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On October 29, 2017, Unit 1 entered MODE 3 from MODE 4 without satisfying all of Technical Specification 3.7.5, Auxiliary Feedwater (AFW) Limiting Conditions for Operation (LCO) as required by LCO Applicability 3.0.4 for the Turbine Driven Auxiliary Feedwater (TDAFW) pump system.

LCO Applicability 3.0.4 does not permit entry into a MODE of applicability when an LCO is not met, unless the associated actions to be entered permit continued operation in the MODE for an unlimited time or after performance of an acceptable risk assessment and the appropriate risk management actions have been established. After entering MODE 3, it was discovered that components were not operable, contrary to LCO 3.0.4.

This event is being reported pursuant to 10 CFR 50.73(a)(2)(i)(B), for an operation or condition prohibited by Technical Specifications.

At 1724 (CDT) on 9/18/17 Door-061, South Control Room Door (DR) was inadvertently disabled. The door became wedged open against its backstop during control room ventilation testing. Door-061 is a barrier that functions to maintain the control room envelope (NA). The barrier was subsequently disengaged from the backstop allowing it to close. The door was inspected and returned to operable status at 1750 (CDT). While the door was stuck open, the control room was in an unanalyzed condition, a condition that could have prevented fulfillment of a safety function, and a common cause inoperability of independent trains or channels.

This event is being reported pursuant to 10 CFR 50.73(a)(2)(ii)(B), 10 CFR 50.73(a)(2)(v)(A), 10 CFR 50.73(a)(2)(v)(D), and 10 CFR 50.73(a)(2)(vii) for a degraded barrier that affected the control room envelope.

On April 1, 2016 the 345/13.8kV high voltage station auxiliary transformer (1X-03) tripped on a differential current relay (1-87A/X-03) actuation. Review of this event determined that there were three instances over the past three years when the required action completion time for not satisfying the Limiting Conditions For Operation of Technical Specification 3.8.1 (AC Sources - Operating) and 3.8.2 (AC Sources - Shutdown) would have been exceeded with the latent error present.

This event is being reported pursuant to 10 CFR 50.73(a)(2)(i)(B) for operation or condition prohibited by technical specifications.

At approximately 1730 on March 9, 2015 with both units at full power, it was discovered that the current limit feature of Battery Charger D-107 was not functioning as expected. Subsequent troubleshooting identified a defective crimp on a wire which was causing an intermittent open circuit that disabled the current limit function.

Evaluation determined that the capability to restore the battery charger to the DC electrical power subsystem to recover a discharged battery following a load shed of the charger may not have been able to be performed as designed. This condition may have resulted in an actual plant condition prohibited by Technical Specifications, Technical Specification 3.8.4. DC Sources-Operating.

No other plant systems were affected by this condition.

This event is being reported pursuant to 10 CFR 50.73(a)(2)(i)(B), Operation or Condition Prohibited by Technical Specifications.

On December 2, 2014, operators commenced a rapid power reduction of Unit 1 due to noted degradation of Unit 1B Condensate Pump. At 2050 on December 2, 2014, with Unit 1 in Mode 1 at 62% power, operators initiated a manual reactor trip of Unit 1 following securing of the Unit 1B Condensate Pump due to imminent failure. The Auxiliary Feedwater Pumps started as expected on low steam generator level experienced due to the reduced steam demand from the turbine trip in response to the reactor trip. All other plant systems functioned as required.

After the reactor trip, feedwater pump suction pressure remained low. The decision was made to secure both Main Steam Generator Feedwater Pumps. The Main Steam Generator Feedwater Pump A was manually secured. Prior to securing the Main Steam Generator Feedwater Pump B, it automatically tripped. All control rods fully inserted in the core due to the manual trip. There was no Emergency Core Cooling System actuation. Offsite power was maintained throughout the event. The Main Steam Generator Feedwater Pumps were available to be restarted due to the recovered feedwater suction pressure from the running Condensate Pump A.

This event is being reported pursuant to 10 CFR 50.73(a)(2)(iv)(A) for both the manual RPS actuation and also for the automatic initiation of Auxiliary Feedwater.

APPROVED BY OMB: NO. 3150-0104 EXPIRES: 01131/2017 Reported lessons learned are incorporated into the licensing process and fed back to industry.

Send comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. NuclearRegulatory Commission, Was hington, DC 20555-0001,or byinternet e-mail to Infocollects.Resource@nrc.gov, and to the Desk Officer, Office of Information and Regulatory Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information collection does not display 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.

On February 6, 2013 at 1132 CST, an undervoltage condition occurred on Unit 1, 1A-05 and 1A-06 safety-related buses, which was caused by a loss of 1X-03 high voltage station auxiliary transformer (HVSAT). The four emergency diesel generators (EDGs) started. The GO1 and G03 EDGs loaded onto buses 1A-05 and 1A-06. Unit 2 maintained offsite power throughout the event.

Unexpected operation of the 1F89-112 circuit switcher resulted in de-energization of the 1X-03 transformer causing a low voltage condition, which started the standby EDGs. The opening of the circuit switcher did not cause a lockout of 1X-03. As a result, the automatic transfer to the redundant offsite power supply In the switchyard was not initiated, and G01 and G03 EDGs automatically loaded onto Unit 1 safety-related buses 1A-05 and 1A-06, once they had reached operating voltage and frequency.

