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On November 25, 2017 Comanche Peak, Unit 2 received alarms indicating a trip of both main feedwater pumps. After confirming a decreasing water level in all four steam generators, the control room initiated a manual reactor trip. All safety systems responded as designed including the automatic start of the auxiliary feedwater system. The cause of the trip of both main feedwater pumps could not be positively identified. Causal analysis indicates that a prior plant modification maintained power to abandoned relays in the Solid State Protection System that may have caused both main feedwater pumps to trip. Subsequent actions were taken to remove the fuses that provided power to the abandoned relays on both Unit 1 and Unit 2 to eliminate recurrence from this possible source. Additional corrective actions have been entered into the Comanche Peak Corrective Action Program.

All times below are in Central Standard Time (CST).

On August 20, 2017 at 1605 PDT, Columbia Generating Station was manually scrammed due to a rise in Main Condenser back pressure. The rise in back pressure was due to the spurious closure of the Main Condenser Air Removal Suction Valve (AR-V-1) as a result of the failure of it's associated solenoid pilot valve. Following the reactor scram and depressurization of the reactor a Level 3 actuation occurred. In addition a startup flow control valve failed which necessitated throttling of the Feedwater start-up level control isolation valve to control Reactor Pressure Vessel level. All other safety systems functioned as expected and all control rods were fully inserted. Reactor decay heat was removed via bypass valves to the main condenser.

The apparent cause was the plant modification to address the single point vulnerability of the closure of AR-V-1 was not implemented in time to prevent a plant shutdown. A temporary modification has been installed to maintain AR-V-1 open for the remainder of the operating cycle.

These events are reportable in accordance with 10 CFR 50.73(a)(2)(iv)(A).

On June 8, 2017 at 1527 hours, the reactor automatically scrammed due to a loss of Main Turbine- Electro-Hydraulic Control (EHC) logic power causing a high neutron flux, Reactor Protection System (RPS) trip. The safety systems operated as expected. Secondary Containment differential pressure lowered to 0" WG due to a trip of the normal operation of the Reactor Building Ventilation system. The differential pressure was restored by the initiation of Standby Gas Treatment System.

The scram was caused directly by a DC+ (direct current, positive) test lead (Maxi Grabber) that inadvertently contacted with the grounding screw, causing a short and momentary loss of EHC logic power.

Immediate action was taken to validate that there was no damage to the +30 VDC (volts DC) EHC logic.

The root cause for this event is an insufficient focus on the High Risk Activity of adjusting the EHC power supply, and inadequate risk mitigating actions for that activity.

The condition is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) as an event that resulted in an automatic actuation of the RPS, including reactor scram. Although no safety system functional failure occurred, this event is also reportable pursuant to 10CFR 50.73(a)(2)(v)(C) as a condition that could have prevented fulfillment of a safety function. There were no actual, or potential consequences to the health and safety of the public as a result of this event.

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On 2/4/16 at 11:21, Salem Unit 2 automatically tripped from approximately 74% power. Power had been reduced at the beginning of dayshift to support a 500 KV transmission line outage. The reactor trip was due to a Main Turbine trip caused by a Main Generator Protection signal initiated by a main generator automatic voltage regulator (AVR) volts/hertz over excitation protection relay. All emergency core cooling systems and emergency safeguards feature systems functioned as expected. As found calibration data for the generator protection logic relay were found out of specification low. An evaluation determined the cause of the generator protection relay trip was poor manufacturing quality and/or shipping damage to an adjusting rheostat.

This report is being made in accordance with 10 CFR 50.73 (aX2Xiv)(A), "Any event or condition that resulted in manual or automatic actuation of any of the systems listed in paragraph (a)(2)(iv)(B)," specifically automatic actuation of the Reactor Protection System and the Auxiliary Feedwater System for this event.

