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On December 9, 2017 at 1347 CDT the Main Control Room received annunciators that indicated a trip of a 4160V 1A1 Breaker, the 480V transformer 1A and Al feed breaker. The loss of Division 1 480V power caused the instrument air (IA) containment isolation valves to fail close as designed. The loss of IA affected various containment loads, including the scram pilot air header and containment isolation valves. Another consequence of this event was that secondary containment differential pressure became positive due to fuel building ventilation dampers failing closed by design due to the loss of power. Operations entered Emergency Operating Procedure (EOP) -08, Secondary Containment Control, and Technical Specification (TS) Limiting Condition for Operation (LCO), 3.6.4.1 Action A.1. Division 2 Standby Gas Treatment System was activated at 1350 and restored secondary containment differential pressure within allowable TS values at 1351. The TS LCO and EOP were exited when allowable TS values were restored. Due to the loss of IA, a manual reactor scram was inserted at 1353 when two control rods began drifting in as expected.

A phase to ground fault was identified on 480V transformer 1A (1AP11E). On December 14, the 480V transformer was replaced and the plant returned to Mode 1 operations on December 15. The condition described in this report was determined to be reportable under 10 CFR50.73(a)(2)(iv)(A), 10 CFR 50.73(a)(2)(v)(C) and 10 CFR 50.73 (a)(2)(ii)(B). The cause of the transformer failure is currently under investigation and will be provided in a supplemental report. This event is classified as an unplanned scram with complications due to the loss of the Division 1 480V power.

On June 2, 2017, plant personnel were performing welding activities on the 'B' Reactor Water Cleanup System (RT) pump while the plant was in operating Mode 4. The Operations Work Control Supervisor (WCS) had given maintenance personnel authorization to prop both 'B' RT pump room doors open so that welding cables could extend through both doors in support of maintenance activities. The doors are part of the plant secondary containment boundary. Authorization granted by the WCS was executed without utilizing the plant barrier impairment process (PBI) per plant procedures. Prior to the plant's transition to operating Mode 2, Operations personnel made a plant announcement requiring the establishment of primary and secondary containment. The plant then transitioned to operating Mode 2 at 0241. However, both RT Pump 'B' doors remained propped open during the plant mode change.

This condition was discovered by shift personnel at 0300 (CDT) and secondary containment was declared inoperable.

The loss of secondary containment was caused by personnel not following the FBI per plant procedure. Secondary containment was subsequently restored twenty four minutes after discovery of the open 'B' RT doors. Corrective actions taken and planned include implementing management action response checklist (MARC) principles for the responsible supervisor and completing a read and sign for planners and schedulers associated with the PBI process.

The condition reported by this Licensee Event Report (LER) was an expected condition as a result of p anned activities, with the exception of one activity, in support of a routine refueling outage. As described in the LER, the U. S. Nuclear Regulatory Commission (NRC) provided enforcement guidance, applicable to boiling water reactor licensees, that allows the reported condition. Although this allowance is provided by the NRC's enforcement guidance, the activities are still considered reportable in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by Technical Specifications (TS).

Between 3/6/2017 and 3/30/2017, Susquehanna Steam Electric Station (SSES) performed Operations with the Potential for Draining the Reactor Vessel (OPDRV) activities on Unit 2 while in Mode 5 without an operable secondary containment, as expected and allowed by the enforcement guidance. Although NRC Enforcement Guidance Memorandum (EGM) 11-003, Revision 3 allows the implementation of interim actions as an alternative to full compliance, this condition is still considered a condition prohibited by Secondary Containment TS 3.6.4.1. The OPDRV activities were planned activities that were completed under the guidance of plant procedures, with the exception of one unplanned activity. Since the planned actions were deliberate, no cause determination was necessary. The unplanned activity was caused by a human performance error related to procedural use and adherence and peer checking. Corrective action included coaching and remediation of the individual involved in the event.

There were no actual consequences to the health and safety of the public as a result of this event.

