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On October 4, 2017 at 0155 hours, while in Mode 1 at 100 percent rated thermal power, inoperability of both A and B trains of Motor Control Center, Switchgear, and Miscellaneous Electrical Equipment Areas Heating, Ventilation, and Air Conditioning System and Battery Rooms Exhaust System (M23/24) occurred. Train A was shutdown and declared inoperable based on excessive drive belt noise and belt malfunction. Train B was inoperable due to ongoing maintenance on its associated chilled water system. The combination of inoperability resulted in a loss of safety function. Technical Specification (TS) 3.0.3 was entered per plant procedures, and at 0250 hours a plant shutdown was commenced. At 0620 hours, the A train of M23/24 was declared operable following belt replacement and TS 3.0.3 was exited. The plant was restored to 100 percent rated thermal power at 0804 hours.

The cause was determined to be inadequate procedural guidance in that the "general tensioning" method described in plant maintenance procedure, V-belt and Sheave Maintenance, is insufficient for restoring components to a reliable condition. Corrective action includes revising the procedure for correct tensioning guidance.

The safety significance of this event is considered to be very small. This event is being reported in accordance with 10CFR50.73(a)(2)(v)(B), 10CFR50.73(a)(2)(v)(C), and 10CFR50.73(a)(2)(v)(D) as an event or condition that could have prevented the fulfilment of a safety function.

NRC FORM 386 (06-2016)

On September 7, 2017, Wolf Creek Generating Station (WCGS) was in Mode 1 at 100 percent power. During evaluation of protection for safety-related equipment from the damaging effects of tornados, WCGS personnel determined that the non safety-related exhaust lines from safety-related atmospheric relief valves (ARVs) and main steam safety valves (MSSVs) could be crimped by tornado generated missiles. If these are crimped completely, these components may be unable to perform their safety functions. The ARVs and MSSVs were declared inoperable and Enforcement Guidance Memorandum (EGM) 15-002, "Enforcement Discretion for Tornado- Generated Missile Protection Noncompliance," Revision 1 was applied. Immediate compensatory measures consistent with EGM 15-002 were implemented within the time allowed by the applicable Technical Specification Limiting Condition(s) for Operation. The ARVs and MSSVs were subsequently declared operable but nonconforming. These tornado missile vulnerabilities existed since the original plant construction. Actions will be taken to establish compliance for these components either by a plant modification or employing a methodology for addressing tornado missile non-conformances.

On April 5, 2017, WCGS personnel provided a 10 CFR 50.72 notification in Event Notification (EN) 52666 concerning tornado missile protection issues known at that time. As stated in EGM 15-002, the NRC will exercise enforcement discretion for subsequent tornado missile 10 CFR 50.72 notifications. Therefore, no 10 CFR 50.72 notification was made for this condition.

Technical Specification 3.7.6. A pinhole sized through wall leak was discovered on the downstream side of CD-123, the 32 Auxiliary Boiler Feed Pump Bearing Cooling Relief Valve, which was unisolable to the Condensate Storage Tank.

The pinhole leak was identified following the performance of 3PT-Q120B, 32 Auxiliary Boiler Feed Pump Functional Test. All Operability and Acceptance Criteria of 3PT-Q120B were sat. The relief valve was removed from the system and sent to a vendor for evaluation. After the vendor evaluation, it was determined that the valve pinhole area leak was due to a casting defect.

This event was determined to be reportable as a Loss of Safety Function pursuant to10 CFR 50.72(b)(3)(v)(B) - 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 remove residual heat.

RC FORM 366 (04-2017)

On May 17, 2017, during Refueling Outage (RFO)-21 while performing an extent of condition review it was discovered that the contact indicating tabs of relays 16A-K30 and 16A-K54 of the Pilgrim Nuclear Power Station (PNPS) Primary Containment System, were visually hanging in the mid-position (partial travel).