On June 26, 2017, Operations commenced a downpower from 100 percent to 93 percent reactor power to support performance of the Main Turbine Stop and Control Valve Test. With reactor power at 94 percent, the 22 Main Boiler Feed Pump Turbine (MBFPT) speed control trouble alarm annunciated coincident with pump speed swings of 800 revolutions per minute (rpm). The operators ceased the downpower and placed the 22 Main Boiler Feedwater Pump (MBFP) in Manual speed control to control the rpm swings. This was unsuccessful, and the rpm swings continued. The 22 MBFPT low pressure (LP) governor valves were observed to be cycling from full-closed to full-open. The decision was made to take local pneumatic control of the 22 MBFP to stabilize pump speed. Two minutes after establishing local pneumatic control, the LP governor valves went to full closed. With the rapid reduction in 22 MBFP speed, the pump was no longer delivering feedwater flow to the SGs. An automatic main turbine runback signal should have been generated on a low speed signal; however, there was no turbine runback actuation. In response, the operators commenced a manual runback to reduce main turbine load, but the decreasing SG levels reached 15 percent, and at 1531 hours a manual reactor trip was initiated.

All control rods fully inserted and all required safety systems functioned properly. The plant was stabilized in hot standby with decay heat being removed by the main condenser. The direct cause of the reactor trip was that the shoulder screws used on the 22 MBFPT LP governor valve servomotor linkage had backed out and detached. This caused the LP governor valves to fail closed, shutting off the turbine steam supply. This event had no effect on the public health and safety. The event was reported to the Nuclear Regulatory Commission (NRC) on June 26, 2017 under 10 CFR 50.72(b)(2)(iv)(B), 50.72(b)(2)(xi), and 50.72(b)(3)(iv)(A).

On April 26, 2017, Arkansas Nuclear One, Unit 1 (ANO-1), was operating normally at 100% rated thermal power.

The 500kV transmission line to the substation at Pleasant Hill, Arkansas was out of service for planned maintenance.

The area around the plant was experiencing severe weather from thunderstorms and tornado warnings had been issued from the National Weather Service for the four county area.

At approximately 1002 CST switchyard breakers for 500kV lines opened on fault current. High winds had damaged the transmission towers approximately 16 miles away from ANO and caused phase to ground faults. This resulted in a loss of all offsite power lines to the 500kV bus. The autotransformer also locked out as designed when the 500kV transmission lines faulted.

The Reactor Operator initiated a manual reactor trip about 8 seconds after the 500kV lines tripped and prior to the reactor protection system initiating an automatic trip. During this time both emergency diesel generators (EDGs) (EK) started as expected. EDG #2 re-energized one Engineered Safeguards bus. EDG #1 ran unloaded until shutdown.

The plant was stabilized in Mode 3 with Emergency Feedwater (EFW) pumps supplying the steam generators, maintaining the water level at the natural circulation setpoint.

On March 23, 2017, at 0014 Eastern Daylight Time (EDT), Watts Bar Nuclear Plant Unit 2 experienced an unplanned trip condition of both Turbine Driven Main Feed Pumps (TDMFPs) following a loss of Main Condenser Vacuum. The trip of both TDMFPs caused an automatic start of both Motor Driven Auxiliary Feed Water Pumps and the Turbine Driven Auxiliary Feed Water Pump as designed.

The plant was performing a normal startup, and had just synchronized the main generator to the grid. Subsequent to the event, the plant was transitioned to Mode 3 by inserting all control rods with a manual trip. All plant safety systems operated as expected.

The loss of condenser vacuum was the result of a significant breach of the Unit 2 main condenser - B zone. This failure is attributed to the main condenser neck support structural design being inadequate to maintain integrity within specification. Repairs to the condenser will be completed prior to Unit 2 returning to service.

On March 10, 2017, at approximately 7:14 a.m. CST, the reactor operator manually actuated a reactor scram in response to an abnormal increase in steam pressure. Reactor power was approximately 15 percent at the time. The turbine generator had been synchronized to the grid at 5:13 a.m. on March 10, and was being closely monitored by engineers and operators since a major modification to the turbine electro-hydraulic control (EHC) system had been installed during the recent refueling outage.

Approximately 45 minutes prior to the manual scram, a main control room alarm actuated indicating a problem with the EHC system.