On November 5, 2016, at 0404, a Reactor Protection System (RPS) actuation occurred due to a valid scram discharge volume high water level signal. This actuation was the result of a Redundant Reactivity Control System (RRCS) Alternate Rod Insertion (ARI) signal that was inadvertently generated during testing. The reactor was in cold shutdown at the time of the RPS actuation, with all control rods inserted. The Reactor Coolant System (RCS) pressure was 830 psig to support excess flow check valve testing, and shutdown cooling was removed from service. When the RRCS/ARI actuated, the B reactor recirculation pump tripped as expected, and the scram air header depressurized as expected.

The depressurization of the scram air header is a design feature of the ARI. The ARI signal established the control rod drive (CRD) system scram flow path. This resulted in a high water level in the scram discharge volume (SDV), an expected response. High water level in the scram discharge volume is an actuation signal for the RPS.

This is a condition reportable under 10 CFR 50.73(a)(2)(iv)(A) as an event or condition that resulted in a manual or automatic actuation of a listed system. The cause of the RRCS/ARI actuation is inadequate procedural guidance which resulted in a personnel error associated with partial procedure performance.

On April 22, 2016, at 1358 Central Daylight Time (CDT), during transfer of the 4160 V (4kV) Shutdown Bus from Alternate to Normal, the Normal Feeder Breaker (BKR 1722) failed to close when the Alternate Feeder Breaker was manually tripped. 4kV SD Bus 2 de-energized, resulting in the loss of 1B and 2B Reactor Protection System (RPS) as well as Steam Jet Air Ejector 1B. Emergency Diesel Generators (EDG) C and D started, but did not tie to the 4kV Shutdown Boards due to Operations personnel immediately re-closing the Alternate breaker and re-energizing 4kV Shutdown Bus 2. Invalid actuations of several Containment Isolation Valves also occurred during this event due to the loss of RPS. At 1530 CDT, EDG C and D were shut down. BFN, Unit 1, was returned to normal operating conditions.

The cause of this event was loose wires in the closing control circuit for BKR 1722 due to work in the vicinity of the control circuit termination points. Corrective actions were to terminate loose wires, using a ring type lug instead of a forked spade type lug, in the closing control circuit for BKR 1722; and to verify Shutdown Bus 2 transferred successfully to BKR 1722. A briefing was provided to Electrical personnel who perform modifications to discuss the potential consequences of installing tie wraps and performing other activities that could adversely affect existing wiring.

The condition reported by this Licensee Event Report (LER) was an expected condition, which was the result of planned activities in support of a routine refueling outage. As described in the LER, the U. S. Nuclear Regulatory Commission (NRC) provided enforcement guidance, applicable to boiling water reactor licensees, that allows the reported condition. Although this allowance is provided by the NRC's enforcement guidance, the planned activities are still considered reportable in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by Technical Specifications (TS).

Between 3/16/2016 and 4/11/2016, Susquehanna Steam Electric Station (SSES) performed Operations with the Potential for Draining the Reactor Vessel (OPDRV) activities on Unit 1 while in Mode 5 without an operable secondary containment, as expected and allowed by the enforcement guidance. Although NRC Enforcement Guidance Memorandum (EGM) 11-003, Revision 3 allows the implementation of interim actions as an alternative to full compliance, this condition is still considered a condition prohibited by TS 3.6.4.1. The OPDRV activities were planned activities that were completed under the guidance of plant procedures and are considered to have low safety significance based on interim actions taken. Since these actions were deliberate, no cause determination was necessary. A license amendment request will be submitted following NRC approval of the Technical Specifications Task Force (TSTF) traveler associated with generic resolution of this issue.

building. The alarms occurred during an entry to the Unit 2 Reactor Water Cleanup (RWCU) pump room. A negative reactor building pressure was restored within two minutes (approximately 20:40 hours) without operator action.

Since both Units 1 and 2 share a common reactor building (RB), the loss of differential pressure impacted both Units 1 and 2 secondary containments.

