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On April 20, 2002, power ascension was in progress following a refueling outage. At 0500 EDT, a control room alarm was received due to the water level decreasing in steam generator (SG) #4. The reactor operator (RO) increased the speed of the A main feedwater pump (MFP). Almost simultaneously, the balance-of-plant operator recognized that the A MFP mini-flow valve was open and an operator in the turbine building was directed to shut it. Water levels in all four SGs began to rise rapidly, and operators lowered the MFP speed and throttled the main feedwater regulating valves. However, at 0509 EDT, SG #4 reached its high level setpoint which led to a turbine trip, a main feedwater isolation, and an auxiliary feedwater system actuation. The shift superintendent ordered a manual reactor trip, which occurred at 0510 EDT.

The causes of this event are: the failure to increase MFP speed in normal increments to correspond with increased water demand as reactor power was rising, and an inadequate response to the SG water levels when it was recognized that levels had dropped too low. The operating crew involved has been counseled on the expectations of managing evolutions and performed just-in-time training prior to assuming the next shift.

On April 15, 2006, while at 100% power, the Unit 1 Control Room crew was challenged by an erratic response of the Loop 3 Main Feed Regulating Valve (MFRV), 1FV0530, while operating in automatic.

The crew was able to stabilize the valve in manual mode, however, over the next 24 hours the control of the valve continued to degrade. On April 16, 2006, it was decided that Unit 1 would be taken to Mode 3 for investigation of the control issue with 1FV0530. On April 17, 2006, at 0026 EDT, Unit 1 was manually tripped at 33% power when Steam Generator number 3 water level was observed to be slowly increasing with 1FV0530 unable to control level in either automatic or manual.

A review found that 1FV0530 operated erratically due to a failed I/P transducer, which resulted in the inability to reduce feedwater flow requiring a manual reactor trip. Based on the results of the observations and failure analysis performed on the I/P transducer, two failures were identified. One failure was the supply air input connector and the resultant electrical to pneumatic conversion process for a valve internal to the controller, and the second failure was the electronic circuit board. The failed transducer and the remaining Unit 1 MFRV I/P transducers were replaced with different make and model I/P transducers prior to the unit restart.

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U.S. NUCLEAR REGULATORY COMMISSION

On April 21, 2008 at 0951 EDT, Unit 1 entered Mode 3, from Mode 4, with the pressurizer heaters in Group A inoperable. Unit 1 entered Mode 3 in a condition prohibited by Technical Specification (TS) 3.0.4. The condition was identified during a pressurizer heater capacity test on April 21, 2008 at 1818 EDT, when a Maintenance electrician observed open breakers on the Group A and C heater panels. The Unit 1 Control Room was immediately notified, and Operations entered a Required Action statement for TS 3.4.9, based on inoperability of pressurizer heater Group A while in Mode 3. The heater breakers were subsequently closed within the 72-hour Required Action statement.

The primary cause of this event was inadequate work instructions to perform the necessary pressurizer heater work. The functional testing requirement to complete heater resistance measurements was not properly planned in the work order to ensure that the equipment was properly tested before being placed in service. In addition, human performance tools were not used by the individuals involved in the manipulation of the breakers when it was determined the instructions were not adequate. The supplemental electrician associated with the pressurizer heater breaker mispositioning event was unaware of the plant procedure used to document breaker manipulation.

On December 7, 2009, at approximately 18:01 hours Eastern Standard Time (EST) with Unit 1 operating at 100 percent rated thermal power, an automatic turbine trip occurred due to low main condenser vacuum. In response to the turbine trip, the Reactor Protection System (RPS) actuated and automatically opened the reactor trip breakers. All control rods fully inserted into the core and all safety systems responded per design. Both Motor Driven Auxiliary Feedwater pumps and the Turbine Driven Auxiliary Feedwater pump started in accordance with plant design due to lo-lo steam generator water level in two steam generators. The unit was stabilized in Mode 3.

