operators secured HPCI and isolated the leak by closing the pump suction isolation valves and the keep fill supply valves. Investigation into the cause of the pump seal leakage is underway and the Unit 1 HPCI system will be placed under clearance for repair. The initial safety significance of this condition is considered to be minimal. The Reactor Core Isolation Cooling (RCIC) system as well as the other Unit 1 ECCS systems are operable at this time. Actions have been taken to protect redundant safety systems. The Unit 1 HPCI system has been removed from service and secured. Investigation is underway to determine the cause of the HPCI main pump leakage. The HPCI system will be placed under clearance for repair. The licensee notified the NRC Resident Inspector. * * RETRACTION ON 7/31/08 AT 1447 EDT FROM TURKAL TO HUFFMAN * * * The HPCI pump uses seal purge water piping in combination with mechanical seals to limit shaft leakage. Investigation of this event found that inadequate post-maintenance venting of piping between the discharge of the HPCI booster pump and the suction of the HPCI main pump led to the seal faces overheating and subsequent failure. The failure of the seal and the leakage associated with it would not have prevented HPCI from performing its required functions. Water intrusion into the oil system is the limiting impact of the seal failure. The HPCI main pump seal failure event has been evaluated and it was determined that, given a worst-case seal failure, the HPCI pump would be able to operate for greater than the required 4.1 hours and, thereby, satisfy its accident, as well as transient, response requirements. On this basis, the HPCI system was capable of performing its function to mitigate the consequences of an accident and the issue is not reportable under 10 CFR 50.72(b)(3)(v)(D). Investigation of this condition is documented in the corrective action program in Nuclear Condition Report (NCR) 277188. The NRC resident was notified of this retraction. The R2DO (Henson) has been notified.
ENS 43942	29 January 2008 19:41:00	10 CFR 50.72(b)(3)(v)(A), Loss of Safety Function - Shutdown the Reactor	High Pressure Coolant Injection System Not Available for Safe Shutdown Capability	The D/C power supply for the Unit 1 High Pressure Coolant Injection (HPCI) system instrumentation has failed resulting in the inability of HPCI to meet its requirement to support safely shutting down the reactor during a Station Blackout (Complete Loss of A/C Power) situation. The Emergency Core Cooling System (ECCS) function of HPCI is still available with the alternate A/C power supply. The licensee is actively troubleshooting the power supply. The HPCI unavailability places the licensee in a 14-day Limiting Condition for Operation action statement. The licensee has notified the NRC Resident Inspector. * * * RETRACTION FROM D. SEMETER TO P. SNYDER ON 3/27/08 AT 1300 * * * This is a retraction of the event notification made on 1/29/08 at 21:50 EST hours. This event (#43942) was initially reported as a safety system functional failure under the requirement of 10 CFR 50.72(b)(3)(v)(A). The notification stated that the D.C. power supply for the Unit 1 High Pressure Coolant Injection (HPCI) system instrumentation failed resulting in the inability of HPCI to meet its requirement to support safely shutting down the reactor during a Station Blackout (SBO) (Complete Loss of A/C Power) situation. The Emergency Core Cooling System (ECCS) function of HPCI is still available with the alternate A/C power supply. A review of the station's current licensing basis determined that HPCI is not credited with a safety function during a Station Blackout (SBO) event. Operating procedures direct securing HPCI early in an SBO event to minimize the discharge rate on the Class 1E batteries. The Reactor Core Isolation Cooling (RCIC) system is credited with maintaining reactor inventory during a SBO event. HPCI remained capable of completing its safety function to inject coolant into the reactor pressure vessel during a loss of coolant accident (LOCA) concurrent with loss of offsite power (LOOP) event. The Division 2 automatic initiation logic was inoperable but the Division 4 automatic initiation logic was unaffected by the Division 2 instrument power supply failure. Division 2 instrument power is required for HPCI automatic flow control and would not have been initially available during a LOOP event. However, the Division 2 instrument power would have been restored when the 480 VAC load center is re-energized approximately 13 seconds into the event. The 13 second delay in HPCl injection is offset by existing margin in HPCI's capability to meet the Technical Specification response time of 60 seconds. Therefore, a condition did not exist at the time of discovery that could have prevented the fulfillment of the HPCI safety function. The licensee notified the NRC Resident Inspector. Notified R1DO (Bellamy).
ENS 43923	14 January 2008 18:41:00	10 CFR 50.73(a)(1), Submit an LER	Invalid Actuation of Group 5 and Group 10 Primary Containment Valves During Surveillance Testing	This is not an LER. The reports being made to the NRC under 10 CFR 50.73(a)(2)(iv)(A), and the 60 day telephone notification option under 10 CFR 50.73(a)(1). The event included invalid '. . .general isolation signals affecting containment isolation valves in more than one system. . .' as discussed in 10 CFR 50.73(a)(2)(iv)(B). The following information is provided as requested in NUREG-1022: (a) The specific train(s) and systems that were actuated? On January 14, 2008 at 13:41 hours. Unit 2 received invalid Division 1 Primary Containment isolation signals to both Group 5 (RHR Shutdown Cooling Isolation valves) and Group 10 (Reactor Core Isolation Cooling (RCIC) system isolation valves) during Division 1 instrumentation surveillance testing. While performing testing, an incorrect lead was lifted causing this invalid actuation. (b) Whether each train actuation was complete or partial. The event resulted in closure of the RCIC steam supply header outboard containment isolation valve. The Division 1 RHR Shutdown Cooling System isolation valves were already closed at the time of the isolation signal. (b) Whether or not the system started and functioned as designed. The Primary Containment isolation instrumentation logic and associated valve closure function (for RCIC) actuated as designed. The licensee took prompt actions to recover the RCIC and RHR systems. The licensee notified the NRC Resident Inspector.
ENS 43878	1 January 2008 03:40:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Unit 3 Automatic Scram Due to Main Generator Load Reject Signal	On 12/31/07 at 2140 the Unit 3 reactor scrammed due to turbine generator load reject signal on the Main Generator. The cause of the load reject signal is unknown and the investigation is continuing. All systems responded as expected to the load reject signal. Six Main Steam Relief valves (MSRVs) opened momentarily and then reclosed. Subsequently, reactor pressure was automatically controlled by the Main Turbine Bypass valves. No Emergency Core Cooling System (ECCS), nor Reactor Core Isolation Cooling (RCIC) reactor water level initiation setpoints were reached, and reactor water level is being automatically controlled by the Feedwater system. This report is being made as required by 10CFR 50.72(b)(2) due to the actuation of the Reactor protection System. Refer to BFN PER number 135878. All control rods fully inserted into the core, and all safety systems are operable. PCIS group isolations were received for groups 2, 3, 6, and 8. There were no grid abnormalities at the time of the load reject, and the event had no effect on Unit 1 or 2. The licensee notified the NRC Resident Inspector.
ENS 43773	7 November 2007 09:06:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge	Reactor Scram as a Result of Loss of Normal Power 13.8 Kv Bus	With the plant in Mode 1 at (approximately) 75% power, the Auxiliary boiler and water treatment building 480 volt switchgear (NJS-SWG1J) faulted. The fault resulted in the loss of the NPS A bus (13.8 Kv normal supply), causing condensate and feed pumps to trip. Operators in the control room immediately responded and the plant was manually scrammed at 0306. Both the high pressure core spray (HPCS) and the reactor core isolation cooling (RCIC) systems responded automatically and injected into the vessel (valid ECCS signal). Safety systems responded as expected, including level 2 isolations. The licensee believes a transformer fault may have transferred up the line and caused the loss of normal power supply. RCIC is controlling reactor water level with primary plant pressure approximately 325 psia. Decay heat is being controlled through modulating the SRV's. The licensee has all systems available to place the unit in safe shutdown and cooldown. The licensee has one inoperable EDG and is not in any technical specification action statement at this time. The licensee notified the NRC Resident Inspector. * * UPDATE AT 2214 ON 11/7/2007 FROM BRYAN KELLEY TO MARK ABRAMOVITZ * * * The high pressure core spray system was returned to its standby lineup at 0318 (all times are CST). Standby service water was being placed in service at 0701 to raise service water header pressure when standby service water pump 'C' started automatically. NPS 13.8kv switchgear 'A' was restored to service at 1245. The reactor core isolation cooling system, which automatically started at the time of the event, was shutdown at 1645. The Division 3 diesel generator, which automatically started at the time of the event, was restored to its standby lineup at 1429. Shutdown cooling was placed in service with residual heat removal pump 'A', at 1626. The plant entered Mode 4 (cold shutdown) at 1942. The electrical fault that initiated the event has been isolated to a 13.8kv/480v transformer in the turbine building. An investigation is ongoing. The licensee notified the NRC Resident Inspector. Notified the R4DO (Spitzberg) and NRR (Lubinski).
ENS 43752	28 October 2007 04:59:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Manual Scram Due to Lowering Intake Level	High winds (in excess of 40 MPH) resulted in significant debris at the plant intake. Traveling screens had been placed in 'Fast' speed and continuous wash on the previous shift in anticipation of predicted high wind conditions. As the debris entered the intake, high traveling screen differential pressure and lowering intake level prompted the operating crew to enter the appropriate Abnormal Operating Procedure (AOP). Efforts to manually clean the screens were ineffective, and at 0059 hours, the crew inserted a manual scram as directed by procedure at 240 foot intake level. On scram, as expected, reactor vessel level lowered to the low level scram setpoint (177 inches above top of active fuel). At this point, as expected, an automatic Reactor Protection System (RPS) actuation, and a Group 2 Primary Containment Isolation System (PCIS) isolation occurred with no anomalies noted. During plant cooldown reactor level lowered to 177 inches above TAF. This resulted in a valid RPS actuation and a PCIS Group 2 isolation signal. All systems responded as expected. Operators were able to maintain reactor vessel level above the actuation setpoint for High Pressure Coolant Injection (HPCI) and Reactor Core Isolation Cooling (RCIC) systems, and these systems were not required to operate. The cause of the failure of the traveling screens to maintain intake level is under investigation. All control rods are fully inserted and the plant is stable in Mode 3, Hot Shutdown. Decay heat is being removed via the turbine bypass valves to the main condenser. No SRVs lifted during the transient. The plant is in a normal shutdown electric plant lineup. The licensee notified the NRC Resident Inspector and the New York Public Service Commission.
ENS 43711	11 October 2007 02:45:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Unit 2 Hpci Pump Seal Failure	On 10/10/2007 a 2245, the Unit 2 High Pressure Coolant Injection (HPCI) Pump developed a leak of approximately 5 gpm due to a suspected pump seal failure. HPCI was in service for a scheduled surveillance test per plant procedure OPT-09.2, HPCI System Operability Test. When the leak was identified, operators secured HPCI. The leak was isolated by securing the pump, closing the pump suction isolation valves, isolating the keep fill supply valves. Operators declared the Unit 2 HPCI System inoperable when the keep fill system was isolated. No automatic system isolation or actuation set points were reached. Safety significance is minimal due to the operability and availability of redundant systems. If a Loss of Coolant Accident (LOCA) were to occur the Reactor Core Isolation Cooling (RCIC) System would automatically inject and if necessary the Automatic Depressurization System (ADS) would depressurize the reactor pressure vessel allowing low pressure Emergency Core Cooling Systems (ECCS) to inject. All low pressure ECCS are operable. Plant risk has been evaluated and remains 'Green'. The Unit 2 HPCI system has been removed from service. The pump suction isolation valves have been closed. Injection piping keep fill connections have been isolated. These actions were taken to stop the leakage of system water out of the failed pump seal. Actions have been taken to protect redundant safety systems, including the RCIC System and ADS. In accordance with Technical Specification 3.5.1 Required Actions: RCIC has been verified to be operable, and HPCI must be restored to operable status within 14 days. HPCI pump seal replacement is being planned in accordance with the site's Work Management process. This event has been entered into the sites Corrective Action Program and an investigation into the cause of the seal failure will be performed. The licensee notified the NRC Resident Inspector. * * RETRACTION RECEIVED FROM LEE GRZEK TO JOE O'HARA AT 1045 EST ON 1/30/08 * * * On October 11, 2007, at 0520 hours, the control room Supervisor made a notification (Event Number 43711) to the NRC Operations Center in accordance with. 10 CFR 50.72(b)(3)(v)(D) (i.e., 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 notification was made as a result of the High Pressure Coolant Injection (HPCI) system being declared inoperable due to indications of a main pump seal leak. Specifically, water was discovered leaking an approximate five gallons per minute from the main pump turbine side seal during performance of OPT-09.2, 'HPCI System Operability Test.' Basis for Retraction Unit 2 HPCI was declared inoperable when the main pump seal leak was first identified. Upon further detailed engineering evaluation, it has been determined that the HPCI system was not rendered inoperable as a result of the condition identified on October 10, 2007, and was able to fulfill its safety functions in the degraded condition. The HPCI pump uses seal purge water piping in combination with mechanical seals to limit shaft leakage. The investigation found debris blocking the seal purge piping, which led to the seal faces overheating and subsequent failure. Water intrusion into the oil system was determined to be the limiting impact of the seal failure. The limiting event for HPCI was determined to be 4.1 hours of operation during a loss of Feedwater event with HPCI only, due to the short runtimes followed by long idle times which maximize water intrusion. The evaluation concluded that the HPCI pump would be able to operate for 4.1 hours, as required for the limiting event, and would be available for 8 hours. Thus, Unit 2 HPCI was degraded but able to meet all required safety functions. On this basis, the HPCI system was capable of performing its safety functions to mitigate the consequences of an accident and the issue is not reportable under 10 CFR 50.72(b)(3)(v)(D). The NRC Resident was notified of this retraction. Notified R2DO(Bonner)
ENS 43635	12 September 2007 10:35:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Reactor Scram Following Intake Structure Traveling Screen Fouling	As a result of high winds and a severe storm front moving through the area a Nuclear Plant Operator (NPO) found the intake canal water murky, wind speed was noted to be 40 MPH. The Traveling Screens were placed in the continuous mode of operation and increased monitoring was put in effect. At 0520 the NPO noted that 'a lot of weeds and fish were coming in through the intake' and that a full trash basket had been changed out. At approximately 0630 the NPO reported that the traveling screens were not moving and intake level was lowering due to the influx of debris. The Shift Nuclear Operator (SNO) entered the appropriate Abnormal Operating Procedure (AOP) for lowering intake level and commenced rapid power reduction. At 0635 with intake level at 240 feet the SNO inserted a manual scram and entered the appropriate AOP and Emergency Operating Procedure (EOP). Reactor Vessel level decreased to less than 177 inches above the top of active fuel resulting in a Primary Containment Isolation System (PCIS) Group 2 isolation signal. The PCIS Group 2 isolation resulted in a valid signal to close PCIS valves in the Drywell Floor Drain System, the Drywell Equipment Drain System, the Residual Heat Removal (RHR) System, the Traversing In-Core Probe (TIP) System, the Containment Atmosphere Dilution (CAD) System, and the Reactor Water Clean-Up (RWCU) System. However, as a result of the power reduction the operators were able to maintain reactor vessel level above the actuation setpoint for the High Pressure Coolant Injection (HPCI) System and the Reactor Core Isolation Cooling (RCIC) Systems and these systems were not required to operate. At 0640 the Scram was reset, at 0710 the Group 2 PCIS Isolation was verified, and at 0729 the Group 2 PCIS Isolation was reset. The cause of the traveling screens stopping has been determined to be due to shear pins on the traveling water screen shearing due to excessive debris loading. All equipment responded as expected during the downpower and subsequent manual Scram. All rods are in and the plant is stable in MODE 3, Hot Shutdown." Decay heat is being removed by dumping steam to the condenser via the turbine bypass valves. The safety buses are being powered by offsite power. The 'B' train Residual Heat Removal pump was out of service at the time of the event for planned maintenance. The licensee notified the NRC Resident Inspector. * * UPDATE FROM G. DORMAN TO J. KNOKE AT 1205 EDT ON 09/12/07 * * * At 1034 with the plant shutdown and a cooldown in progress reactor vessel (RV) level lowered to less than 177 inches above TAF (Top of Active Fuel). This resulted in a valid Reactor Protection System (RPS) Scram signal and a PCIS Group 2 Isolation Signal. AP systems responded as expected. Reactor vessel level remained above the actuation setpoint for HPCI and RCIC and they were not required to operate. RV level was restored and the Scram was reset. At the time of the initial event and at this update the plant is in LCO action statement 3.5.1.A for the 'B' RHR Pump being out of service. The system is being restored at this time. The licensee notified the NRC Resident Inspector. The licensee also notified the state and is providing a press release to the media. Notified R1DO (Trapp).