The relays were replaced during RFO-21 along with 16A-K29 and 16A-K53, and all four relays were sent to an offsite vendor for further testing and analysis. Other relays were reviewed but were determined to be outside the scope of this extent of condition review.

PNPS stated at the time that this event was reportable under 10 CFR 50.73(a)(2)(i)(B) - Operation or condition prohibited by Technical Specifications; and potentially reportable in accordance with 10 CFR 50.73(a)(2)(v)(B), (C) and (D) - Any condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to remove residual heat, control the release of radioactive material and mitigate the consequences of an accident. However, additional information provided by our offsite vendor and an engineering evaluation, support the conclusion that there was never a loss of safety function regarding any of the four relays (16A-K29, 16A- K30, 16A-K53 and 16A-K54). Therefore, this event was not reportable under 10 CFR 50.73(a)(2)(i)(B) nor under 10 CFR 50.73(a)(2)(v)(B), (C) or (D).

This event posed no threat to public health and safety.

On April 17. 2017, the staff identified a low refrigerant level in the Unit 1 train B essential chilled water (EC) system chiller during inspection. Operations personnel immediately declared EC chiller train B inoperable. On April 17, 2017, the leak was corrected and EC chiller train B was refilled with refrigerant to within the manufacturer's specifications. Operations personnel declared the system operable on April 18, 2017. The chiller had been inoperable since April 11. 2017, when the automatic purge system was placed into service. The direct cause of the low refrigerant level was leakage due to prior installation of a fitting on the automatic purge system filter without a plug.

During the 7-day period that EC chiller train B was inoperable, the supported low pressure safety injection (LPSI) system train B was inoperable. LPSI train A was also inoperable for approximately 17 minutes on April 13, 2017, during the performance of a routine surveillance test. This 17-minute period represented a condition that could have prevented the fulfillment of a safety function.

The cause of the leak was determined to be ineffective work instructions that did not identify the appropriate part number to be used during filter replacement. Corrective actions include revision of the work instructions. This change will ensure that the existing plug remains in place during filter element replacement. A leak test was also added to the work instructions to verify that no refrigerant leaks are present following maintenance.

A review of the current licensing basis revealed that intentionally coupling the Seismic Category I Service Water System 'SWS) with the not Seismic CAT I Standby Service Water System (SWE)(KG) is a non-conformance with the current icensing basis, and renders the SWS inoperable. As a result, a review of the SWS Design Basis Accident (DBA) full flow surveillance test revealed that during the past three years performance, there were two trains of SWS concurrently inoperable for a time period, as logged, greater than the seven hour shutdown completion time required by Technical Specification 3.0.3.

This condition is reportable as an operation or condition which was prohibited by the plant's Technical Specifications under 10 CFR 50.73 (a)(2)(i)(B), and could have prevented the fulfillment of a safety function under 10 CFR 50.73(a)(2) (v)(B) for the SWS along with the systems that it supports of Emergency Core Cooling (ECCS), Primary Component Cooling Water System (CCP), and the Recirculation Spray System (RSS) .

The plant was not aligned to this configuration at the time of discovery, and all procedures have been revised to eliminate this condition.

On March 7, 2016, while performing set-up activities for 2-PT-R084C, "23 EDG 8 Hour Load Test," the normal supply breaker to 480 Volt AC Bus (ED) 3A tripped on overcurrent. This caused 480 Volt AC Buses 3A and 6A to de-energize since, as part of the test set-up activities, the tie breaker (3AT6A) between Buses 3A and 6A was closed and the normal supply breaker for Bus 6A was opened. This resulted in a loss of both 21 and 22 Residual Heat Removal (RHR) (BP) pumps. As 'designed, all Emergency Diesel Generators (EDGs) (EK) received automatic initiation signals to start. All required 480 Volt AC buses automatically re-energized by design, with the exception of Bus 3A, which had an overcurrent lockout. Operators manually started 22 RHR pump to restore RHR cooling.