The cause of the low condenser vacuum was determined to be inadvertent operation of a control room handswitch that resulted in a de-energization of a non-lE 480 volt switchgear. The loss of power to the non-lE 480 volt switchgear resulted in the defeat of an interlock on the loop seal drain valve for the standby Steam Jet Air Ejector (SJAE) which allowed the valve to open. Once the water in the loop seal had drained to the main condenser, a path between the condenser and the atmosphere was established and the main condenser vacuum started to decline. Approximately nine minutes elapsed from the time the handswitch was inadvertently opened until the low main condenser vacuum turbine trip setpoint was reached which resulted in the automatic turbine trip and subsequent automatic reactor trip.

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On August 31, 2011 with Unit 1 operating in Mode 1 at 100 percent rated thermal power at approximately 0906 hours Eastern Daylight Time, the Unit 1 reactor automatically tripped. In preparation for maintenance on the controls for the main feedwater regulating valve (MFRV) on steam generator (S/G) 2, the valve was placed on an air gag. The air gag maintains the MFRV in position and allows minor changes in steam generator water level to be controlled by the bypass feedwater regulating valve (BFRV). However, shortly after the air gag was installed, feedwater flow to S/G 2 increased beyond the capability of the BFRV to control. The increase in feedwater flow to S/G 2 resulted in water level on S/G 2 exceeding the Hi-Hi nominal trip setpoint (NTS). This caused a main feedwater isolation, turbine trip and subsequent reactor trip in accordance with plant design.

The cause of the event was due to increased air pressure being supplied to the MFRV when the valve was placed on the air gag. The first corrective action was revising the procedure to ensure calibrated test gauges are used to determine the pressure setting of the regulator for the air gag and for an operator to be present while the MFRV is controlled by the air gag. The second corrective action is to replace the contact type potentiometer used in the MFRV control circuit which has been proven unreliable.

On February 15, 2012, with the unit at 100 percent power, it was determined that opening the boundary valve between the safety related and seismically qualified Refueling Water Storage Tank (RWST) and the non safety related and non seismically qualified Spent Fuel Pool Purification (SFPP) system in Modes 1-4, renders the RWST inoperable. Plant procedures had been revised In 2009 to allow opening this boundary valve in Modes 1-4 under administrative controls. The 10 CFR 50.59 safety evaluation that had been performed to support the procedure change had concluded that the administrative controls would allow the RWST to remain operable. However, in consideration of the new interpretation provided in NRC Information Notice 2012-01, it was judged that the RWST would be considered to be inoperable regardless of the administrative controls established when the RWST was aligned to non-seismic piping in Modes 1 - 4. Since the boundary valve had been opened in Mode 1 under administrative controls and the one hour completion time of Technical Specification 3.5.4 Condition D was not entered, under this recent interpretation, this represented a condition prohibited by Technical Specifications and is reportable pursuant to 10 CFR 50.73(a)(2)(I)(B). This event had no significant safety consequence since a seismic event had not occurred while the SFPP system was in service on the RWST.

NRC FORM 386 (10.2010)

On November 27, 2013, an internal wiring discrepancy was discovered on Class 1 E battery charger 1AD1CB (EJ) following the trip of the battery charger AC input breaker.

The wiring discrepancy prevented the battery charger from performing all required functions of LCO 3.8.4, DC Sources - Operating. One of two redundant battery chargers and one battery per train must be operable to meet the requirements of LCO 3.8.4. Subsequent review of battery charger maintenance activities determined that on September 30, 2013 the remaining redundant operable battery charger was removed from service for maintenance activities for approximately 14.5 hours.

LCO 3.8.4, DC Sources - Operating requires restoration of the inoperable DC source within 2 hours or entry into Mode 3 within the next 6 hours, and entry into Mode 5 within the following 30 hours. Although the degraded charger was able to maintain battery terminal voltage within limits under minimal loading condition, the DC source was inoperable for a time greater than allowed by Technical Specification.