ENS 43457	29 June 2007 00:17:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation	Reactor Trip Due to Condensate Pump Trip	Reactor trip at 1717 hrs PDT due to (condensate pump) COND-P-2B trip. Reactor power was at 70% with (condensate pump) COND-P-2A secured. Reactor vessel level reached -50 inches and was restored with High Pressure Core Spray and Reactor Core Isolation Cooling. Main Steam Isolation Valves closed as expected due to the reaching -50 inches. All systems operated as expected. Further investigation into COND-P-2B trip is underway. Plant is stable in mode three, heat removal is being maintained by RHR-P-2B and Safety Relief Valves. All rods fully inserted on the automatic reactor scram. All safety systems were available at the time of the trip. The trip was considered uncomplicated. The reactor pressure is currently being maintained between 500 to 600 psi and water level between 60 to 80 inches. The licensee was at 70% power at the time of the trip due to maintenance of condensate pump P-2A. The licensee will notify the NRC Resident Inspector.
ENS 43395	29 May 2007 12:35:00	10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge	Manual Reactor Scram Due to Loss of Feed Pumps After Electrical Transient	On 5/28/07 with Hope Creek in Operating Condition 1 at 100% Reactor power, an electrical transient and loss of 'A' and 'B' reactor feed pumps resulted in lowering reactor water level. Operators inserted a manual reactor scram at 0835 in response to the lowering reactor water level. Reactor water level lowered to (-) 38 inches subsequent to the manual scram, resulting in initiation of High Pressure Coolant Injection (HPCl) and injection to the reactor vessel. The Reactor Core Isolation Cooling (RCIC) system also initiated but tripped. Investigation of the cause of the electrical transient, loss of the 'A' and 'B' RFP's, and trip of the RCIC system are currently in progress. Initial review of the event indicates that all other systems operated as expected. Current plant conditions as of 1100 are: Hope Creek is in mode 3 at 715 psig with heat removal to the main condenser via the Main Turbine Bypass valves. All control nods fully inserted on the scram. This report also documents a 4 hour report under 10CFR50.72(b)(2)(iv)(A) for valid ECCS initiation and injection to the reactor vessel (RAL 11.3.1). The reactor is stable with the water level currently at 17 inches and feedwater being supplied by the 'C' feed pump. No Safeties lifted during the transient. All systems functioned as required except for the trip of the RCIC. The licensee was not in any major technical specification LCO at the time of the trip. The licensee notified the NRC Resident Inspector. The licensee will also notify the States of NJ and Delaware, and Lower Alloways Creek Township.
ENS 43197	28 February 2007 03:26:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Coolant Injection (Hpci) Inoperability	On February 27, 2007, at approximately 2200 hours, testing of the Unit 2 High Pressure Coolant Injection (HPCI) system was in progress in accordance with 0PT-09.2, HPCI System Operability Test following system maintenance. Soon after the HPCI turbine was started a high level alarm condition in the HPCI barometric condenser was experienced. Evidence suggests the most probable cause was due to failure of the 2-E41-F048, Condensate Pump Discharge Check Valve, to open. The adverse consequence of this check valve failing to open is inadequate cooling flow to the HPCI lube oil cooler. The HPCI turbine was removed from service per applicable plant procedures. At the time of discovery, the HPCI system was inoperable for scheduled maintenance. However, this equipment failure would have prevented the HPCI system from fulfilling its safety function. Limiting Condition for Operation (LCO) per Technical Specifications (TS) 3.5.1. 'ECCS - Operating' Condition D had been previously entered on 2/25/07 at 1500, which required maintaining the Reactor Core Isolation Cooling (RCIC) system operable and restoration of HPCI operability in 14 days. All other ECCS systems are operable including RCIC. The LCO allowed outage time is due to expire on 3/11/07 at approximately 1500 hours. The licensee notified the NRC Resident Inspector. UPDATE FROM TURKAL TO KNOKE AT 11:33 EDT ON 04/26/07 * On February 28, 2007, at 0540 hours, the Control Room Supervisor made a notification (Event Number 43197) to the NRC Operations Center in accordance with 10 CFR 50.72(b)(3)(v)(D) (i.e., 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 notification was made as a result of an unexpected high level alarm condition for the High Pressure Coolant Injection (HPCI) system barometric condenser, which was received during the post-maintenance operability testing of the HPCI system. At the time of discovery, the HPCI system was inoperable; having been properly removed from service for planned maintenance. It was believed that check valve 2-E41-F048, which is in the discharge piping of the HPCI barometric condenser condensate pump, downstream of a connection from the HPCI lube oil cooler cooling water discharge line, did not open, as required, during the HPCI post maintenance operability run. With valve 2-E41-F048 closed, there is a potential for inadequate cooling flow for the HPCI lube oil and, as such, a potential that the HPCI system could be inoperable as a result. Basis for Retraction Upon further review, it has been determined that the 2-E41-F048 functioned properly during the post-maintenance HPCI system operability testing. The valve was disassembled and inspected during the recent Unit 2 refueling outage and confirmed to be operating properly. As such, adequate HPCI lube oil cooling existed and HPCI could have fulfilled its intended safety function. Physical inspection of the HPCI lube oil cooler piping, during the Unit 2 refueling outage, revealed that the lube oil cooler outlet orifice was missing. The missing orifice can result in higher than design flows through the lube oil cooler and higher backpressure at the barometric condenser condensate pump discharge. The higher backpressure can affect the ability to pump down the barometric condenser vacuum tank. Additionally, during troubleshooting activities performed prior to the refueling outage, valve 2-E41-F058, which is in the discharge piping of the HPCl barometric condenser condensate pump, upstream of the connection from the HPCI lube oil cooler cooling water discharge line, showed evidence of sticking. Either of these conditions could have caused the barometric condenser high level alarm without affecting HPCI lube oil cooling. If the barometric condenser becomes completely full, a relief valve on the tank will lift and relieve water to the HPCI room sump. The room sump pump has adequate capacity to keep up with the maximum expected flow. Operability of the HPCI system will not be affected by this condition. The higher than design cooling water flow rate does not adversely affect the capability of the lube oil cooler to remove heat from HPCI system lube oil and, as such, does not affect HPCI operability. Additionally, physical inspection of the cooler during the refueling outage found no damage or erosion of the cooler internals, and the cooler was successfully pressure tested. The barometric condenser condensate pump, barometric condenser vacuum pump, and barometric condenser water level instrumentation are not required to support operability of the HPCI system. Investigation of this condition is documented in the corrective action program in Nuclear Condition Report (NCR) 223820. On this basis, the HPCI system was capable of performing its function to mitigate the consequences of an accident and the issue is not reportable under 10 CFR 50.72(b)(3)(v)(D). The NRC resident was notified of this retraction." Notified R2DO(Payne). UPDATE FROM TURKAL TO KNOKE AT 09:30 EDT ON 06/04/09 * On February 28, 2007, at 0540 hours, the Control Room Supervisor made a notification (EN 43197) to the NRC Operations Center in accordance with 10 CFR 50.72(b)(3)(v)(D), 'any event or condition that at the time of discovery could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident'. The notification was made as a result of an unexpected high level alarm condition for the High Pressure Coolant Injection (HPCI) system barometric condenser, which was received during the post-maintenance operability testing of the HPCI system. Revised Basis for Retraction On April 26, 2007, EN 43197 was retracted. The basis for the retraction stated that the 2-E41-F048 functioned properly and adequate HPCI lube oil cooling existed. It also attributed the high level in the HPCI barometric condenser to either a missing lube oil cooler outlet orifice or potential sticking of valve 2-E41-F058 versus the originally believed malfunction of the 2-E41-F048 valve. In either case, the retraction stated that if the barometric condenser becomes completely full, a relief valve (2-E41-F018) on the tank will lift and relieve water to the HPCI room sump. The room sump pump has adequate capacity to keep up with the maximum expected flow. As such, operability of the HPCI system would not be affected by either a missing lube oil cooler outlet orifice or potential sticking of valve 2 -E41-F058. During the Unit 2 refueling outage, which began on February 28, 2009, it was discovered that the HPCI barometric condenser relief valve (2-E41-F018) had been assembled incorrectly and would not have functioned as described in the April 26, 2007 retraction of EN 43197. However, EN 43197 can be retracted without relying on proper operation of the relief valve. At the time of the event, the HPCI barometric condenser condensate pump, the HPCI barometric condenser vacuum pump, and the HPCI barometric condenser water level instrumentation were functioning properly and would have prevented condensate from reaching the HPCI turbine casing. On this basis, the HPCI system was capable of performing its function to mitigate the consequences of an accident and the issue is not reportable under 10 CFR 50.72(b)(3)(v)(D). The NRC Resident Inspector was notified of this revised retraction. Notified R2DO (Mark Lesser)
ENS 43177	20 February 2007 23:20:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Hpci Declared Inoperable Due to an Apparent Equipment Malfunction	On February 20, 2007 at 1720 hours, the High Pressure Coolant Injection (HPCI) system was declared inoperable. During a system walkdown the HPCI Motor Speed Changer (MSC) was discovered energized. The MSC controls HPCI turbine speed during system startup and shutdown, and should not have been energized at the time of the walkdown. Additional troubleshooting determined the MSC was not functioning properly, rendering the HPCI system inoperable. This event is being reported as a condition that could have prevented fulfillment of a safety function in accordance with 10CFR50.72(b)(3)(v)(D) because the HPCI system is a single train system and the loss of HPCI could impact the plant's ability to mitigate the consequences of an accident. In accordance with Technical Specification Action 3.5.1.F, the Reactor Core Isolation Cooling (RCIC) system was confirmed operable. Further troubleshooting and engineering evaluations are continuing. The licensee informed the NRC Resident Inspector. * * RETRACTION AT 1146 ON 3/5/2007 FROM ERIK MARKS TO MARK ABRAMOVITZ * * * The purpose of this report is to retract the ENS report made on February 20, 2007 at 1720 hours (ENS #43177) under 10CFR50.72(b)(3)(v)(D), a condition that could have prevented fulfillment of a safety function. The initial report was made when the Unit 2 High Pressure Coolant Injection (HPCI) system was declared inoperable following a system walkdown that discovered the HPCI Motor Speed Changer (MSC) was energized. The MSC controls HPCI turbine speed during system initiation, and should not have been energized at the time of the walkdown since the system was not in operation. During troubleshooting the MSC responded slower than expected. Due to this unexpected behavior, it was not certain if HPCI could have met its design basis requirements. However, a subsequent engineering evaluation has determined that at the time of discovery, the HPCI system injection time would have been sufficient to meet its safety function. Repairs to HPCI were completed and the system was declared operable on February 22, 2007 at 0036 hours. The licensee notified the NRC Resident Inspector. Notified the R3DO (Orth).