A few minutes later, it was reported from the turbine building that there was a steam leak in the area of the EHC steam pressure transmitters. Shortly thereafter, reactor pressure began to increase with no demand signal present, at which time the reactor operator initiated the scram. The main feedwater system remained in service, and reactor water level control performed normally as designed. No reactor safety-relief valves actuated. The main turbine bypass valves did not open following the shutdown, and engineering review determined this condition was consistent with the response to the abnormal configuration of the EHC system pressure transmitters created by efforts to isolate the leak locally. Approximately five minutes after the scram, the outboard main steam isolation valves were manually closed to limit the reactor cooldown rate. This event resulted from the incorrect installation of a new compression fitting in the steam pressure instrumentation tubing for the main turbine control system. This event is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) as a manual actuation of the reactor protection system.

On April 17, 2017, at 0004 Eastern Daylight Time, Unit 1 was in Mode 1 at approximately 100 percent of rated power, and Unit 2 was in Mode 1 at approximately 22 percent of rated power and was starting up from a refueling outage. Operators manually tripped the Unit 2 main turbine to halt increasing bearing vibration.

The power circuit breakers (PCBs) for the Unit 2 main generator did not open as expected on the turbine trip, but subsequently opened when main generator reverse power relays actuated. This resulted in the automatic start of all four emergency diesel generators (EDGs). The EDGs did not tie to emergency busses because offsite power was still available. This event resulted from a component which failed due to foreign material intrusion. A limit switch associated with a main turbine stop valve failed to change states when the turbine was tripped. The limit switch configuration, together with other logic, satisfied the conditions to start the EDGs. The limit switch failure resulted from foreign material in the switch. The failed limit switch was replaced. Planned corrective actions include inspecting similar switches on both units, and sealing the wire entrances of the switch bodies to improve foreign material exclusion.

On October 14, 2016, Clinton Power Station (CPS) determined subsequent to the 3rd Quarter NRC Exit Meeting that a condition prohibited by Technical Specification (TS) 3.7.6, "Main Turbine Bypass System," had occurred associated with a failure to complete a TS Required Action within the associated Completion Time.

Specifically, testing of Main Steam Turbine Bypass Valve (TBV) Numbers 4, 5, and 6 was not performed within the required test' interval and the TBVs were appropriately declared inoperable as required by TS Surveillance Requirement.(SR) 3.0.1.

Thermal Limit penalties were applied as required by Limiting Condition for Operation (LCO) 3.7.6. A Surveillance Frequency Change was processed in accordance with TS Program 5.5.16, "Surveillance Frequency Control Program," in June 2016 to change the Frequency for SR 3.7.6.1 from 31 days to 12 months. TBVs 5 and 6 were subsequently declared OPERABLE and the thermal limit penalties removed without performing the required SR 3.7.6.1, contrary to TS SR 3.0.1 Bases.

The apparent cause of this event was determined to be that no specific requirement exists in either plant procedures or industry guidance which prohibits declaring a component or system OPERABLE based solely on an extension of the required surveillance test interval. Corrective actions include testing the valves with an alternate method and completing administrative procedure changes. This event is reportable under 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by TS.

On October 8, 2016, the Shearon Harris Nuclear Power Plant was reducing power to enter a planned refueling outage (RFO-20). The plant was at approximately 8 percent power in Mode 1 when the unit experienced an unplanned reactor trip with a safety injection (SI) and main steam line isolation (MSLI). A malfunction of the turbine controller during turbine mechanical overspeed trip testing caused an excessive draw of steam flow from the Steam Generators (SGs). This caused the Engineering Safety Features Actuation System instruments to detect a valid change in SG pressure and initiate a rate compensated Low Steam Line Pressure signal. This signal initiated a SI and MSLI, which in turn initiated reactor trip, turbine trip, feedwater isolation, and closed the main steam isolation valves.

Degraded equipment within the turbine controller resulted in excessive opening of the governor valves; this was caused by an inadequate supply of hydraulic oil to meet the increased system demand during testing. Insufficient hydraulic accumulator capacity was available to support system demand. One accumulator was known to be out-of-service; a second was discovered post-event. Also, a hydraulic oil pressure switch used for turbine control was not functioning properly. The equipment deficiencies have been corrected.

Changes have been made to the testing procedure to validate at least four accumulators are in service prior to testing. The Power Operation (Mode 2 to Mode 1) procedure will also be revised to validate at least four accumulators are in service. A new calibration procedure will be implemented for the deficient oil pressure switch to ensure better quality control over verifying switch function.