The safety significance of this event is very low. Unit 2 was not affected and there were no adverse effects to the health and safety of the public.

NRC FORM 365(104010) NRC RM 365I1 004010) FO LICENSEE EVENT REPORT (LEI) U.S. NUCLEAR REGULATORY COMMISSION

On 4/12/14 at 20:08, Unit 1 Reactor was manually tripped from 28 percent power. The manual trip occurred during power ascension following the 1R18 refueling outage. Control room operators received a Loop 1 Train B main steam isolation valve (MSIV) trouble annunciator followed by the MSIV not fully open annunciator. Control room operators recognized steam generator 1 level and loop 1 steam flow lowering and manually tripped the reactor.

Unit 1 was stabilized in Mode 3. Plant systems responded as expected with decay heat removal via Auxiliary Feedwater and steam discharge to the Main Condenser. Unit 2 was unaffected and there were no adverse effects on plant safety or on the health and safety of the public. This incident is of very low safety significance.

On July 27, 2014 at approximately 1409 Eastern Daylight Time, Vogtle Unit 1 was operating in Mode 1 at 100 percent power. While surveillance testing was being performed on the Main Feed Pump A (MFP A) a control oil leak developed in the lockout solenoid valve. The reduced control oil pressure resulted in a reduction of feed pump speed. Control Room Operators observed lowering feedwater flow to the Steam Generators and manually actuated the Reactor Protection System (RPS) system which resulted in a turbine-generator trip. All rods fully inserted into the core, the Main Feedwater Isolation system and the Auxiliary Feedwater system automatically actuated as expected. The unit was stabilized in Mode 3 and decay heat was discharged to the condenser. The cause of the event was a failure of the trip lockout solenoid valve which led to reduced pressure on the trip relay for MFP-A which reduced the speed of the pump and consequently the total feed flow to the Steam Generators.

The safety significance of the event is very low. Unit 2 was not affected and there were no adverse effects on the health and safety of the public.

APPROVED BY OMB: NO. 3150-0104 EXPIRES: 01/31/2017 Estimated burden per response to corn* Mth this mandatory collection request 80 hours.

Reported lessons teamed are incorporated into the Ficensitv process and fed back to industry.

Send comments regardng burden estimate to the FOIA. Rimy and Information Collections Branch (T-5 F53). U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by intemet e-mail to Infocollects.Resource@nrc.gov, and to the Desk Officer, Office of Information and Regulatory Affairs, NE013-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information collection does not dsplay a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

Reactor Coolant System Loop 2 Overtemperature Delta-T (OTDT) instrument channel 2T-421 was restored to service on February 26, 2005, following maintenance to correct overtemperature setpoint (OTSP) drift by replacing a summing amplifier. After the channel was returned to service, the OTSP signal continued to drift until March 3, 2005, when 2T-421 was again removed from service and a different summing amplifier replaced, correcting the drift anomaly. On July 21, 2005, an engineering evaluation of the instrument channel drift evolution concluded that this channel's OTSP signal had drifted outside of the Technical Specifications (TS) allowable values for the input signals for a period of time longer than allowed by the action requirements. Therefore, the unit had operated in a condition prohibited by the TS.

The causes of this event include the failure to perform adequate troubleshooting and post-maintenance testing on February 26, 2005. I&C technicians and their supervision were advised of the proper course of action expected for this type of event, and procedures were revised to clarify the expectations for functional testing following corrective maintenance.

On August 23, 2010 an Operations Superintendent was reviewing past performances of the reactor trip breaker surveillance test in preparation for an upcoming surveillance test on a reactor trip breaker.