ENS 43159	9 February 2007 18:08:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge	Reactor Scram Due to Low Reactor Water Level	At 1208(CST) on 02/09/2007 with Unit 3 at 100% power, an automatic reactor scram (RPS) was received due to lowering water level. Loss of water level was due to lowering condensate flow which in turn caused a reduction in feedwater flow. Reactor water level lowered to -45 Inches. High Pressure Coolant Injection and Reactor Core Isolation Cooling systems initiated as expected. Additionally, the Recirculation Pump breakers tripped as expected. All expected Primary Containment Isolations, Group 2 (RHR Shutdown Cooling), Group 3 (RWCU), Group 6 (Ventilation), and Group 8 (TIP) were received along with the auto start of Control Room Emergency Ventilation (CREV) and 3 Standby Gas Treatment (SBGT) trains. Unit 2 was at 80% power and was unaffected by the event. Investigation has been initiated as to the cause of the lowering condensate flow. This event is reportable as a 4-hour and 8-hour non-emergency notification in accordance with 10 CFR50.72(b)(2)(iv)(B) as any event or condition that results in actuation of the reactor protection system (RPS) when the reactor is critical, 10 CFR 5172(b)(3)(Iv)(A) as any event or condition that results in valid actuation of any of the systems listed in paragraph (b)(3)(Iv)(b), and 10 CFR 50.72(b)(2)(Iv)(A) as any event or condition that results or should have resulted In ECCS discharging to the reactor coolant system. All control rods fully inserted, the electrical grid is stable. Decay heat is being removed via the turbine bypass valves to the main condenser. The licensee has notified the NRC Senior Resident Inspector. There was no excessive cooldown rate during the injection phase as cooldown rate did not exceed 100 degrees Fahrenheit. Total injection time for both HPCI and RCIC systems was approximately 2 minutes which resulted in approximately 13,000 gallons of coolant from the condensate storage tank (CST) entering the reactor vessel. Primary plant temperature and pressure are 531 degrees Fahrenheit and 928 psig, respectively.
ENS 43062	25 December 2006 10:39:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge	Reactor Scram Due to Trip from Neutron Monitoring System	On 12/25/06 at approximately 05:39 an automatic reactor scram occurred on Brunswick Unit 2. The Reactor Protection System (RPS) actuated on Neutron Monitoring System (APRM/OPRM) trip for APRM 2 and 4. All control rods properly inserted when the scram occurred from the RPS signal. Reactor water level reached low level 1 (LL1) and low level 2 (LL2) as a result of the scram. The LL1 signal causes a Group 2 (floor and equipment drain isolation valves), Group 6 (monitoring and sampling isolation valves) and Group 8 (shutdown cooling isolation valves) isolation signal. The LL1 isolations occurred as designed. The LL2 (signal) causes a Reactor Core Isolation Cooling (RCIC) system actuation, High Pressure Coolant Injection (HPCI) system actuation, Group 3 (reactor water cleanup valves) isolation signal, a secondary containment isolation signal, a Standby Gas Treatment (SBGT) initiation signal, a Control Room Emergency Ventilation (CREV) initiation signal, Reactor Recirculation Pump trip and an Alternate Rod Insertion (ARI) actuation signal. The low level 2 condition was reached momentarily and did not affect all instruments due to calibration differences. Initial assessment concludes that the appropriate LL2 isolations and actuations occurred as designed. Further evaluation of LL2 isolation and actuations will be conducted. The RCIC system actuation resulted in injection into the reactor as designed. The HPCI system actuated but did not inject because reactor water level was recovered. The plant is in a stable condition. An investigation is in progress to determine the cause of the Neutron Monitoring System trip. RCIC started momentarily and then was secured. Reactor water level being maintained via normal feedwater system. Decay heat being removed through the bypass valves. Normal electrical lineup for shutdown. EDGs available. Unit 1 not affected by this transient. The licensee notified the NRC Resident Inspector.
ENS 42955	1 November 2006 23:37:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(a)(1)(i), Emergency Class Declaration 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge	Unit 2 Declared an Unusual Event Due to Loss of Offsite Power to the 4Kv Emergency Buses	At 1823 EST, Unit 2 was manually scrammed due to a loss of offsite power from the Startup Auxiliary Transformer to both 4KV Emergency (E) buses. Both Emergency Diesel Generators (EDGs) 3&4 autostarted and re-energized the affected electrical buses. At 1823 EST, an Unusual Event was declared based on EAL 06.01.01, "Inability to power either 4KV E bus from offsite power." Unit 2 is currently stable in mode 3, Hot Shutdown, with MSIVs closed and HPCI controlling pressure and RPV Water Level. All control rods fully inserted following the manual reactor scram. The licensee determined that no emergency facilities will be activated and that no offsite assistance is needed at this time. The licensee informed both state and local agencies and will inform the NRC Resident Inspector. * * UPDATE PROVIDED BY JOEL LEVINER TO JEFF ROTTON AT 2214 EST ON 11/01/06 * * * On 11/01/06 at approximately 18:23 (EST) Brunswick Unit 2 experienced a loss of the unit's Startup Auxiliary Transformer and a loss of reactor forced circulation. A manual reactor scram was performed as required by station Abnormal Operating Procedures. Due to the loss of the Startup Auxiliary Transformer and subsequent manual reactor scram, a loss of Offsite Power resulted to the unit's power buses when unit shutdown was completed. All control rods properly inserted when the manual reactor scram was performed. All four site emergency diesels started and diesels 3 and 4 are supplying the Unit 2 emergency buses. Reactor water level reached low level 1 (LL1) and low level 2 (LL2) as result of the reactor scram and loss of offsite power. The LL1 signal resulted in Group 2 (floor and equipment drain isolation valves), Group 6 (monitoring and sampling isolation valves) and Group 8 (shutdown cooling isolation valves) isolation signals. All low level 1 isolations occurred as designed. The LL2 resulted in a Reactor Core Isolation Cooling (RCIC) system actuation, High Pressure Coolant Injection (HPCI) system actuation, Group 3 (reactor water cleanup valves) isolation signal, a secondary containment isolation signal, a Standby Gas Treatment (SBGT) initiation signal, a Control Room Emergency Ventilation (CREV) initiation signal, and an Alternate Rod Insertion (ARI) actuation signal. All isolation and actuations occurred as designed with the exception the CREV initiation and ARI actuation. CREV initiation and ARI actuations were performed by manual actions. The failure of the CREV and ARI initiation/actuations are under investigation. The RCIC and HPCI systems were used to restore reactor water level to the normal operation band. Reactor vessel pressure is being controlled in the normal band with manual operation of Safety Relief Valves (SRV), and HPCI/RCIC in pressure control mode. The Main Steam Isolation Valves (MSIVs) (Group 1) and the drywell pneumatic isolation valves (Group 10) closed on the loss of power. The plant is a stable condition. Troubleshooting activities are in progress to determine the cause of the event. At 1910, the NRC was previously notified of the Unusual Event declaration. Initial Safety Significance Evaluation: The safety significance of this event is minimal and Unit 2 is in a stable condition. All control rods properly inserted when the manual scram was performed. Plant safety systems responded as required with the exception of the CREV and ARI systems which did not automatically initiate but functioned properly when manually actuated. All four emergency diesels started and Unit 2 diesels 3 and 4 are supplying the Unit 2 emergency buses. Reactor pressure and level are being controlled per procedure, with HPCI and RCIC. Actions are in progress to re-establish off site power supply to emergency buses 3 and 4 via backfeed through the Unit Auxiliary Transformer (UAT). Corrective Actions: Actions are in progress to re-establish offsite power supply to emergency buses 3 and 4 via backfeed through the UAT. Investigations are in progress to determine the cause of the SAT failure and the failure of CREV and ARI to auto-initiate. The licensee has notified the NRC Resident Inspector and the State and local emergency agencies. Update provided also added the following reportable notifications due to the event: 10CFR50.72(b)(2) (iv)(A) and(iv)(B) and 10CFR50.72(b)(3)(iv)(A). Notified R2DO (Evans). * * UPDATE PROVIDED BY MARK SCHALL TO JEFF ROTTON AT 1805 EST ON 11/02/06 * * * Licensee reported that the Unusual Event was terminated at 1745 EST on 11/02/06 after Offsite power was restored to both 4 KV E Buses from the Unit Auxiliary Transformer (UAT) on Unit 2. The #3 and #4 EDGs have been secured and are in Standby. #1 EDG remains inoperable and #2 EDG is presently being Load Tested. The licensee will be notifying the NRC Resident Inspector and the State and local emergency agencies. Notified R2DO (Evans), NRREO (Richards), IRD Manager (Leach), DHS (Barnes), and FEMA (Kuzia).
ENS 42929	24 October 2006 06:42:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Core Spray (Hpcs) Declared Inoperable for Approx. 3.4 Hours	At 0142 on October 24, 2006, while aligning the High Pressure Core Spray system for surveillance testing of the Reactor Core Isolation Cooling System Storage Tank Level instrumentation, 1E22-F015, the Suppression Pool suction valve for the High Pressure Core Spray pump, failed to stroke fully open. High Pressure Core Spray was declared inoperable as a result. This event is considered a loss of a single train system needed to mitigate the consequences of an accident. The High Pressure Core Spray system was restored to an operable condition at 0506 on October 24, 2006 after the suction valve was successfully stroked open and the HPCS suction source was aligned to the Suppression Pool in accordance with Technical Specification Limiting Condition for Operation 3.5.1. The cause of the event is currently under investigation. All other Emergency Core Cooling systems were fully operable during the time period HPCS was inoperable. The Senior Resident Inspector has been notified by the licensee. * * RETRACTION FROM SIMPSON TO HUFFMAN AT 1534 EST ON 11/10/06 * * * Upon further review of this event, the High Pressure Core Spray (HPCS) system remained operable. Based upon valve motor operator thrust verification testing data and troubleshooting, the cause of the suppression pool suction valve for the HPCS pump stopping in mid-position was determined to be tripping of the open-direction torque switch prior to the open limit switch setpoint. Normally, the condition of the open-direction torque switch has no safety-related consequence since the torque switch is bypassed during design basis events and the valve's motor gearing capability is sufficient to open the valve when the torque switch is bypassed. During this event, as directed by the surveillance test procedure, operators placed the HPCS Motor Operated Valve (MOV) test switch to the test position which resulted in the open-direction torque switch not being bypassed (i.e., was in the circuit) during repositioning of the HPCS suppression pool suction valve. Due to placing the HPCS MOV test switch to test, operators entered the action of Operational Requirements Manual section 2.5.2 (Motor Operated Valves Thermal Overload Protection). The action requires operators to return the MOV test switch to normal (removing the torque switch from the circuit) if an emergency condition occurs requiring valve repositioning. As operators were opening the HPCS suppression pool suction valve for testing, suction for the HPCS pump was aligned from the RCIC storage tank. When the HPCS suction valve from suppression pool stopped in mid-position, the HPCS suction valve from the RCIC storage tank was still fully open (per design, stays full open until the HPCS suppression pool suction valve is full open). Therefore, if an accident occurred requiring HPCS to initiate and inject water into the reactor pressure vessel during this event suction would have initiated from the RCIC storage tank. The HPCS system can take suction from either the RCIC storage tank or the suppression pool, and a HPCS initiation signal does not automatically swap HPCS pump suction from the RCIC storage tank to the suppression pool or vice versa. The operators immediately recognized the HPCS suppression pool suction valve did not fully open. If an accident condition occurred, operators would reposition the HPCS MOV test switch to Normal (to bypass the open torque switch). In the event a condition requiring a HPCS suction transfer to the suppression pool occurred, the suppression pool suction valve would fully open and the RCIC storage tank suction valve would fully close, completing the required suction shift. On this basis, the HPCS system was capable of performing its function to mitigate the consequences of an accident and this issue is not reportable under 10 CFR 50.72(b)(3)(v)(D). The NRC Resident was notified of this retraction. R3DO(Cameron) notified.