However, prior to restoring the normal supply power to Bus 3A, 23 EDG tripped on overcurrent which resulted in a second loss of RIM event. The cause for the Bus 3A supply breaker tripping was inadequate procedural guidance resulting in excessive loads being energized on Buses 3A and 6A. The direct cause for 23 EDG tripping was cracked solder joints on the automatic voltage regulator (AVR). Corrective actions included revising 2-PT-R084C and replacing the voltage regulator. The event had no effect on public health and safety.

On Thursday July 28, 2016, at approximately 2357 hours with power level at approximately 100 percent, Nine Mile Point Unit 1 (NMP1) experienced a loss of Uninterruptible Power Supply (UPS), UPS 162B which resulted in loss of Reactor Protection System (RPS) Bus 11. Numerous half scram and half isolation signals were generated in addition to the isolation of both # 11 and # 12 Emergency Condensers (ECs).

EC # 12 was returned to standby on 7/29/2016 at 0041 hours and EC # 11 was returned to standby on 7/29/2016 at 0045 hours. The causes of this event were the failure of a UPS capacitor and the bypass power transfer set point being set too low for the type of transient. Corrective actions include immediate replacement of the failed capacitor, installation of new higher temperature rated capacitors and adjusting the low voltage bypass power transfer set point.

This event is reportable under 10CFR50.73(a)(2)(v)(B).

On March 4, 2016, during the Braidwood NRC Component Design Basis Inspection, a concern was raised regarding why it was acceptable for the diesel driven Auxiliary Feedwater (AF) pump engine combustion air intake to be located in the turbine building, a non-safety related structure. On March 7, 2016, the additional evaluations that were completed for Byron determined that the existing configuration did not adequately support diesel engine operation with high energy line break (HELB) conditions in the turbine building, and at 0400 hours Operations entered Technical Specification Limiting Condition for Operation 3.7.5, "Auxiliary Feedwater (AF) System," Condition A, "One AF train inoperable," for one train (B-train) of AF inoperable for both Units 1 and 2. The AF trains were declared operable following a corrective action to install a temporary configuration change to provide an engine combustion air intake from the auxiliary building.

The cause of the event was insufficient validation of vendor analysis inputs in 1993 while reviewing the AF diesel engine's ability to function during a turbine building HELB event.

The corrective actions planned are to develop and install a permanent modification to re-route the AF diesel engine intakes for Unit 1 and 2.

On January 19, 2016, at approximately 1100 Central Standard Time (CST), during troubleshooting of the Main Control Room (MCR) green light indication on the 3A Residual Heat Removal (RHR) Pump Motor Breaker Transfer Switch (MBTS), it was discovered that the 3A RHR Pump MBTS had malfunctioned, potentially preventing the pump from starting from the MCR. The 3A RHR Pump was declared inoperable.

On January 20, 2016, at approximately 0030 CST, the 3A RHR Pump was declared operable following replacement of the 3A RHR Pump MBTS.

A Past Operability Evaluation concluded that the 3A RHR Pump was inoperable from January 9 to January 20, 2016, exceeding the Technical Specification allowed outage time. During this time, the 3B and 3D RHR Pumps were also inoperable on January 14, 2016, from 0127 to 0215 CST, resulting in a Safety System Function Failure. A Probabilistic Risk Assessment determined there was a negligible increase in risk.

The cause of this event was failure of the transfer switch to fully latch due to binding resulting from the MBTS being installed greater than its twenty-one year service life with no Preventative Maintenance (PM) performed. Corrective actions include verifying similar transfer switches are latched in the NORMAL positon on BFN, Units 1, 2, and 3, and creating a PM activity with a replacement schedule for these switches.

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 November 10, 2015, at 1502 Eastern Standard Time (EST), two cold weather suits were inadvertently dropped into the equipment pit portion of the Sequoyah Nuclear Plant Unit 2 reactor cavity, resulting in two containment recirculation drains being declared inoperable. Technical Specification (TS) Limiting Condition for Operation (LCO) 3.6.15, "Containment Recirculation Drains," and TS LCO 3.0.3 were entered. The first suit was removed from the equipment pit at 1553 EST.