The cause was a sheared air line inside the Unit 1 RB ventilation exhaust plenum which depressurized the air header supplying operating air to all three Unit 1 reactor building exhaust fan isolation dampers, causing the dampers to fail open, including the one on the standby fan.

Corrective actions included replacing the sheared air line, and the addition of a preventive maintenance task for replacement of equivalent air lines on all RB supply and exhaust fan dampers.

The safety significance of this event was minimal. Given the impact on the secondary containment, this report is submitted (for Units 1 and 2) in accordance with the requirements of 10CFR 50.73(a)(2)(v)(C), which requires the reporting of any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to control the release of radioactive material.

On November 24, 2015 at 0534 hours, the Monticello Nuclear Generating Plant was at 0% power in Mode 3 (Hot Shutdown) for a forced outage. While initially placing Shutdown Cooling (SDC) in service, the 12 Residual Heat Removal (RHR) pump tripped approximately 8-10 seconds after start due to the closure of the RHR SDC suction isolation valves. When placing SDC in service, flow rapidly increased after opening the RHR Division 2 Low Pressure Coolant Injection (LPCI) outboard injection valve causing a localized pressure transient in the reactor recirculation pump suction piping that resulted in an isolation of the SDC suction line. Reactor pressure vessel (RPV) pressure remained stable at approximately 30 psig.

Prior to attempting to place 'B' SDC in service, the Condensate system and the 'F' Safety Relieve Valve were in service providing decay heat removal. Immediate actions were taken to restore 'B' RHR SDC to operable status, thus an alternative method of decay heat removal was already established by the Condensate system and `F' Safety Relief Valve.

On August 3, 2015, an extent of condition review for LER 2015-003, "Use of the Reactor Water Cleanup (RWCU) System to Lower Level without Declaring an Operation with a Potential to Drain the Reactor Vessel (OPDRV) with Secondary Containment Inoperable," identified two prior occurrences where this had occurred. On May 26, 2013, during the 2013 Refueling Outage, the RWCU System was used to lower reactor cavity level with the Secondary Containment (SCT) inoperable. On February 4, 2014, during the 2014 recirculation pump seal forced outage, reactor water level was lowered in preparation for startup using the RWCU System while the SCT and the B Standby Gas Treatment subsystem were inoperable. Each occurrence constitutes an operation or condition prohibited by the Technical Specifications, during OPDRV, which are reportable in accordance with 10 CFR 50.73(a)(2)(i)(B).

The cause was determined to be that the plant procedure controlling OPDRVs failed to provide adequate guidance to determine an OPDRV activity which resulted in actions taken that were not in accordance with NRC Enforcement Guidance Memorandum (EGM) 11-003, Revision 2. The plant OPDRV procedure has been revised to reflect the guidance of the EGM.

On May 8, 2014, at 1645, the results of an industry operating experience (OE) extent of condition review identified that an un-fused control circuit associated with the Unit 1 Reactor Water Cleanup Isolation Valve 12 could short circuit due to a fire in the circuit cable routing. This short circuit could cause the cable to self- heat and cause secondary fires along the associated cable route. The unanalyzed secondary fires could adversely affect safe shutdown equipment and potentially cause the loss of ability to safely shutdown as required by 10 CFR 50 Appendix R. The original plant wiring design and configuration for the containment isolation valve did not include separate overcurrent protection for motive power and control wiring. The only protection for control circuit wiring is by motive circuit fuses which are not sized appropriately to protect the control wiring. As a compensatory measure, Operations has initiated a fire inspection each shift to monitor the associated Fire Areas (1 and 10) until separate fuses are installed within the control circuitry of the motor operated valve (MOV). A similar event was reported in LER 2013-002.

This condition was entered into the Nine Mile Point (NMP) corrective action program as Condition Report (CR) 2014-004630.