ENS 42921	19 October 2006 22:56:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge	Automatic Scram Following Spontaneous Feedwater Valve Closure	At 1756 CDT with the plant operating at 100% power, a reactor scram occurred in response to a reactor water level 3 signal from an apparent loss of feedwater. Both feedwater injection lines isolated when isolation valves were inadvertently closed, The cause of the isolation valve closure is under investigation. When reactor water level lowered to level 2, high pressure core spray (HPCS) initiated automatically and recovered water level. The reactor core isolation cooling system (RCIC) was tagged out for maintenance at the time of the event. Following the scram, main steam isolation valves isolated on low main steam header pressure. As a result, reactor pressure control was being controlled with the safety relief valves. SRV pressure control in turn led to EOP entry conditions on containment pressure and suppression pool level. Both feedwater lines were opened, and normal reactor level control was restored. The MSIV's were opened and pressure control was returned to the turbine bypass valves and the main condenser. Initial indications are that all plant equipment functioned as designed with the exception of the 'B' feed pump which experienced an apparent seal failure. The plant is stable in Mode 3. All plant conditions are understood. This event is being reported in accordance with 10CRF50.72(b)(2) as an RPS actuation and an injection of HPCS into the reactor vessel, and in accordance with 10CRF50.72(b)(3) as a loss of safety function of HPCS, as it was manually disabled during recovery from the event. The HPCS Injection valve was manually overridden closed for 76 minutes. In addition,' containment isolation valves in multiple systems actuated in response to the RPV level 2 signal. Reactor vessel water level lowered to below level 2. Decay heat is being removed by normal feedwater to the reactor vessel steaming to the main condenser. Offsite power is available and stable. Emergency Diesel Generators are available. The licensee notified the NRC Resident Inspector. * * UPDATE FROM LICENSEE (D. WILLIAMSON) TO M. RIPLEY 1740 EDT ON 10/20/06 * * * The closure signal to the main feedwater header isolation valves occurred when part of a chart recorder above the isolation valve control switches was dropped by an operator. The operator was attempting to adjust the paper drive mechanism in the recorder, and accidentally dropped the paper cartridge, which struck the 'CLOSE' pushbuttons on the isolation valve control switches. Following the scram, there was a delay in placing the reactor mode switch in the 'SHUTDOWN' position, which is an immediate action required by procedure. Placing the mode switch to 'SHUTDOWN' bypasses the reactor low steam pressure MSIV Isolation. Reactor steam pressure began dropping after the scram, until it reached the MSIV automatic closure setpoint, and the MSIVs isolated, In addition the licensee corrected one of the 10 CFR Section entries from "50.72(b)(3)(v)(A) POT UNABLE TO SAFE SD" to "50.72(b)(3)(v)(D) ACCIDENT MITIGATION." The licensee notified the NRC Resident Inspector. Notified R4 DO (D. Powers) and NRR EO (N. Chokshi)
ENS 42906	13 October 2006 17:57:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Coolant Injection (Hpci) System Declared Inoperable Due to Potential Turbine Exhaust Diaphragm Failure	On October 13, 2006 at 1357 (EST) Unit 2 HPCI system was declared inoperable due to indications of a leaking rupture diaphragm in the turbine steam exhaust line. This determination was made when water was discovered in the E41-PSH-N012A and E41-PSH-N012C instrument lines during the performance of 0MST- HPCI23Q (HPCI Turbine Exhaust Diaphragm High Pressure Instrument Channel Calibration). TS LCO 3.5.1. 'ECCS - Operating,' Condition D was entered for the HPCI system being declared inoperable. The Reactor Core Isolation Cooling (RCIC) system was verified operable per Required Action D.1. Required Action D.2 of TS LCO 3.5.1 requires the HPCI system to be returned to operable status within 14 days. The initial safety significance of this condition is considered to be minimal. The RCIC system and all other required ECCS, are operable at this time. HPCI has been isolated and will be placed under clearance to allow the turbine exhaust diaphragm to be inspected and replaced if necessary The (NRC) Resident Inspector has been notified. * * * RETRACTION FROM M. TURKAL TO P. SNYDER ON 12/05/06 * * * Upon further review, it has been determined that the HPCI system was not rendered inoperable as a result of the condition identified on October 13, 2006. The HPCI system is equipped with two rupture diaphragms on the steam exhaust line installed in series. Between the rupture discs are four instrument lines leading to pressure switches (i.e., E41-PSH-N012A, N012B, N012C, and N012D) and a header vent line that vents to the HPCI room atmosphere. The HPCI Turbine Exhaust Diaphragm Pressure - High signals are initiated from these pressure switches; which are required to be operable per Technical Specification 3.3.6.1, 'Primary Containment Isolation Instrumentation,' to isolate the HPCI exhaust line in the event of a degraded inner rupture disc, before the redundant outer disc is significantly challenged. This isolation provides equipment protection and (is) not assumed in any transient or accident analysis. The suspected leaking inner rupture diaphragm was confirmed to be fully intact and, as such, not a source of the water (i.e., approximately 1.125 quarts) in the E41-PSH-N012A and E41-PSH-N012C instrument lines. The most likely source of this water is residual water remaining from a rupture disc failure that occurred in November 2003. Engineering has evaluated the potential impact of the residual water and determined that both the HPCI system and the HPCI Turbine Exhaust Diaphragm Pressure - High isolation function remained operable. There was not sufficient water in the lines to affect the function of the HPCI rupture diaphragms if required. In addition, the quantity of water discovered would not have prevented a HPCI initiation, if required, as evidenced by successful operation of the Unit 2 HPCI system on at least 10 occasions since November 2003. The Technical Specification required function of the pressure switches was not impacted by the presence of residual water. Investigation of this condition is documented in the corrective action program is Nuclear Condition Report (NCR) 209265. On this basis, the HPCI system was capable of performing its function to mitigate the consequences of an accident and the issue is not reportable under 10 CFR 50.72(b)(3)(v)(D). The NRC Resident Inspector was notified of this retraction. Notified R2DO (Landis).
ENS 42889	7 October 2006 21:50:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(2)(i), Tech Spec Required Shutdown 10 CFR 50.72(b)(3)(ii)(A), Seriously Degraded 10 CFR 50.72(b)(3)(v)(C), Loss of Safety Function - Release of Radioactive Material	Technical Specification Required Shutdown Due to Loss of Primary Containment Integrity	At 17:50, on 10/07/2006, the Peach Bottom Atomic Power Station identified a crack approximately 4 inches long on a Unit 2, Reactor Core Isolation Cooling (RCIC) test line, as the line penetrates the Suppression Pool of Primary Containment. The degraded piping represents a loss of primary containment integrity, placing one of the principle safety barriers in a 'Seriously Degraded' condition as defined by 10CFR50.72 (b)(3)(ii)(A). This condition required a Reactor Shutdown per the plants Technical Specifications (TS) (TS 3.6.1.1). Unit 2 was manually scrammed, at 20:16, in order to shutdown the reactor and place the unit in Mode 3 per the Technical Specifications. The TS required shutdown is reportable per 10CFR50.72(b)(2)(i). The unplanned reactor scram is reportable per 10CFR50.72(b)(2)(iv)(B). The reactor scram and resultant Emergency Safety Feature actuations were completed as required. In addition, the loss of primary containment integrity represents a condition that 'could have prevented the fulfillment of a safety function of a structure required to control the release of radioactive material' and/or 'mitigate the consequences of an accident.' This is reportable per 10CFR50.72(b)(3)(v)(C) and (D). Unit 2 is currently shutdown, Mode 3, with an RPV cooldown in progress, with plans to Enter Mode 4 by 02:00 on 10/08/06. All control rods fully inserted on the Manual Reactor Scram. The reactor is currently being fed from the condensate system with decay heat being removed to the condenser via the MSL drains. The electric plant is in a normal shutdown lineup. See EN # 42887 for related NOTICE OF UNUSUAL EVENT. Additional 10 CFR Section not listed above: 50.72(b)(3)(v)(D) ACCIDENT MITIGATION The licensee notified the NRC Resident Inspector.
ENS 42810	28 August 2006 17:00:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Coolant Injection Overspeed Trip Mechanism Failed to Reset	The High Pressure Coolant Injection system (HPCI) over-speed trip tappet did not reset as expected during the trip tappet test after securing from a successful HPCI operability run, thereby preventing a re-start of the HPCI system. The Automatic Depressurization System (ADS), Core Spray sub-systems, Low Pressure Coolant Injection (LPCI) and the Reactor Core Isolation Cooling (RCIC) systems are operable." The unit is in a 14 day LCO for this event. The licensee will notify the NRC Resident Inspector. * * RETRACTION FROM MIKE PLETCHER TO JOE O'HARA AT 1130 ON 9/28/06 * * * NRC Notification 42810 was conservatively made to ensure that the Eight-Hour Non-Emergency reporting requirements of 10CFR50.72 were met pending the evaluation of condition observed with the High Pressure Coolant Injection (HPCI) Overspeed Trip reset feature that was discovered while performing scheduled testing for the HPCI System. During surveillance testing on 08/28/06, the HPCI System was started and satisfied the Technical Specification requirements designed to demonstrate HPCI System Operability. Subsequently, while testing the specific components of the system, the HPCI Overspeed Trip functioned as expected, but would not reset when manually depressed (locally). The Shift Manager declared the system inoperable and remained in the Limited Condition of Operation (LCO) that was entered prior to commencing the testing activities. Subsequent investigation determined that the reset function of the HPCI turbine overspeed trip device is not required to support HPCI from performing the system safety functions as described in the station design and licensing basis. ENS Event Number 42810, made on 08/28/06, is being retracted. The licensee notified the NRC Resident Inspector. The R1DO(Hott) has been notified.
ENS 42807	27 August 2006 22:05:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation	Reactor Trip Due to Reactor High Water Level	At 1705 CDT on August 27, 2006, a high water level trip occurred resulting in a reactor scram. All control rods fully inserted on the scram signal. Reactor water level is being controlled in the normal operating band and reactor pressure is being controlled in a normal band. The apparent cause of the high level trip was a High Pressure Core Spray (HPCS) system initiation. There is no indication that the HPCS initiation was caused by an actual parameter reaching a trip setpoint. Division four nuclear system protection system (NSPS) is the current focus of troubleshooting activities. The Reactor Core Isolation Cooling (RCIC) system isolated after the scram. Troubleshooting is in progress to determine the cause. Both offsite power sources are operable and emergency diesel generators are operable and available if required. All safety related systems are available if required. The licensee notified the NRC Resident Inspector.
ENS 42657	21 June 2006 04:15:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Coolant Injection (Hpci) Declared Inoperable Due Excessvie Aux Oil Pump Motor Current	During routine weekly operation of High Pressure Coolant Injection (HPCI) Auxiliary Oil Pump (AOP), 2E41C002-3, the pump displayed indications of excessive motor current after the pump had been inservice for approximately 45 minutes. The pump was secured and, following review of electrical diagrams and consultation with Electrical Maintenance, the operating current of the AOP was checked and determined to be excessive. The AOP was declared inoperable, with the AOP inoperable, the HPCI system cannot be considered operable. The HPCI System is a single train ECCS system. Investigation into the cause of the high motor current is ongoing. All other Emergency Core Cooling Systems are fully operable including Reactor Core Isolation Cooling (RCIC). The NRC Resident Inspector was notified of this event by the licensee. UPDATE FROM A. DISMUKE TO J. KNOKE AT 0933 ON 07/21/06 *** Retraction of NRC Event # 42657: After further review and evaluation it has been determined that the eight hour call made June 21, 2006 per the guidance of 50.72(b)(3)(v)(D) should be retracted. On 06/21/2006 at approximately 0015 EDT, Unit 2 was at 100 percent Rated Thermal Power. During routine weekly operation of the High Pressure Coolant Injection (HPCI) Auxiliary Oil Pump, 2E41-C002-3, the pump displayed indications of excessive motor current after the pump had been in-service for approximately 45 minutes. Investigation revealed the running amps to be 46 amps with nameplate data running amps shown as 27 amps. An evaluation was performed for the as-found condition that considered the cause and effects of the increased running amps on the ability of the auxiliary oil pump to perform its design function. Specifically, the effect of a shunt resistor short to open was reviewed. Areas reviewed for impact were motor speed, system over pressurization, motor insulation, Environmental Qualification, and motor service life. The results of the evaluation showed that significant margin existed to ensure the auxiliary oil pump design function was maintained. Therefore, the auxiliary oil pump operability was maintained and HPCI operability was also maintained. The HPCI system was immediately removed from service using normal plant procedures; a work order initiated, and the existing motor was replaced to ensure continued long term reliability. The licensee notified the NRC Resident Inspector. Notified R2DO (Ernstes)
ENS 42549	4 May 2006 02:30:00	10 CFR 50.72(b)(3)(ii)(A), Seriously Degraded	Rcic Declared Inoperable Due to Degraded Flow Instrument	The licensee indicated the Reactor Core Isolation Cooling (RCIC) has been made inoperable by a degraded flow instrument. The deficiency will prevent RCIC from achieving its design flow of 410 gpm. The degraded condition limits the flow to 360 gpm. This condition put the licensee into LCO 3.5.3.A. To exit the LCO an I&C tech will need to perform a venting operation on the flow transmitter. The licensee will notify the NRC Resident Inspector. * * UPDATE AT 1252 EDT ON 5/4/06 FROM GENE DORMAN TO S. SANDIN * * * The licensee provided the following additional information: EVENT NOTIFICATION RETRACTION At 0607 on 05/04/2006 the James A. FitzPatrick Nuclear Power Plant notified the NRC Operations Center that, 'Reactor Core Isolation Cooling (RCIC) System has been made inoperable by a degraded flow instrument. The deficiency will prevent RCIC from achieving its design flow rate of 410 gpm. Estimated flow rate in the current condition is 360 gpm.' This notification was made pursuant to 10 CFR 50.72(b)(3)(ii)(A) 'Any event or condition that results in: (A) The conditions of the nuclear power plant, including its principal safety barriers, being seriously degraded;' Subsequent review of this event determined that the degradation of the RCIC System did not result in any of the plant's principal safety barriers (i.e., fuel cladding, reactor coolant pressure boundary, or the primary containment integrity) being degraded therefore, criterion 10 CFR 50.72(b)(3)(ii)(A) is not applicable to the event. Additionally the guidance contained in Regulatory Issue Summary (RIS) 2001-14, 'Position on Reportability Requirements for Reactor Core Isolation Cooling System Failure' was reviewed and it was confirmed that the RCIC System is not credited in the UFSAR for mitigating the consequences of a rod ejection accident, so the 10 CFR 50.72(b)(3)(v)(D) accident mitigation criterion does not apply. Consequently this notification is being retracted. The licensee informed the NRC Resident Inspector. Notified R1DO (Bellamy).