At that time, only one of the drains remained inoperable and LCO 3.0.3 was exited. The remaining suit was removed from the equipment pit at 1556 EST, and LCO 3.6.15 was exited. Plant conditions were restored to normal within the allowed LCO times and no plant shutdown was required. The two cold weather suits in the Unit 2 reactor cavity area created the potential for obstructing the flow path for containment recirculation adversely affecting the safety function of the Containment Spray and Emergency Core Cooling Systems that are needed to mitigate the consequences of a design basis accident. The effect of this condition resulted in an unanalyzed condition that significantly degraded plant safety.

The apparent cause was failure of the Maintenance personnel to identify and mitigate potential hazards and risks during the pre-job briefs, 2-minute rule, and walk downs. Corrective action includes addition of risk mitigation strategies to the containment access control procedure. Unit 1 was unaffected by this event.

On May 2, 2015, the Monticello Nuclear Generating Plant (MNGP) was in Mode 5 for a refueling outage.

During performance of surveillances of the non-credited 4kV essential Bus, MNGP experienced a loss of the 4kV Bus and essential Load Center due to an improperly landed jumper wire. Loss of the Load Center de- energized the valve position indication on the Residual Heat Removal (RHR) shutdown cooling inboard isolation valve, causing a subsequent trip of the RHR pump operating in shutdown cooling on a pump suction interlock and a loss of normal shutdown cooling. Control Room operators entered the appropriate abnormal procedures and verified alternate decay heat removal was in service until shutdown cooling could be restored.

Immediate corrective actions included suspension of all work pending approval of the shift manager to ensure outage activities did not further degrade plant conditions and electrical work was limited to protect shutdown cooling. The essential Load Centers were cross tied to restore normal shutdown cooling.

Corrective actions include revising procedures to reinforce human performance tools, adequately assess risk involved with electrical work, and ensuring effective barriers are in place to harden residual heat removal function durina shutdown conditions.

On March 12, 2015, after further evaluation of system performance of SRV-3A and SRV-3C, along with results of valve internal conditions identified during physical inspection, the valves were determined to have been inoperable for an indeterminate period during the last operating cycle. Specifically, SRV-3C was determined to be inoperable based on its on-demand performance at low reactor pressures, as well as the visual conditions that were identified during the inspection process. SRV-3A was considered inoperable based on it having similar internal indications as SRV-C when it was disassembled and inspected. SRV-3A Was installed in May 2011 and SRV-3C was installed in October 2013.

Additionally, during an extent of condition review of historical SRV performance, the review identified on March 13, 2015 that SRV-3A had failed to open in response to three manual actuation demands on February 9, 2013.

At the time the valves were declared inoperable the reactor was at 100% power. The valves had been replaced in February 2015 during the forced outage relating to winter storm Juno. This event posed no threat to public health and safety.

On February 11, 2015, at 0820 Central Standard Time, Brown's Ferry Nuclear Plant (BFN), Unit 3, declared the High Pressure Coolant Injection (HPCI) and Reactor Core Isolation Cooling (RCIC) systems inoperable due to no suction source aligned. During surveillance testing, the Condensate Storage Tank (CST) emergency discharge isolation valve energized and closed when the breaker was closed, isolating both systems from their suction source. It was subsequently determined that maintenance task. Operations personnel re-opened the isolation valve using the hand switch in the Control Room, restoring operability to the HPCI and RCIC systems.

The apparent cause of this event was inadequate design review of a 2010 plant modification which allowed latent design vulnerabilities to be introduced into the plant.

The corrective actions to reduce the probability of a similar event occurring in the future were to remove thermal overload heaters from the affected breakers, preventing valve closure when these breakers are closed; to review a sample of recent engineering change packages for quality of Design Review; to repair a faulty hand switch; and to implement a design change for the CST isolation valves for all three BFN units to prevent spurious operation of the isolation valve when the associated breaker is closed.