On February 16, 2014 at 1216, Nine Mile Point Unit 2 (NMP2) was operating at 100 percent power when an automatic actuation of the Division I and III Emergency Diesel Generators (EDG) occurred due to a loss of a 345 kV bus owned by National Grid. The bus outage resulted in the loss of off-site power source (Line 5) owned by Exelon. Automatic actuation of the EDGs is reportable under 10 CFR 50.72(b)(3)(iv)(A) and 10 CFR 50.73(a)(2)(iv)(A). The cause of the loss of Line 5 is due to a faulted current transformer associated with 345kV Breaker R210 owned by National Grid, the transmission owner. The faulted transformer caused a voltage transient for both station service and offsite power loads. This resulted in the loss of: 1) the service water radiation monitor and radwaste/reactor building vent gaseous effluent monitoring systems 2) the 'C' and 'D' Reactor Water Cleanup (WCS) filter strings, and 3) spent fuel pool cooling. The voltage transient also caused Feed Water level control valve actuator controls to lock up and go to manual operation. The causal analysis identified the failure mechanism of the CT as an insulation breakdown internal to the CT.

The corrective actions include purchasing spare CTs and performing follow up tests and repairs on damaged equipment. NMP1 LER 2008-001 and NMP2 LER 2012-004 are similar LERs submitted previously which involve the actuation of the EDGs due to a loss of Power Line 5.

On 12/8/13 at 2026 hours with the plant in Mode 1 at 97.3 percent reactor power, operators received multiple alarms due to the trip of 4160 volt 1A1 breaker which resulted in a loss of power to two Division 1 480 volt unit substations.

Operators were immediately dispatched and found a 4160/480 volt stepdown transformer failed. Many Division I components lost power. The loss of power caused an instrument air (IA) containment isolation. The loss of IA affected various containment loads, including the scram pilot air header, the main steam isolation valves and the reactor water cleanup system. At 2036 hours, the scram pilot air header low pressure alarm was received, and in response to an anticipated automatic reactor scram, operators immediately initiated a manual reactor scram. All control rods fully inserted into the core. Reactor pressure vessel water level dropped to the low reactor water level 3 setpoint (normal result of a scram from high power) and operators entered the Reactor Pressure Vessel Control Emergency Operating Procedure. The most probable cause of the transformer failure was a tum to turn failure of the high side windings due to insulation breakdown over time, prior to its expected end of life. An installed spare was connected to replace the failed Division 1 transformer.

On Monday October 14, 2013 at 2121 hours (EDT), with the reactor critical at 100% core thermal power, the mode switch in RUN, and offsite power 345KV Line 342 out of service for a scheduled upgrade, a loss of offsite power (LOOP) occurred due to the loss of the second 345KV Line 355. All control rods fully inserted, main steam isolation valves closed on the loss of power to the reactor protection system, and the emergency diesel generators automatically started supplying power to both 4160V safety buses. Following the scram, 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 per design. A plant cool down commenced with reactor water level being maintained in the normal post-scram band of +12 inches to +45 inches utilizing the High Pressure Coolant Injection (HPCI) and Reactor Core Isolation Cooling (RCIC) systems.

The cause of Line 355 loss was due to a failure of an offsite substation tower support. The offsite tower was repaired and Line 355 was energized at 2023 hours on October 15, 2013.

These events posed no threat to public health and safety.

On Thursday, August 22, 2013 at 0755 (EDT) with the reactor critical at 98% core thermal power (CTP), and the mode switch in RUN, the Pilgrim Nuclear Power Station (PNPS) was manually scrammed due to lowering reactor water level resulting from a trip of the reactor feed pumps. The reactor feed pumps tripped due to a loss of power to the pump seal cooling water flow switch relays and resultant automatic actuation of the feed pump trip circuit.

The direct cause of the reactor feed pump trip was an automatic actuation of the feed pump trip circuitry. The feed pump trip circuits actuated as designed in response to a loss of power to the pump seal cooling water flow switch relays. The seal cooling water flow switch relays lost power as a result of a 120V AC breaker trip resulting from a short-to-ground fault in the associated circuits fed by the breaker. Corrective action was taken to repair the ground fault in the associated circuits fed by the 120V AC breaker and to revise reactor feed pump trip circuit design to remove the loss of seal water trip function.