ENS 42479	5 April 2006 23:55:00	10 CFR 50.72(b)(3)(ii)(B), Unanalyzed Condition	Abnormal Operating Procedure (Aop) for Station Blackout Could Not Be Performed in Specified Time Period	DAEC (Duane Arnold Energy Center) abnormal operating procedure AOP 301.1 for Station Blackout specifies that 30 minutes are allowed to establish alternate ventilation for RCIC (Reactor Core Isolation Cooling) /HPCI (High Pressure Coolant Injection) rooms, switchgear rooms, battery rooms, and the Main control room. During validation demonstration conducted on April 5, 2006 for the NRC Components team (from NRC Region 3 Office) the 30 minutes requirement was not met with the control room alternate ventilation taking about 60 minutes and with the other areas also exceeding their time requirements. This event is reportable as an unanalyzed condition that significantly degraded plant safety pursuant to 10 CFR 50.72(b)(3)(ii) reportability notification. The NRC Resident Inspector was notified of this event by the licensee. * * RETRACTION FROM MURRELL TO HUFFMAN AT 1442 EDT ON 6/01/06 * * * Duane Arnold Energy Center is retracting event number 42479 which was reported to the NRC Operations Center on 4/5/06 at 1855. This event is now determined to be not reportable because further evaluation to assess the significance of the delays in establishing alternate control room ventilation determined that the delay did not result in an adverse temperature increase in the affected areas. Specifically, the control room and back panel area temperature rise was evaluated using a detailed mass and heat transfer model of the affected areas. The evaluation confirmed that delays in establishing alternate control room ventilation did not adversely impact station commitments to 10 CFR 50.63 or accident responses outlined in UFSAR Section 15.3.2. Other areas required to have alternate ventilation established within 30 minutes had previously been successfully validated. Therefore, this event is not reportable as an unanalyzed condition that significantly degraded plant safety. The analyses and the bases for this retraction can be found under the plant corrective action program. The licensee notified the NRC Resident Inspector. R3DO (Kozak) notified.
ENS 42272	18 January 2006 15:00:00	Other Unspec Reqmnt	24-Hour Condition of License Report Involving Fire Protection Program Non-Compliance	This notification is being made pursuant to the Perry Nuclear Operating License section 2.C.6 (violation of the Fire Protection Program). Incorrect configuration of Division 1 remote shutdown panel wiring was identified during performance of surveillance testing. This incorrect configuration is associated with the Reactor Core Isolation Cooling motor operated exhaust valve. In the event of a fire in the control room, the motor operated exhaust valve would have the potential for spurious operation caused by fire induced shorts prior to isolation from the control room. Repairs and operator actions could have been taken to restore the valve. However, these repairs and operator actions are not currently identified in the Fire Protection Safe Shutdown analysis or associated operating procedures. Therefore, for this issue Perry does not comply with the Perry Fire Protection Program. Repairs have been completed and configuration has been restored. The licensee will notify the NRC Resident Inspector.
ENS 42243	5 January 2006 15:30:00	10 CFR 50.72(b)(3)(ii)(B), Unanalyzed Condition	Unanalyzed Condition Involving Rcic Operation During Mcr Evacuation	During an engineering assessment, a condition was found which does not meet the assumptions of the River Bend post-fire safe shutdown analysis. 10CFR50 Appendix R states that for alternate shutdown capability (i.e. shutdown from outside the main control room), reactor coolant system process variables shall be maintained within those predicted for a loss of normal AC power, and the fission product boundary integrity shall not be affected. Generic Letter (GL) 86-10, 'Implementation of Fire Protection Requirements,' states that the following assumptions are required for evaluation of a control room fire: 1) fire-induced spurious operation of safe shutdown components has occurred; 2) offsite power is lost; and, 3) the emergency diesel generators (DGs) do not automatically start. Based on the conservative assumptions imposed by GL 86-10, the following control room fire scenario must be addressed. A fire is assumed to cause motor-operated valve E51-MOVF063, the inboard steam supply to Reactor Core Isolation Cooling (RCIC) turbine to close. The same fire requires the main control room (MCR) to be evacuated, and during relocation to the Division 1 Remote Shutdown panel, offsite power is lost. The post-fire safe shutdown analysis has evaluated RCIC to be available from the Remote Shutdown Panel in order to maintain reactor water level, and that the Division 1 and 3 DGs are started locally. The Division 2 DG is not analyzed to remain free of damage caused by the MCR fire. Since valve E51-MOVF063 is powered from Division 2, and there is no Division 2 power available to re-open the valve, steam would not be available to power the RCIC turbine. E51-MOVF063 is located in the drywell, making manual operation of the valve impractical. Therefore, RCIC is postulated to not be available to maintain reactor level. Establishing reactor level control is a time-critical function that is required to occur within ten minutes of MCR evacuation in order to meet one of the Appendix R safe shutdown performance goals. This condition involves compliance with 10CFR50, Appendix R. Plant equipment remains operable. The scope of this analysis deficiency is limited to the MCR fire scenario, with three concurrent failures. The MCR Is continuously manned. The affected cables in the MCR under-floor area are protected by fire detection and automatic suppression systems, which would rapidly detect and smother a fire. Introduction of ignition sources, such as work involving welding or grinding, is strictly controlled by station procedures. While the assumptions of the post-fire safe shutdown analysis are not met for this scenario, it has been verified that the components required to properly align the Division 1 Residual Heat Removal system in the low pressure coolant injection mode would be available at the Division 1 Remote Shutdown Panel. Control of three safety-relief valves is also available at the Division 1 Remote Shutdown Panel to depressurize the reactor vessel for low pressure injection. An analysis is under way to determine the response of reactor water level, given these conditions. The licensee notified the NRC Resident Inspector.
ENS 41844	14 July 2005 21:10:00	10 CFR 50.72(b)(3)(ii)(B), Unanalyzed Condition	Station Blackout Temperature Analysis Higher than Rcic Governor Documentation	During fact gathering in response to an NRC inspection inquiry, it was determined that documentation does not exist that demonstrates that the Reactor Core Isolation Cooling (RCIC) Electronic Governor Module (EGM) would be able to operate during the required Station Blackout (SBO) coping mission time at the postulated post SBO RCIC room temperature of 206.4F. Current documentation supports operation up to 150F. The EGM is a skid-mounted module that provides speed control signals for the RCIC Woodward Governor. Failure of the EGM would result in a loss of speed control for the RCIC turbine. This could result in an overspeed, underspeed or no change condition. Overspeed of the turbine would result in a mechanical overspeed trip. This device is not in the EQ program but is Augmented Quality. RCIC continues to perform its Technical Specification required functions as defined in the Bases of Technical Specification (TS) 3.5.3. The TS function is to respond to transient events by providing makeup coolant to the reactor. The RCIC Room temperatures for the postulated TS transient events is less than the currently documented component qualification temperature. The RCIC is not an ESF system and no credit is taken in the safety analysis for RCIC system operation but is retained in the TS based on its contribution to the reduction of overall plant risk per Criterion 4 of 10 CFR 50.36. The RCIC system design requirements ensure that the criteria of 10CFR50 Appendix A, GDC 33, are satisfied. Due to the lack of supporting documentation for the EGM, the beyond design basis regulatory SBO rule requirements of 10 CFR 50.63 may not be met. This condition could potentially result in an unanalyzed condition that could significantly degrade plant safety and is therefore reportable under 10 CFR 50.72(b)(3)(ii). An analysis of the RCIC Room Heat Up Rate calculation is being performed as there are conservatisms built into the calculation that when removed will result in a lower temperature than 206.4F. Additional actions in progress include, establishing appropriate protected pathways to minimize the potential for a Loss Of Off-Site Power which could result in a SBO, performance of temperature qualification testing at SBO temperatures for the EGM, and performance of an extent of condition review for remaining RCIC components to ensure temperature qualification is met for the SBO rule. In parallel with temperature qualification testing, a modification to relocate the EGM to an area outside the RCIC room that has a lower SBO profile temperature is being pursued in the event that temperature qualification is not successful. The licensee notified the NRC Resident Inspector. * * RETRACTION FROM D. COVEYOU TO W. GOTT AT 1427 EDT ON 8/16/05 * * * A 8-hour notification was made on July 14, 2005, in accordance with 10 50.72(b)(3)(ii)(B), Unanalyzed condition. The report was made because documentation did not support the continued operation of Reactor Core Isolation Cooling (RCIC) Electronic Governor Module (EGM) during the required Station Blackout (SBO) coping mission. Since the initial report, the post SBO room heatup calculation was evaluated and determined that the decay heat removal function during the SBO coping mission was met. The decay heat removal function during SBO coping period is achieved by either High Pressure Core Spray (HPCS) or RCIC systems. In addition, the other RCIC functions (i.e., Remote Shutdown, and Safe Shutdown Fire) were evaluated and determined to be met. Since the RCIC functions and the decay heat removal and vessel inventory functions during the SBO coping mission were maintained, the plant was not in an unanalyzed condition and this issue is not reportable. Since the condition is not reportable EN 41844 is retracted. The licensee notified the NRC Resident Notified R3DO (K. O'Brien)
ENS 41790	23 June 2005 20:46:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Unit Experienced an Automatic Reactor Scram Due to a Loss of Feedwater Flow	On June 23, 2005 at 1348 PDT Columbia Generating Station experienced a Reactor Protection System (RPS) actuation and closure of all Main Steam Isolation Valves (MSIV) while operating at approximately 25% power. Currently, Reactor Pressure Vessel (RPV) level is being controlled using the Reactor Core Isolation Cooling (RCIC) system and RPV pressure is stable at approximately 800 psi. There was no automatic ECCS system injection. At this time, the plant is stable and indications show that the RPS actuation and closure of MSIVs was initiated in response to a valid low RPV water level signals that occurred because of a loss of feedwater flow. Determination of the cause of the loss of feedwater flow is ongoing at this time. All control rods fully inserted. The licensee informed the NRC Resident Inspector.
ENS 41787	22 June 2005 04:40:00	10 CFR 50.72(b)(3)(iv)(A), System Actuation	Multiple Specified Systems Actuations Due to Loss of Ac Safety Related Buses	At 23:40 CDST, LaSalle Unit 2 experienced a trip of the 4160 Volt AC feed breaker to 480 Volt AC Safety Related buses 235X & 235Y. As a result of this feed breaker trip, containment isolation valves closed in multiple systems. The systems which isolated included Containment Monitoring System, Drywell Floor Drains and Drywell Equipment Drains, Reactor Recirculation Flow Control Hydraulic System, Drywell Instrument Nitrogen System, Reactor Water Cleanup System, and Reactor Recirculation Sample System. This event is reportable under 10 CFR50.72(b)(3)(iv)(A). In addition to the- above mentioned system isolations, the following plant responses occurred due to the loss of these 480 Volt AC buses: Reactor Building Ventilation was lost due to the closure of the secondary containment isolation dampers; Multiple Division 1 containment isolation valves lost their AC power source, a 1/2-SCRAM occurred due to the loss of the 2A Reactor Protection System Motor-Generator set, the DC charger feed to the Division 1 DC Battery/Bus was lost, and the battery is currently maintaining availability of DC power to the bus. Troubleshooting has determined that the cause of the breaker trip was due to a defective neutral ground current protective relay. This relay has been replaced and the buses have been re-energized. System restoration is currently in progress. The licensee informed the NRC Resident Inspector. * * UPDATE FROM JEFF WILLIAMS TO GERRY WAIG AT 1217 EDT ON 06/22/05 * * * The following is an update to EN# 41787. Restoration of all required safety systems with the exception of the Reactor Core Isolation Cooling (RCIC) system has been completed. The associated ECCS systems were filled, vented and restored to an available status at 0630 CDST and full operability established at 0803 CDST. The Division 1 DC battery was fully recharged and returned to an operable status at 0803 CDST. Restoration of the RCIC system and investigation into the cause of the relay failure is currently in progress. The licensee has notified the NRC Resident Inspector. Notified R3DO (Bruce Burgess).
ENS 41650	29 April 2005 06:27:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Reactor Core Isolation Cooling Full Flow Test Line May Not Isolate	On 4/28/05 Grand Gulf provided a call in on an issue with (two) secondary containment isolation valves on the Main Steam Line drain system. (See EN-41645) A preliminary detailed review of similar valves has been completed. An additional concern with the Reactor Core Isolation Cooling (RCIC) full flow test line was noted. Specifically preliminary engineering evaluation indicates that during full flow test with flow to the Condensate Storage Tank concurrent with a high drywell pressure secondary containment isolation signal the differential pressure across the valves may prevent adequate design bases closure. Pending further evaluation this issue is conservatively considered reportable under 10CFR50.72(B)(3)(v)(d). Testing of Reactor Core Isolation Cooling with return to the Condensate Storage Tank has been suspended until resolution of this issue. The licensee notified the NRC Resident Inspector.
ENS 41582	9 April 2005 05:50:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation	Reactor Scrammed from 61% Power Due to Low Reactor Water Level	On 04/09/05 at approximately 00:50 an automatic reactor scram occurred on Brunswick Unit 2. The Reactor Protection System (RPS) actuated on low reactor water level (LL1). All control rods inserted from the RPS signal. The LL1 signal also provided a Group 2 (floor and equipment drain isolation valves), 6 (monitoring and sampling isolation valves) and 8 (shutdown cooling isolation valves) isolation signal for the respective containment Isolation valves. Reactor low level 2 (LL2) resulted in a Reactor Core Isolation Cooling (RCIC) system actuation and injection into the reactor. The High Pressure Coolant Injection (HPCI) system actuated but did not inject because reactor water level recovered. The Reactor Water Cleanup system (RWCU) isolated (Group 3 isolation). Secondary Containment isolated and the Standby Gas Treatment (SBGT) system initiated. An Alternate Rod Insertion signal was received and the Reactor Recirculation Pumps tripped as designed. An investigation is in progress to determine the cause of the reactor level transient. Safety systems and isolations functioned as designed. The NRC Resident Inspector was notified.