On September 19, 2016, after achieving Cold Shutdown for the 1R26 Refuel Outage, as found testing was performed on all five (5) Electromatic Relief Valves (EMRVs). The "E" EMRV did not open from the Main Control Room (MCR), and no change in indication was observed. Per the work activity, technicians were dispatched to the Drywell to verify that the valve did not move upon receiving an open signal from the MCR.

A cutout switch in the valve actuator was stuck in the open position, thereby preventing the solenoid from actuating to open the valve. The cutout switch did not operate as required due to, hinge pin washers not installed in the cutout switch assembly. Without the washers installed to the hinge pins interfered with the solenoid frame holes creating mechanical binding. Based on this information it is suspected that the "E" EMRV would have been inoperable for longer than Technical Specification Allowed Out of Service Time (AOT) of 24 hours. Testing and inspections were performed on all EMRVs prior to installation in the plant.

Therefore, this issue is reportable under 10 CFR 50.73(a)(2)(i)(B) as an Operation or Condition which was Prohibited by the plant's Technical Specifications.

On 6/28/16 at 04:22 Salem Unit 2 automatically tripped from 100% power on Generator Protection. The reactor trip was initiated due to a Main Turbine (MT) trip caused by a Main Generator ProtectiOn signal.

All emergency core cooling systems and emergency safeguards feature systems functioned as expected.

The motor driven and steam driven auxiliary feedwater pumps started as expected on steam generator low level. Operators stabilized the plant in Mode 3 with decay heat removal via the main steam dump valves and auxiliary feedwater system.

Investigation identified that a broken current transformer core ground wire internal to the A Main Power Transformer (MPT) was intermittently touching the X1 and X2 low voltage connections inside the transformer bushing compartment causing a ground fault. This caused the turbine generator trip.

This report is being made in accordance with 10CFR50.73 (a)(2)(iv)(A), "Any event or condition that resulted in manual or automatic actuation of any of the systems listed in paragraph (a)(2)(iv)(B)," for this event actuation of the Reactor Protection System (RPS) and the Auxiliary Feedwater System (AF).

On May 31, 2016 at 1626, Calvert Cliffs Unit 1 experienced an automatic reactor trip. The cause of the trip was a spurious high level steam generator signal due to a failed Steam Generator 11 Channel B High Level Turbine Trip Under Voltage Logic Module, 12/4BL-XA27.

The spurious high level trip signal resulted in a turbine trip followed by an automatic reactor protection system trip on loss of load. The failed under voltage logic module was sent off-site to the vendor to conduct a failure analysis. The analysis identified two most probable causes for the failure. The first most probable cause was due to an intermittent failure of an integrated circuit of the under voltage logic module. The second most probable cause was due to an inadvertent solder bridge between a pin on the integrated circuit chip and the board. A refurbished logic module was installed and subsequently tested prior to the unit returning to power. The corrective action planned to prevent recurrence is to replace the current Engineered Safety Features Actuation System (which includes the non-safety high level turbine trip) with a system that will eliminate single point vulnerabilities within this system.

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On May 15, 2016, with Millstone Power Station Unit 3 (MPS3) operating in MODE 1 at 74% power, the operators observed decreasing hydrogen pressure in the main turbine generator. Upon field investigation it was determined there was an active hydrogen leak from the main generator. The operators manually tripped the reactor and vented the hydrogen from the main generator. The reactor trip was uncomplicated. The auxiliary feedwater (AFW) pumps started as designed on low steam generator level and operators maintained steam generator level.

The active hydrogen leak was the direct cause of the manual reactor trip. The hydrogen leak was caused by a dislodged plug on a port on the main generator. MPS maintenance procedures did not contain adequate procedural guidance in that there was no specific direction for installation, i.e., torque value and verifications. The procedures will be revised to include specific direction to tighten the plugs and applicable verifications (i.e., torque value, peer checking). Additional corrective actions are being taken in accordance with the station's corrective action program.

The actuation of the RPS and the automatic start of the AFW pumps is being reported in accordance with 10 CFR 50.73 (a)(2)(iv)(A) as an event that resulted in manual or automatic actuation of systems listed in 10 CFR 50.73(a)(2)(iv)(B).