During this review it was determined that on January 28, 2010 the 2B Solid State Protection System (SSPS) Mode Selector switch was placed in Test to perform a surveillance test on the 2B reactor trip breaker. Placing the 2B SSPS Mode Selector switch in Test defeats the Engineered Safety Features (ESF) automatic actuation signal to the 2B train components. At the time 2B SSPS Mode Selector was placed in test, the 2A high head safety injection (HHSI) pump was tagged out of service for planned maintenance. In this configuration, both trains of HHSI were rendered inoperable and outside the Conditions stated in Technical Specification 3.5.2, since neither train would have automatically started on an ESF actuation signal. Although not recognized at the time of the event, this condition required entry into Technical Specification LCO 3.0.3.

The cause of this event was due to an inadequate Loss of Safety Function (LOSF) determination, as described in Technical Specification 5.5.15, being performed and the work planning process not adequately identifying potential Technical Specification implications for the scheduled work.

hNRC FORM 366 (9-2007) PRINTED ON RECYCLED PAPER 5

On April 8, 2014 at approximately 04:30 Eastern Standard Time, Vogtle Unit 2 was operating at Mode 1 at 100 percent power when Unit 2 received a Steam Generator 3 narrow range low-low level automatic Reactor Protection System actuation as a result of the Loop 3 Main Feedwater Regulating Valve failing closed. The RPS actuation resulted in a trip of the turbine-generator. All rods fully inserted into the core, the Main Feedwater Isolation system and the Auxiliary Feedwater system automatically actuated as expected. The plant was stabilized in Mode 3 and the decay heat was discharged to the condenser. The cause of the event was a failure of the Steam Generator 3 Main Feed Regulator Valve control system.

The safety significance of the event is very low. Unit 1 was not affected and there were no adverse effects on the health and safety of the public.

On March 14, 2015 at approximately 04:29 AM Eastern Daylight Time (EDT), Vogtle Unit 2 was operating in Mode 1 at 100 percent power when the Loop 3 outboard Main Steam Isolation Valve (MSIV) spuriously closed. The sudden closure of the steam isolation valve caused a rapid pressure reduction in the remaining three Steam Generators (SGs) due to increased steam flow resulting in a Reactor Protection System (RPS) actuation due to rate compensated Low Main Steam Line Pressure Safety Injection and Steam Line Isolation. All control rods fully inserted and all equipment actuated as designed.

The unit was stabilized in Mode 3 with decay heat being removed through the atmospheric relief valves (ARVs) to the environment. The Loop 3 MSIV closure was due to failure of the hydraulic dump solenoid valve which resulted in a loss of hydraulic pressure to the MSIV.

This event had no adverse effect on the health and safety of the public, and is of very low safety significance. This event is reportable per 10 CFR 50.73(a)(2)(iv)(A) due to actuation of a system listed in 10CFR 50.739a)(2)(iv)(B). Unit 1 was unaffected.

NRC FORM 360 (02-2014)

Between January 16 and February 13, 2017, a power supply that supports operation of one of two ventilation supply fans for the 2A Emergency Diesel Generator (EDG) failed. Vogtle Electric Generating Plant (VEGP) Technical Specifications (TS), 3.8.3 Condition F requires restoration of the fan within 14 days or the EDG must be declared inoperable. This condition was not identified by operators because there is no failure indication. Therefore, the power supply was not repaired within the required time. The EDG should have been declared inoperable and TS 3.8.1. Condition B entered.

Subsequently the completion time for TS 3.8.1 Condition B expired and the unit should have been shut down. This action was not taken and Unit 2 operated in a condition prohibited by TS.

Between February 13 and February 22, 2017, the second power supply failed on this EDG resulting in the second ventilation supply fan being inoperable. Since no failure indication is available, this condition was not identified by the operators. The TS 3.8.3 action for two power supplies inoperable is to immediately declare the EDG inoperable.

Subsequently, the completion time expired and the unit operated in a condition prohibited by TS. During a monthly surveillance run on March 8, both power supplies were discovered failed. Both power supplies were replaced on March 9, 2017 and the EDG was declared operable.