ENS 41499	16 March 2005 17:43:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Core Spray System Inoperable Due to Degraded Pump Motor Air Deflector	The following information was provided by the licensee via facsimile (licensee text in quotes): At 0943 with Columbia Generating Station operating at 100% power the High Pressure Core Spray (HPCS) system was taken out of service for maintenance. During the maintenance activity, severe cracking and degradation was discovered on the upper air deflector of the HPCS pump motor. This component functions to direct air into the motor housing to provide cooling while the system is operating. A preliminary evaluation determined this represents a condition that at the time of discovery could have prevented fulfillment of the safety function of the HPCS system to mitigate the consequence of an accident and is reportable pursuant to 10 CFR 50.72(b)(3)(v)(D). Upon discovery of this condition plant operators fulfilled the action required by Technical Specifications LCO 3.5.1 condition B to verify by administrative means that the Reactor Core Isolation Cooling (RCIC) system is operable and took action to restore the HPCS system to operable status within 14 days. No other systems were required to function in response to this event. The licensee notified the NRC Resident Inspector.
ENS 41405	12 February 2005 01:59:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge	Rps Actuation	The following text was obtained from the licensee via facsimile: At approximately 1959 hours Central Standard Time, Grand Gulf Nuclear Station experienced a loss of Electrical Bus 11R. This caused a loss of additional electrical buses, and a subsequent reactor scram on low reactor water (level). The feedwater system was lost, and reactor low level 2 was reached. The Reactor Core Isolation Cooling System and High Pressure Core Spray System injected into the reactor and restored reactor water level. A primary containment, secondary containment, and drywell isolation occurred as expected. The Division 1 Diesel started and picked up the Division 1 bus. The Division 3 Diesel Generator started on the reactor low water level 2. The condenser is removing decay heat. The plant status currently is stable, with normal reactor water level and feedwater restored. All control rods inserted. The cause for the loss of Bus 11R is under investigation. Safety systems appeared to function as designed. The licensee notified the NRC Resident Inspector.
ENS 41310	6 January 2005 06:12:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation	Manual Reactor Scram Due to Reactor Recirculation Pump Trip	At approximately 0106 on 1-6-05, Reactor Recirculation Pumps A and B down-shifted from fast to slow speed which resulted in reactor power decreasing from 100% to approximately 46%. As operators started to reduce power using control rod insertion, Reactor Recirculation Pump A tripped to 'off.' At 0112 on 1-6-05, a manual reactor scram was inserted due to operating under undesirable power to flow conditions. At approximately 0119, the operators were unable to start the Motor Feedwater Pump, Reactor Core Isolation Cooling system was manually started. Level control was established using a Reactor Feed Pump Turbine and Reactor Core Isolation Cooling. The Main Steam Isolation Valves were closed to limit cooldown. Reactor level is being controlled with the Reactor Core Isolation Cooling System and safety relief valves are available for reactor pressure control. The cause of the Reactor Recirculation Pumps down-shifting and the subsequent trip of Reactor Recirculation Pump A is still under investigation. The cause of the Motor Feedwater Pump failure to start is likewise under investigation. All control rods fully inserted. The lowest reactor level reached was 154 inches above TAF. The electrical grid is stable and ESF systems remain available. Reactor pressure and level are being maintained by the Reactor Core Isolation Cooling system. The licensee notified the NRC Resident Inspector.
ENS 41252	10 December 2004 19:17:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation	Reactor Scram Due to Loss of Vital Instrument Bus	At 1317 (hrs CST) on December 10, 2004, an automatic actuation of the reactor protection system (RPS) occurred resulting in a reactor scram. The apparent cause of the event was loss of a vital instrument bus due to a fault in a nonsafety related vital inverter. This inverter provides power to selected control room instrumentation and controls. This resulted in the loss of feed water level control. Reactor level is being maintained by the High Pressure Core Spray System. The feed water system is not available. Reactor pressure is being controlled through the main turbine steam bypass system to the condenser. The condenser is available and being used as the heat sink. The residual heat removal system was operated in suppression pool cooling mode to provide a means of rejecting water from the suppression pool (water input from High Pressure Core Spray System minimum flow line). The plant is currently stable, and being maintained in hot shutdown. Systems responded as expected based on the initiating event. Reactor Core Isolation Cooling is not being used pending evaluation of a system alarm that is currently being investigated. Investigation of the initiating fault is being pursued in order to recover the vital bus and feed water level control. It has been preliminarily determined that the loss of instrument power resulted in the Main Feedwater regulating valve failing as-is and the "B" Reactor Recirculation Pump shifting down in speed. The reduction in reactor power with constant feed flow resulted in a high reactor vessel water level, producing a direct reactor scram signal at the High Level 8 setpoint. The licensee has notified the NRC Resident Inspector. * * UPDATE FROM G. HUSTON TO M. RIPLEY AT 2025 EST 12/10/04 * * * At 1657 CST (on 12/10/04), reactor level control was restored to the normal Feedwater and Condensate Systems. The High Pressure Core Spray System was restored to the normal standby lineup. Investigation into the cause of the reported RPS actuation continues. Investigation into the Reactor Core Isolation Cooling System alarms has resulted in declaring this system inoperable. The licensee will notify the NRC Resident Inspector. Notified R4 DO (L. Smith), NRR EO (M. Tschiltz) and IRD Manager (S. Frant) * * UPDATE TO W GOTT AT 0016 EST ON 12/12/04 * * * The final determination of the cause of the scram was determined to be due to the B recirc pump downshift and subsequent power to flow scram on APRM flux. The licensee will notify the NRC Resident Inspector. Notified R4DO (L Smith) * * UPDATE TO JOHN MACKINNON FROM HUSTON AT 1332 EST ON 12/16/O4 * * * The Reactor Core Cooling System was returned to available status at 0343 on 12/11/2004 and was restored to operable status at 2200 on 12/11/2004." The licensee notified the NRC Resident Inspector. Notified R4DO (Kriss Kennedy).
ENS 41216	23 November 2004 01:30:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Inadvertent Isolation of the Reactor Core Isolation Cooling System	This ENS notification is made to report that on November 22, 2004 at 17:30 PST the Reactor Core Isolation Cooling (RCIC) system was rendered inoperable when its inboard steam supply containment isolation valve inadvertently closed during the performance of a routine surveillance procedure. The surveillance procedure was stopped and plant operators entered the appropriate Technical Specification Action Statements. The RCIC system was restored to its normal standby lineup and declared operable two hours and three minutes after the isolation. NRC guidance in NUREG 1022 (Rev. 2), 'Event Reporting Guidelines,' and NRC Regulatory Issue Summary (RIS) 2001-14, 'Position on Reportability Requirements for Reactor Core Isolation Cooling System Failure,' indicates that RCIC failures are not reportable unless the RCIC system is specifically credited in the plant's Final Safety Analysis Report for mitigating the consequences of a Control Rod Drop Accident (CRDA). Columbia Generating Station has determined that the current licensing basis and docketed correspondence is not clear regarding RCIC credit for CRDA mitigation. Proposed FSAR changes were recently submitted by Energy Northwest to the NRC that would clarify that RCIC is not credited for CRDA mitigation. However, the NRC staff has not yet approved these proposed changes. Therefore, Columbia Generating Station has decided to conservatively report this event under 10 CFR 50.72(b)(3)(v)(D). A follow-up LER will be issued under 10 CFR 50.73(a)(2)(v)(D). The licensed has notified the NRC Resident Inspector.
ENS 41142	8 October 2004 22:31:00	10 CFR 21.21	Part 21 Report: Auxiliary Relays Failure	In accordance with 10CFR21.21(d)(3), initial notification of a reportable defect is being made by James A. Fitzpatrick (JAF). The failure of two General Electric (GE) IRMA auxiliary relays in a short period of time were identified in the corrective action system as a potential common mode failure. Initial troubleshooting revealed that both relay coils indicated open. There was no evidence of any obvious cause for the coils to open circuit (e.g. discoloration, smell, physical damage). Both relays are normally de-energized relays located in a mild environment in the relay room (controlled humidity, no vibration at the panels, no local heat source that could cause accelerated aging). Both relays were installed in 1988 along with 21 other relays. A total of 33 relays were purchased from GE with the same lot/date code. An extent of condition review was conducted. By checking the continuity of related relay coils, two other coil failures were detected. A failure analysis of the relays was performed. The failure mode was determined to be an open in the coil due to corrosion of the coil wire. This open in the coil will prevent the relay from changing state as the relay is energized. An independent laboratory concluded that the coil insulation was damaged and that the under lying wire was damaged during coil manufacture. The damage allowed the copper wire to corrode over the years to the point of failure. These HMA relays were installed in multiple Emergency Core Cooling Systems (ECCS) and other systems. Each component was evaluated to determine the specific impact on the respective system. The systems affected included: Residual Heat Removal (RHR, the Low Pressure Coolant Injection (LPCI) mode of operation), Emergency Diesel Generators (EDGs), Automatic Depressurization System (ADS), Reactor Core Isolation Cooling (RCIC), Core Spray (CS), and High Pressure Coolant Injection (LPCI). JAFs evaluation concluded that a substantial safety hazard existed in that there was a potential for a major deficiency/major degradation of essential safety-related equipment, specifically for the RHR (LPCI mode of operation) and HPCI systems. No other safety functions would have been lost for the other identified systems. Component and Supplier: GE HMA Type auxiliary relays GE Part No. 12HMA124A2 GE Dwg No. DA137C6164P001 Date Code 14VC; 8836 Serial #s: D88542-0001D R02 through D88542-0033D R02 All were purchased as safety-related from GE under JAF PO # 88-5628 All installed safety-related relays from this lot were replaced during the recent refueling outage. The licensee notified the NRC Resident Inspector.
ENS 41110	11 October 2004 01:53:00	10 CFR 50.72(b)(3)(iv)(A), System Actuation	a Rps Actuation Signal Occurred Due to Low Reactor Water Level While in Mode 3	At 2153 (hrs. EDT) on October 10, 2004, the Hope Creek Generating Station experienced an automatic reactor scram signal on low reactor level +12.5 inches (Level 3) while cooling down following a manual scram. As previously reported under Event Notification 41109, the Main Steam Isolation Valves (MSIV's) were closed as the result of a steam leak in the Turbine Building. The +12.5 inch (Level 3) scram occurred from the manual closure of a Safety Relief Valve (SRV) while it was being manually operated to reduce reactor pressure. The SRV was closed when reactor level was +24 inches, resulting in a reactor level shrink. Reactor level lowered to +8 inches, and stabilized. The secondary condensate pumps immediately restored reactor level to its normal band following the scram signal. SRV's were being utilized to assist the plant cool down because the High Pressure Coolant Injection (HPCI) system had been manually taken out of service. The HPCI vacuum tank vacuum pump tripped on an overload/power failure condition, and use was not desired. The Reactor Core Isolation Cooling (RCIC) system was out of service because of a high reactor level condition, due to plant cool down. Also, the Reactor Water Cleanup (RWCU) system was out of service due to the initial manual scram that occurred at 1814 hours which prevented normal reactor level blow down. The NRC Resident Inspector was notified and Lower Alloway Creek Township will be notified. HOO note: See Event # 41109
ENS 41109	10 October 2004 22:14:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge	Manual Reactor Scram Due to a Steam Leak in the Turbine Building	At 1814 (hrs. EDT) on October 10, 2004, Hope Creek Generating Station was manually scrammed due to a steam leak in the Turbine Building. All Control Rods inserted fully. Subsequent to the manual actuation of the Reactor Protection System, reactor pressure was reduced to minimize the effects of the steam leak. Degrading Main Condenser Vacuum following the scram resulted in trips of all operating Reactor Feed Pump Turbines at 10 (inches) HgA. The High Pressure Coolant Injection (HPCI) and Reactor Core Isolation Cooling (RCIC) Systems were manually initiated for reactor level control and the Main Steam Isolation Valves (MSIV's) were closed to isolate the leak - MSIV closure was completed prior to reaching the Main Condenser Vacuum isolation setpoint of 21.5 (inches) HgA. During plant stabilization, Reactor Water Level lowered below the RPS actuation setpoint of 12.5 inches four separate times. First, following the initial scram. Second, immediately following initiation of the HPCI and RCIC systems, when the 'A' and 'B' Reactor Water Level channels lowered to -38 inches (Level 2). Level 2 is the HPCI and RCIC actuation setpoint and Primary Containment Isolation actuation setpoint for Groups 2, 7, 8, 9, 12, 13, 14, 17, 18, 19, and 20 valves. Because only two of the four Level 2 instrument channels actuated, the isolation of these systems was channel dependent and occurred as required by the respective isolation logic. Third, following manual closure of the MSIVs. Finally, Reactor Water Level lowered below 12.5 inches following reset of the original manual scram signal which resulted in an automatic scram signal. RCIC was re-initiated manually to restore Reactor Water Level. No personnel were injured during this event. The plant is currently stable in OPCON 3 with reactor pressure at 615 psig. Pressure control (decay heat removal) was transitioned to HPCI in pressure control mode during plant stabilization. Reactor Water Level is being maintained with the Secondary Condensate Pumps. Two loops of RHR in Suppression Pool Cooling mode are in service with Suppression Pool Temperature at 110 degrees F in compliance with Technical Specification 3.6.2.1 Action b.2. Actions to determine the cause of the steam leak and effect repairs are in progress. The licensee will inform Lower Alloway Creek Township and has informed the NRC resident inspector. * * UPDATE ON 10/11/04 @ 0049 HRS EDT BY BAUER TO GOULD * * * On steam leak investigation, a walk down of the turbine building condenser bay determined the source of the leak to be a failure of an 8 inch moisture separator dump line. The line break is located approximately one foot from the condenser shell penetration. An additional investigation into the root cause of the failure has commenced. The NRC Resident Inspector was notified and Lower Alloway Creek Township will be notified. The Reg 1 RDO (Richard Barkley) and EO (Chris Grimes) were informed. HOO Note: See Event # 41110
ENS 40964	17 August 2004 12:28:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation	Manual Reactor Scram Due to Trip of Reactor Feedwater Pump "a" on Low Suction Pressure.	With a reactor startup in progress at 0528 PDT, operators at Columbia Generating Station inserted a manual reactor scram when the operating Reactor Feed Water (RFW) pump RFW-P-1A tripped. Reactor power was approximately 20% at the time of RFW pump trip. The cause of the RFW pump trip was due to low suction pressure; the cause of the low suction pressure is currently under investigation. The Reactor Core Isolation Cooling (RCIC) system (was manually started and) was used to maintain reactor vessel water level until reactor pressure was reduced to within the capacity of the condensate booster pumps (500 to 600 psi). The RCIC system has been returned to a standby lineup. The reactor is in Mode 3 (Hot Shutdown) with both reactor recirculation pumps running at minimum speed (15 Hertz). Decay heat is being rejected to the main condenser via auxiliary steam loads. All ECCS systems are operable. All emergency diesel generators are operable. No Safety Relief valves lifted during the scram. The NRC Resident Inspector was notified of this event by the licensee. See similar event number 40959 that occurred on 08/15/04.