This event posed no threat to public health and safety.

On Friday February 8, 2013, at 2117 hours with the reactor initially at 85% core thermal power, Pilgrim Nuclear Power Station (PNPS) experienced a loss of off-site power (LOOP) resulting in a load reject and a reactor scram. All rods fully inserted and the Emergency Diesel Generators automatically started and powered safety-related buses A5 and A6. All other safety systems functioned as required.

The plant stabilized in Hot Shutdown. At the time of the event a significant winter storm (Nemo) was buffeting Southern New England. At 2200 hours PNPS in conjunction with the local grid operator determined off-site power sources were not reliable and efforts to restore off-site power were temporarily suspended. At 2200 hours, PNPS declared a Notification of Unusual Event. On February 10, at 1055 hours, one of two off-site power supplies was restored, all safety buses were powered from the startup transformer and the Unusual Event was exited. Later on February 10, at 1402 hours with the plant in Cold Shutdown, ice bridging on a startup transformer insulator caused its 345 KV supply breaker to open resulting in a second LOOP. Again the EDG's started and powered safety-related buses. All other safety systems functioned as required. Shutdown cooling was restored at 1426 hours.

On February 10, at 2020 hours, this occurrence was reported to the USNRC as documented in EN# 48739.

The severe winter storm which caused extensive generalized geographical damage to the electrical distribution network was root cause of the LOOP events.

These events posed no threat to public health and safety.

On Thursday, January 10, 2013 at 1534 hour (EST), with the reactor at 100% core thermal power, both reactor recirculation pumps unexpectedly tripped and a manual reactor scram was inserted as required by station procedures. Following the reactor scram, all rods were verified to be fully inserted and the Primary Containment Isolation System Group II (Reactor Building) and Group VI (Reactor Water Cleanup System) actuations occurred as designed due to the expected reactor water level shrink associated with the scram signal. All other plant systems responded as designed. The scram was uncomplicated and decay heat was released to the main condenser via the turbine by-pass valves.

The cause of the two reactor recirculation pumps tripping was due to the inadvertent seal-in of a relay (pump trip interlock) in the Low Pressure Coolant Injection (LPCI) Loop Select Logic circuitry within the Residual Heat Removal (RHR) System during surveillance testing. When the logic was reset at completion of testing, a normally open relay contact (which was inadvertently closed) interlocked with the recirculation pumps circuit, sent a trip signal to their drive motor breakers.

Corrective action has been taken to revise the subject surveillance procedure with steps to reinstall relay covers and added a verifier to observe relay status/ state prior to resetting the relay logic circuit.

This event had no impact on the health and/or safety of the public.

On Tuesday, May 22, 2012 at 1311 hours, with the reactor at approximately 35% core thermal power, during a planned power reduction to support thermal backwash of the main condenser, a manual reactor scram was inserted due to degrading main condenser vacuum. The direct cause of the degraded vacuum is attributed to loss of the Steam Jet Air Ejector (SJAE) inter-condenser loop seal due to a partially open SJAE steam supply valve (1-H0-163). The root cause of the 1-H0-163 valve being partially open was due to inadequate processing of an emergent work order related to the reach rod position indication versus the actual valve position.

Following the reactor scram, all rods were verified to be fully inserted and the Primary Containment Isolation System Group II (Reactor Building) and Group VI (Reactor Water Cleanup System) actuations occurred as designed due to the expected reactor water level shrink associated with the scram signal. Standby Gas Treatment System Train 'B,' which is designed to shutdown 65 seconds after the Group II signal is received if the Standby Gas Treatment Train 'A' is in service, continued to operate until manually secured. With this exception all other plant systems responded as designed.

This event had no impact on the health and/or safety of the public because emergency core cooling systems were operable and available to perform their required safety functions.