This event is being reported pursuant to 10 CFR 50.73(a)(2)(iv)(A), any event or condition that resulted in a manual Dr automatic actuation of any of the systems listed in 10 CFR 50.73(a)(2)(iv)(B), including any event or condition that results in the actuation of the emergency AC electrical power system.

On June 6, 2011, while Unit 1 was in MODE 1 and Unit 2 was in MODE 4, the feeder breaker to safeguards 480V bus, 2B-04, opened on overcurrent.

The feeder breaker tripped on overload after energizing a pressurizer heater group. This trip resulted in de- energizing electrical bus 2B-04. No other breakers tripped during this event. The results of an investigation determined the overload trip was improperly set low.

A technical assessment for reportability was completed. Nextera Energy Point Beach, LLC (NextEra) determined that electrical bus 2B-04 was inoperable for specific time periods from March 23, 2011 through June 7, 2011 for Unit 1 and Unit 2. Technical Specification Limiting Conditions for Operation (LCOs) and associated Action Conditions (TSACs) for TS 3.8.9 Distribution System - Operating (TSAC 3.8.9 A and B), TS 3.8.10 Distribution Systems - Shutdown (TSAC 3.8.10 A), and TS 3.5.3 ECCS - Shutdown (TSAC 3.5.3 A and B) were not met during specific time periods. Therefore, pursuant to 10 CFR 50.73(a)(2)(i)(B), the event is reportable as a condition prohibited by Technical Specifications. This event is also being reported pursuant to 10 CFR 50.73(a)(2)(v)(D), any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident.

The feeder breaker overload trip setting was corrected.

On 11/27/2011 at 0226 CDT, an undervoltage condition occurred on Unit 1, 1A-05 and 1A-06 safety-related buses during the restoration of 1X-03 high voltage station auxiliary transformer (HVSAT). The four emergency diesels (EDGs) started. The G-01 and G-03 EDGs loaded onto buses 1A-05 and 1A-06. Offsite power remained available to Unit 2 throughout the event via an alternate path.

During switchyard realignment of the 1X03 HVSAT, the 1F89-112 circuit switcher failed. This resulted in a low voltage condition which started the standby EDGs. The fault did not cause a lockout of 1X03, the associated switchyard component. As a result, the automatic transfer to the redundant offsite power supply in the switchyard was not initiated, and GO1 and G03 automatically loaded onto Unit 1 safety system buses 1A05 and 1A06 once the diesels had reached operating voltage and frequency.

The safety significance of this event was low because at the time of the event Unit 1 was in MODE 5, and shutdown cooling capability was maintained via the steam generators. Following the event, station procedures were revised to check local circuit switcher indicators for proper configuration prior to and following operation.

This event is being reported pursuant to 10 CFR 50.73(a)(2)(iv)(A), any event or condition that resulted in a manual or automatic actuation of any of the systems listed in 10 CFR 50.73(a)(2)(iv)(B) including any event or condition that results in the actuation of the emergency AC electrical power system.

On February 27, 2011, at 2159 CST, during the testing of the A train safety injection (SI) system (BQ), it was discovered that the oiler for the Unit 2, B train SI pump, had rotated and the oil had drained out. The B train SI pump was declared inoperable. At the time of the event, the A train of SI was out of service for performance of a routine inservice test. Because both trains of SI were inoperable, LCO 3.0.3 was entered. Upon completion of the A train inservice test, Unit 2 exited LCO 3.0.3 at 2211 CST.

Immediate corrective actions taken included restoring the oiler to the vertical position, refilling it and performing a 5-minute pump run. The root cause of the event was determined to be a 1995 modification to the SI pump oiler which introduced a latent design/configuration flaw. Additional corrective actions will include a design change to the SI pumps and oiler assemblies for both units to reduce the possibility of accidental misalignments. The actions are being tracked to completion in the corrective action program.

An 8-hour ENS report was made in accordance with 10 CFR 50.72(b)(3)(v)(D) on February 28, 2011 at 0345 CST.

On January 15, 2008, at 1404 Central Standard Time, Point Beach Nuclear Plant (PBNP) experienced a loss of transformer 1X04, low voltage station auxiliary transformer for Unit 1. The loss of 1X04 resulted in the declaration of an Unusual Event, SU1, "Loss of All Offsite Power to Essential Busses for GREATER THAN 15 Minutes.

The Unusual Event was reported on EN# 43907 in accordance with 10 CFR 50.72(a)(1)(i), "The declaration of any of the Emergency Classes specified in the licensee's approved Emergency Plan," 10 CFR 50.72(b)(2)(xi), "News Release or Notification of Other Government Agency," 10 CFR 50.72(b)(2)(i), "Plant Shutdown Required by Technical Specifications.

Technical Specification (TS) 3.8.1 Action Condition B, "Associated unit's 13.8/4.16 kV transformer inoperable," was entered at 1404 on January 15, 2008. This Condition has a Completion Time of 24 hours to return the transformer to operable status. At 1404, January 16, 2008 the Completion Time was not met and Unit 1 entered TS 3.8.1 Action Condition H with a Required Action to be in MODE 3 in 6 hours and MODE 5 in 36 hours. Unit 1 shutdown commenced at 1549 and Unit 1 was in MODE 3 at 1948, January 16, 2008.