ENS 40959	15 August 2004 20:03:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation	Manual Reactor Scram Due to Reactor Feedwater Pump Trip	With a reactor startup in progress at 1303 PDT, operators at Columbia Generating Station inserted a manual reactor scram when the running Reactor Feedwater (RFW-P-1A) pump tripped. Reactor power was approximately 18% at the time of RFW-P-1A trip. The cause of the RFW-P-1A trip was a high RFW Turbine Drain Tank (MD-TK-1) level; the cause of the MD-TK-1 high level is under investigation. The Reactor Core Isolation Cooling (RCIC) was used (manually started) to maintain reactor vessel water level until reactor pressure was reduced to within the capacity of the condensate booster pumps; the RCIC system has been returned to a standby lineup. The reactor is in mode 3 with both reactor recirculation pumps running at minimum speed (15 Hertz). Decay heat is being rejected to the main condenser via auxiliary steam loads. One control rod that indicated full-in immediately after the scram lost full-in indication eleven seconds after the scram. This control rod indicated full-in again 84 seconds after the scram. This ENS notification is made pursuant to 10 CFR 50.72(b)(2)(iv)(B). The licensee has notified the NRC Resident Inspector.
ENS 40909	30 July 2004 13:45:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Reactor Core Isolation Cooling (Rcic) Turbine Failed to Achieve Design Pressure and Flow During Surveillance Testing	The following information was obtained from the licensee via facsimile: During a surveillance of the Reactor Core Isolation Cooling system (RCIC), the RCIC turbine failed to achieve design pressure and flow. Other safety systems, including the High Pressure Coolant Injection (HPCI) system, are available. This failure is believed to be due to a RCIC flow controller problem. Investigation is continuing. Design pressure/flow is 1250 psig/400 gpm. Actual pressure/flow was 1220 psig/350 gpm. The licensee has notified the NRC Resident Inspector.
ENS 40833	22 June 2004 13:00:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Presure Coolant Injection System Inoperable Due to Maintenance	On June 21, 2004, at approximately 0830 hours, testing of High Pressure Coolant Injection (HPCI) system instrumentation commenced per Maintenance Surveillance Test 2MST-HPC128R, 'HPCI Reactor Water Level Channel Calibration And Functional Test.' At 0900 hours, it was determined that the instrumentation would require corrective maintenance and Technical Specifications (TS) Limiting Condition for Operation (LCO) 3.3.5.1, 'Emergency Core Cooling System (ECCS) Instrumentation,' Condition C was entered for HPCI system Reactor Vessel Water Level - High instrument channel 2-B21-LTN017B-2. Required Action C.2 of TS LCO 3.3.5.1 provides 24 hours for the channel to be returned to operable status. On June 22, 2004, at 0900 hours, the instrument channel was not returned to operable status due to continuing maintenance activities to calibrate the channel. Therefore, Condition G of TS LCO 3.3.5.1 (Required Action and associated Completion Time of Condition C not met) was entered and the High Pressure Coolant Injection (HPCI) system was declared inoperable in accordance with TS LCO 3.3.5.1 Required Action G.1. TS LCO 3.5.1. "ECCS - Operating," Condition D was entered for the HPCI system being declared inoperable. The Reactor Core Isolation Cooling (RCIC) system was verified operable per Required Action D.1. Required Action D.2 of TS LCO 3.5.1 requires the HPCI system to be returned to operable status within 14 days. The (NRC) Resident Inspector has been notified. The initial safety significance of this condition is considered to be minimal. The HPCI System is still available during maintenance activities. The RCIC system, as well as all other required ECCSs, are operable at this time. Maintenance activities and post maintenance testing were completed at 14:55 on June 22, 2004 allowing the HPCI System to be restored to an operable status.
ENS 40824	17 June 2004 09:21:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Coolant Injection (Hpci) Declared Inoperable	While changing out a light bulb in the Unit 1 HPCI room, the surveillance operator noticed that the bolts for the HPCI pump discharge check valve, 1E41-F005, bonnet on pressure seal were loose. All six bolts could be turned by hand. HPCI was declared inoperable until an investigation is performed. The bolts were properly torqued and HPCI pump run is complete and sat. Licensee entered Technical Specification 3.5.1 (14 day Limiting Condition of Operation). All other Emergency Core Cooling Systems are fully operable including the Reactor Core Isolation Cooling System. The NRC Resident Inspector was notified of this event by the licensee. * * RETRACTION FROM DISMUKE TO CROUCH AT 1700 EDT ON 10/28/04 * * * The following information was obtained from the licensee via facsimile: A subsequent investigation revealed that a hot torque of the Unit 1 HPCI pump discharge check valve (1E41-F005) was performed during the 165 psig pump operability surveillance test which was performed following reassembly during the Unit 1 refueling outage. During this surveillance, the pump discharge pressure and thus internal pressure on the pressure seal cover, is maintained between 265 and 305 psig. However, during the rated pressure run, the pump discharge pressure achieved is required to be greater than or equal to 1135 psig. This difference in internal pressure (1135-305 = 830 psig minimum), acting on the bottom of the pressure seal cover, forced the pressure seal cover to move upward toward the cover retainer, compressing the pressure seal more tightly. As the pressure seal cover moved toward the cover retainer, the retainer bolts also moved upward, but the cover retainer remained stationary, due to gravity. Therefore, the retainer bolts were no longer torqued against the retainer cover, creating the 'as found' condition. It is site and vendor (Flowserve) experience that once the pressure seal cover is wedged upward, sufficient friction exists between the pressure seal cover, the pressure seal, and the valve body to prevent the pressure seal cover from relaxing the sealing force on the pressure seal once the valve internal (system) pressure is removed. Furthermore, no gap existed between the head of any of the retainer bolts and the retainer cover. The sealing function of the pressure seal was never lost, and the valve would have performed its design function while the retainer bolts were in the 'as found' 'finger tight' condition. Therefore, the valve remained operable at all times when the HPCI system was required to be operable following the Unit 1 refueling outage. This was further substantiated by the fact that no leakage was observed during the rated pressure pump operability run on 3/14/04. Following discovery of the 'finger tight' condition, the retainer bolts were cold torqued to the appropriate value (370 ft-lbs) by Maintenance personnel on 6/17/04. A HPCI pump surveillance was then performed and a hot torque of 370 ft-lbs was performed immediately after the system was shutdown. Tampering was considered as a possible cause for the loosened bolts, but no evidence could be found to support these bolts being loosened intentionally. All evidence available suggests that the bolts were loosened by internal pressure, which is consistent with vendor experience. Based on the above information this event is not reportable, and this notification serves to withdraw the previous notification made on 6/17/2004. The licensee has notified the NRC Resident Inspector. The Headquarters Operations Officer notified R2DO (Bonser).
ENS 40785	30 May 2004 18:37:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Core Spray System Inoperable	The High Pressure Core Spray (HPCS) system was declared inoperable due to the pump's failure to meet the flow requirement specified in TS Surveillance Requirement 3.5.1.4. This surveillance is normally performed on a quarterly basis in accordance with the plant's In-service Testing (IST) Program. The flow values measured during the performance of this surveillance were below both the normal and alert ranges. This test had also been run on 5/27/04 with results in the alert range; HPCS system instruments had been vented between the two tests to rule out the possibility that the results were due to measurement errors. Upon declaring the HPCS pump inoperable, TS 3.5.1 Action B was entered. In accordance with Action B, the Reactor Core Isolation Cooling (RCIC) system was verified to be operable. With the RCIC system verified operable, Action B provides a 14-day completion time to restore HPCS to an operable status. All other Emergency Core Cooling Systems (ECCS) were operable during this event. This event is being reported as an event or condition that could have prevented the fulfillment of a safety function credited for mitigating the consequences of an accident. The HPCS system is a single train system at Columbia. The licensee notified the NRC Resident Inspector. * * UPDATE ON 06/14/04 @1752 BY MIKE BRANDON TO C. GOULD * * * RETRACTION On May 30, 2004, Energy Northwest provided an 8-hour notification pursuant to 10 CFR50.72(b)(3)(v)(D). This notification reported the apparent failure of the High Pressure Core Spray (HPCS) system's pump to meet the flow requirements of Surveillance Requirement (SR) 3.5.1.4. Upon the apparent failure to satisfy this SR, Energy Northwest entered Action B of Technical Specification (TS) 3.5.1 (14 day completion time) and initiated actions to investigate the cause of this apparent failure. This investigation determined the cause of this apparent failure was due to an anomaly in the processing of the pressure and flow input signals and the instrumentation used for documenting the results of the surveillance. Additional testing using alternative instrumentation determined the HPCS pump was fully capable of providing flow within the existing acceptance criteria of the plant's In-service Testing (IST) Program and thus capable of satisfying the SR. This investigation determined that no actual degradation of the pump existed that would have caused a valid failure of the SR. This was an instrumentation issue only. The HPCS system would have been capable of performing its specified safety function in the as-found condition and was capable of fully satisfying the SR. Therefore, this condition would not have prevented the fulfillment of a safety function and is therefore not reportable under 10CFR50.72. The HPCS system was declared OPERABLE on June 03, 2004 at 22:59 PDT. The NRC Resident Inspector was notified.
ENS 40636	3 April 2004 08:00:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Coolant Injection System Inoperable	During plant startup from the Brunswick Unit 1 Refueling Outage, the High Pressure Coolant Injection (HPCI) System was declared inoperable due to pump data not meeting the acceptable value of OPT-09.2, HPCI System Operability Test. With pump flow established at the reference value of 4550 gallons per minute, the actual turbine speed was 2530 rpm, outside the acceptable range of 2485-2515 rpm. Initial Safety Significance Evaluation: Minimal since the Automatic Depressurization System (ADS), the Low Pressure Coolant Injection System (LPCI), and the Core Spray System are Operable. In addition the Reactor Core Isolation Cooling System (RCIC) is Operable. Corrective Actions: Engineering to evaluate the test results and determine corrective actions. The licensee will notify the NRC Resident Inspector. * * RETRACTION TAKEN ON 5/6/04 @ 1534 EDT BY CROUCH FROM ELBERFELD * * * The following information was obtained from the licensee via facsimile: The purpose of this call is to retract the notification (Event Number 40636) made by the Brunswick Steam Electric Plant, Unit No, 1, Docket No. 50-325 / License No. DPR-71, on April 3, 2004, at 0549 hours. On April 2, 2004, at 2324 hours, the High Pressure Coolant Injection (HPCI) system was declared inoperable for scheduled testing performed in accordance with 0PT-09.2, 'HPCI System Operability Test.' 0PT-09.2 includes, in part, Technical Specification (TS) Surveillance Requirement (SR) 3.5.1.7, to verify that, with reactor pressure < 1045 and > 945 psig, the HPCI pump unit could develop a flow rate > 4250 gpm against a system head corresponding to reactor pressure. The testing also includes in part, In-service Test (IST) program requirements for HPCI pump performance (to test for pump degradation). During this testing, water is circulated from the Condensate Storage Tank (CST) through the HPCI pump and back to the CST through a 'Bypass to CST' valve. Motive force for the pump is provided by reactor steam being routed through the HPCI turbine into the suppression pool. Due to the heat energy being deposited in the suppression pool, time for HPCI turbine/pump testing is limited. When tested, the HPCI pump passed the TS SR 3.5.1.7 pump pressure and flow rate test requirements. However, when HPCI turbine speed was set to the IST-required value of 2,500 rpm, as indicated by the control room indicator 1-E41-C002-4 (the preferred indication), the IST required system flow of 4,550 gpm could not be attained. Turbine speed was then adjusted, using a portable speed indicator, to attain 4,550 gpm system flow. The portable speed indicator read 2530 rpm, high, outside the acceptable range of 2,485 to 2,515 rpm. The unsatisfactory test indicated potential pump degradation. The IST program requires the equipment to be declared inoperable until unsatisfactory test results are evaluated. On April 3, 2004, at 0436 hours, the HPCI system was declared inoperable due to the unsatisfactory test. At 0549 hours, the NRC was notified (Event Number 40636) in accordance with 10 CFR 50.72(b)(3)(v)(D) as a condition that at the time of discovery could have prevented the fulfillment of the safety function of a system needed to mitigate the consequences of an accident. During the testing with the portable speed indicator, it was noted that the control room indicator 1-E41-C002-4 was reading high (i.e., 1-E41-C002-4 was reading 2,600 rpm compared to 2,500 rpm on the portable speed indicator). Turbine speed indicator 1-E41-C002-4 was adjusted back to within required accuracy in accordance with Work Order 306977. After the initial test, a thorough review of pump data, instrument calibration data, and IST program guidance was conducted. It was determined that there was no indication of pump degradation and no indication of a flow indicator problem. Having corrected a speed indicator problem, sections of 0PT-09.2 were performed on April 5, 2004, to test for pump degradation using the preferred speed indicator 1-E41-C002-4. Test results were satisfactory and demonstrated that the pump performance met the IST program requirements. The HPCI system was declared operable on April 5, 2004, at approximately 0521 hours. Investigation of this condition is documented in the corrective action program in Action Request (AR) 123551. NUREG-1022, Rev. 2, Section 3.2.7 (page 56) lists types of events or conditions that are generally not reportable under 10 CFR 50.72(b)(3)(v) and 10 CFR 50.73 (a)(2)(v) criteria. The list of not-reportable conditions includes: - Removal of a system or part of a system from service as part of a planned evolution for maintenance or surveillance testing when done in accordance with an approved procedure and the plant's TS (unless a condition is discovered that could have prevented the system from performing its function) On April 2, 2004, the HPCI system was removed from service for testing in accordance with an approved procedure 0PT-09.2. The system was declared inoperable due to the test results discussed above, and since the HPCI system is a single train safety system, an ENS notification was made. However, no condition was discovered that could have prevented the HPCI system from performing its functions. Carolina Power & Light Company, doing business as Progress Energy Carolinas, Inc., has determined that this event does not meet the 10 CFR 50.72 or 10 CFR 50.73 reporting criteria and the notification for Event Number 40636 is retracted. The resident inspector has been notified.