On October 23, 2011, at 09:15, Nine Mile Point Unit 2 (NMP2) was operating at 100 percent of rated thermal power when the Division I reactor water cleanup system (RWCU) differential flow - high channel was declared inoperable due to failing its channel check. A troubleshooting plan was developed to determine the cause for the failed channel check.

While performing the troubleshooting plan, at three separate times (October 24, 2011 at 01:52, 02:58, and 05:19), both the Division I and Division II RWCU differential flow timers were placed in bypass, and Technical Specification (TS) 3.3.6.1, Condition B was entered for one or more automatic functions with isolation capability not maintained. In each of the three instances, one channel of the RWCU differential flow - high function was restored to operable status within 1 hour as required by TS 3.3.6.1 Required Action B.1. In the morning of October 24, 2012 the oncoming crew recognized that bypassing both RWCU differential flow timers in this manner could have prevented the fulfillment of a safety function.

The cause of this event was human performance error. The operating crew became focused on the completion time associated with the LCO condition and never fully evaluated the Technical Specification Bases.

The crew involved in this event has been coached. An Operations department communication has been sent as a result of this event which reinforced the requirements of TS 3.0.2 Bases and the importance of an operating crew to use all available information with the Shift Manager as the single point of accountability. The RWCU system operating procedure has been revised to clarify the reportability requirements when removing both divisions of the RWCU high differential flow isolation from service. A training needs assessment has been initiated to determine if additional training is needed on TS Bases.

On April 28, 2011, at 2338 hours Central Daylight Time, with all three units in cold shutdown and power supplied to the 4-kV shutdown buses by onsite emergency diesel generators (EDGs), Browns Ferry Nuclear Plant personnel performed a shutdown of the Unit 1/2 C EDG. The Unit 1/2 C EDG was shutdown due to a hydraulic oil leak in piping for the EDG governor that was causing voltage and frequency fluctuations. Following shutdown of the Unit 1/2 C EDG, the 4-kV shutdown board C, which was being powered by the Unit 1/2 C EDG, de-energized. This resulted in a loss of power to the 1B Reactor Protection System causing a Primary Containment Isolation System (PCIS) actuation. The PCIS isolation (Group 2) caused the loss of Shutdown Cooling on Unit 1 for 47 minutes. In addition, the loss of power to the 4-kV shutdown board C also caused the loss of the 2B Residual Heat Removal (RHR) pump leading to a momentary suspension of Shutdown Cooling for Unit 2. Shutdown Cooling for Unit 2 was immediately restored using the 2D RHR pump. The root cause of the oil leak was determined to be a less than adequate design of the Unit 1/2 C EDG governor oil piping to compensate for vibration I loading.

This report also constitutes a 10 CFR 21 notification.

On December 26, 2010, at 1615 hours Central Standard Time, an alarm for Main Turbine Vibration High 3-VA-47-15 was received in the Unit 3 control room on annunciator panel 3-XA-55-7B Window 32.

Control room operators responded using Unit 3 Alarm Response Procedure (ARP) 3-ARP-9-7B. Exciter rotor inboard journal bearing vibration level indicated 8.0 mils and rising, and the outboard journal bearing indicated 5.5 mils and rising. At 1617 hours, an Upper Power Runback was initiated per the ARP. It was noted that vibration levels initially lowered then continued rising. At 1620 hours, control room operators initiated a manual reactor scram.

The direct cause of this event was an exciter rotor-deflector rub resulting from a combination of high differential air exit temperatures and existing decreased clearances on the rotor. The root cause was inadequate procedural guidance for monitoring the exciter air cooling system and prescribing mitigation actions to be taken based on differential temperature limits.

The rub was corrected during the forced outage. Corrective actions include installation of cooler vents for use in minimizing air binding, establishment of a cooler venting process, increased controls and documentation of manual "balancing" valve manipulation, increased system monitoring process rigor and oversight, and performance of a training analysis for inclusion of relevant aspects of this root cause into the Operations and Engineering training materials.