ENS 40536	21 February 2004 16:41:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Rcic System Inoperable Due to Possible Undervoltage Relay Failure	This ENS notification is made to report that on February 21, 2004 at 0841 PST Reactor Core Isolation Cooling was rendered inoperable due to RCIC-V-13 (RPV injection valve) motor operator losing power. Preliminary investigation indicates the undervoltage relay may have failed, resulting in a loss of control power for the valve and loss of valve position indication. The event is considered reportable to the NRC under 10 CFR 50.72(b)(3)(v)(D) based on guidance contained in NUREG 1022, "Event Reporting Guidelines," and NRC Regulatory Issue Summary (RIS) 2001-14, 'Position on Reportability Requirements for Reactor Core Isolation Cooling System Failure.' A follow-up LER will be issued under 10 CFR 50.73(a)(2)(v)(D). This event placed the plant in technical specifications LCO 3.5.3 which has a 14 day duration. The licensee notified the NRC Resident Inspector.
ENS 40318	13 November 2003 03:22:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Coolant Injection System Isolation During Testing	During quarterly surveillance testing of the High Pressure Coolant Injection (HPCI) System the HPCI system isolated. The cause of the isolation is believed to be high turbine exhaust diaphragm pressure. HPCI is currently inoperable. The outboard steam line isolation valve closed automatically and the inboard steam line isolation valve was manually closed. The HPCI room carbon dioxide fire protection system actuated due to the high temperature spike. No fire was present. The Reactor Core Isolation Cooling (RCIC) System, Auto Depressurization System (ADS), Low Pressure Core Spray System and Low Pressure Coolant Injection System are operable. Initial Safety Evaluation - Low initial safety significance due to availability of alternate high and low pressure injection systems. Corrective Actions - HPCI will remain inoperable pending investigation. Determine and correct the cause of HPCI isolation. Determine if the inboard steam isolation valve should have automatically closed. The licensee has notified the NRC Resident Inspector. * * * UPDATE ON 12/04/03 @ 0945 BY STEVE TABOR TO C GOULD * * * Upon further investigation of this event, it has been determined that the malfunction of the HPCI system was due to a condition which was introduced by the maintenance/testing activities while the system was declared inoperable. During the valve restoration/clearance cancellation process performed in support of HPCI system return to service, the 2-E41-F021, HPCI Exhaust Line Check Valve was inadvertently left in the locked closed position. In this configuration turbine exhaust over pressurization occurred resulting in actuation of the turbine exhaust diaphragm high pressure trip, subsequent generation of a Primary Containment Isolation system Division 1 Group 4 isolation signal, closure of the HPCI system outboard steam isolation valve 2-E41-F003, and rupture of the HPCI turbine exhaust rupture disc assembly. An evaluation of the impact of this event was performed and the necessary corrective actions and additional post-maintenance testing completed satisfactorily prior to declaring the HPCI system operable on November 16, 2003, at 2015 EST. After further review of the event and event reporting guidance, this event is not reportable in accordance with 10 CFR 50.72 or 50.73. NUREG-1022, Revision 2 provides clarification of the reporting requirements contained within 10 CFR 50.72 and 50.73. Specifically, in discussions associated with events that could prevent fulfillment of a safety function, NUREG-1022, Revision 2, Section 3.2.7, provides the following example of a condition that is not reportable under these criteria: removal of a system or part of a system from service as part of a planned evolution for maintenance or surveillance testing when done in accordance with an approved procedure and the plant's TS (unless a condition is discovered that could have prevented the system from performing its function) In this case, HPCI was properly removed from service for planned maintenance/testing under TS Limiting Condition for Operation, A2-03-1190, and was not returned to service until HPCI system operability was restored. The intent of the qualifying statement in NUREC-1022 (i.e., unless a condition is discovered that could have prevented the system from performing its function) is to ensure that pre-existing operability concerns that are discovered during maintenance activities are reported. It is not intended to require reporting of conditions, introduced by the maintenance/testing activity that are identified and corrected prior to returning the system to service. In this case, post-maintenance testing performed prior to declaring the HPCI system operable, identified a problem that had been introduced by activities implemented in support of the maintenance activity prior to returning the HPCI system to service and which did not exist at any time when the HPCI system had been relied upon to fulfill its intended safety function. Therefore the licensee is retracting this event. The licensee notified the Resident Inspector The Reg 2 RDO(Brian Bonser) was notified
ENS 40297	4 November 2003 22:32:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge	Brunswick Unit 2 Scram Due to Generator/Turbine Trip	On November 4, 2003, at approximately 1732 hours, Unit 2 received a generator/turbine trip due to loss of excitation, which resulted in a Reactor Protection System (RPS) trip. Plant response to the reactor shutdown resulted in High Pressure Coolant Injection and Reactor Core Isolation Cooling (RCIC) system actuations on low reactor coolant level. Additionally, primary containment isolation system actuation signals for valve groups 1, 2, 3 , 6, 8, and 10 were received and the valves closed as required. All four emergency diesel generators automatically started, but did not load because power was never lost to the emergency buses. The loss of power from the generator trip resulted in reactor building ventilation isolation and automatic start of both trains of the Standby Gas Treatment (SBGT) system. SBGT Train A immediately tripped, but was successfully placed in service. All control rods fully inserted into the core. At approximately 1857 hours, another RPS trip was received due to low reactor coolant level while cycling Safety Relief Valves; however, all control rods were already inserted. The safety significance of this event is considered to be minimal. The plant responded as designed to the transient with the exception of the SBGT Train A initial starting issue. An event investigation team has been assembled to determine the cause of the event. Plant response to the event is being evaluated and identified issues will be addressed prior to plant restart. The licensee reported that the station electrical grid is normal and the emergency diesel generators have been shutdown and returned to standby status. The current plant conditions are 550 psi, 496 degrees F with RCIC operating to maintain reactor water level. The main condenser is available and being used to dump steam from the reactor. Two safety relief valves opened during the transient and reclosed as expected. The reactor water level decreased to minimum of approximately 90 inches during the transient. The cause of main steam isolation valve (MSIV) closure is under investigation. The licensee also reported that this event caused a Group 6 Isolation, reactor building ventilation isolation, and standby gas treatment actuation signal on Brunswick Unit 1. These Unit 1 systems have been returned to a normal configuration. The licensee has notified the NRC Resident Inspector.
ENS 40229	7 October 2003 19:31:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Core Spray Declared Inoperable (Hpcs)	At 1231 hours on October 7, 2003, the High Pressure Core Spray (HPCS) system at Columbia Generating Station was declared inoperable due to a failure to maintain system pressure while the system was being operated with the keep-fill piping isolated for maintenance on the system waterleg pump. This action rendered the HPCS system unable to perform its safety function to mitigate the consequences of an accident. Upon discovery of the inoperable condition, the Reactor Core Isolation Cooling system was verified to be operable and HPCS was restored to operable status at 1538 in accordance with the Required Action of plant Technical Specifications Limiting Condition for Operability 3.5.1, Conditions B.1 and B.2. All other Emergency Core Cooling System (ECCS) were operable during the time the HPCS system was inoperable. This event is being reported pursuant to the guidance for reporting under 50.72(b)(3)(v)(D) contained in NUREG 1022, which states for single train systems that perform a safety function, loss of a single train would prevent the fulfillment of the safety function and therefore is reportable. The NRC Resident Inspector will be notified of this event by the licensee.
ENS 40196	24 September 2003 04:53:00	10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation 10 CFR 50.72(b)(3)(iv)(A), System Actuation 10 CFR 50.72(b)(2)(iv)(A), System Actuation - ECCS Discharge	Automatic Scram at Susquehanna on Low Water Level	At 0053 hours on September 24, 2003 with Susquehanna Unit 1 operating at 100% power an automatic reactor scram occurred due to low water level. At the time of the scram, reactor feed pump testing was in progress and the 'C' reactor feed pump tripped. The reactor recirc pumps runback initiated as expected when water level reached 30" with the feed pump tripped. Level continued to drop and reached the Level 3 auto scram setpoint. Level continued to drop and reached a low level of approximately -48" wide range. Reactor Core Isolation Cooling and High Pressure Coolant Injection auto started at their initiation setpoints and injected to the vessel to recover level. All level 2 and 3 containment isolations occurred as expected. The reactor recirc pumps tripped as expected when level 2 was reached. Reactor Pressure was controlled with bypass valves, there were no Safety Relief Valve lifts. There are no challenges to containment. Unit 1 is currently stable in Mode 3 with both reactor recirc pumps restarted. A human performance error was the cause of the reactor feed pump trip. Investigation is continuing into the plant response to the reactor feed pump trip. The NRC Resident Inspector was notified of this event.
ENS 40134	5 September 2003 13:33:00	10 CFR 50.72(b)(3)(v)(A), Loss of Safety Function - Shutdown the Reactor 10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	High Pressure Coolant Injection (Hpci) Declared Inoperable.	At 09:30 EDT, Unit 1 was performing the HPCI Quarterly Flow verification surveillance. Shortly after the initiation of the system an abnormally loud bang was heard. System flow of approximately 5200 gpm and discharge pressure of approximately 1300 psi was achieved at approximately 09:33. Approximately 4 seconds after reaching rated system flow HPCI discharge pressure increased to approximately 1675 psi and system flow dropped to approximately 2700 gpm. HPCI had been declared inoperable at 08:35 EDT to perform the surveillance and will remain inoperable until the cause of the loss of system flow is corrected. Because HPCI is a single train ECCS (Emergency Core Cooling System) safety system, this event results in the loss of an entire safety function which requires an 8 hour ENS notification in accordance with 10CFR50.72(b)(3)(v) and the guidance provided under NUREG-1022, rev. 2. There are no other ECCS systems presently out of service. Reactor Core Isolation Cooling (RCIC) is fully operable and HPCI entered Tech Spec 3.5.1 (14 day Limiting Condition of Operation). All other ECCS systems are fully operable. The NRC Resident Inspector was notified of this event by the licensee. * * RETRACTION FROM WALSH TO CROUCH ON 10/02/03 @ 1548 EDT* * * On 09/05/2003, PPL Susquehanna LLC made an ENS notification per 10CFR50.72(b)(3)(v) in response to an apparent loss of the HPCI (High Pressure Coolant Injection) safety function. In the event, results of HPCI Quarterly Flow Surveillance testing did not meet acceptance criteria established for the system. Investigation into the cause of the failed HPCI surveillance revealed a 360-degree weld crack on the HPCI Test Line to Condensate Storage Tank (CST) Valve, HV155F008. HV155F008 is not in the reactor vessel injection flowpath. The impact of this crack, which was located between the valve seat cage assembly and the valve body, was that the HPCI Test Line to CST valve was not capable of throttling over the full range of HPCI system flows. Valve performance became erratic at higher flows because the valve seat cage was lifted out of the valve body into the flow path, increasing system resistance, and preventing attainment of design flow in the HPCI test loop. While the ability to effectively test the HPCI system using the test return path to the CST was compromised, the HPCI injection flowpath to the reactor vessel was not adversely affected by the damaged valve. Accordingly, the HPCI system maintained full capability for providing sufficient coolant to the reactor vessel in the event of a small break loss-of-coolant accident. Because the HPCI safety function was not compromised by the identified test path obstruction, this ENS notification is being retracted. The Licensee has notified the NRC Resident Inspector. Notified R1DO (Cobey).
ENS 40098	22 August 2003 09:34:00	10 CFR 50.72(b)(3)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident	Reactor Core Isolation Cooling System Inoperable	This ENS notification is made to report that on August 22, 2003 at 02:34 PDT Reactor Core Isolation Cooling was isolated due to the discovery of a degraded pilot cell in the Division 1 250 VDC battery. Operators isolated the steam inlet valve to the RCIC turbine (RCIC-V-1) because the minimum flow bypass valve, RCIC-V-19, (a primary containment isolation valve) was declared inoperable and isolated to comply with the plant TS. Isolation of RCIC-V-1 effectively removed RCIC from service since it is the containment isolation valve. The event is considered reportable to the NRC under 10 CFR 50.72(b)(3)(v)(D) based on guidance contained in NUREG 1022, "Event Reporting Guidelines," and NRC Regulatory Issue Summary (RIS) 2001-14, "Position on Reportability Requirements for Reactor Core Isolation Cooling System Failure." A follow-up LER will be issued under 10 CFR 50.73(a)(2)(v)(D). The licensee will be notifying the NRC Resident Inspector.

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