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On May 3, 2016 Engineering personnel identified the potential past inoperability of Reactor Protection System Overtem. perature Delta T and Overpressure Delta T Channel III. Corrected coefficients were input to a Loop C resistance temperature detector (RTD) and resulted in a significant change to the setpoint.

Evaluation confirmed that the Channel III setpoint had exceeded the Technical Specification (TS) allowable

• value and was inoperable for approximately five days. Because the inoperable condition was not recognized at the time, the TS required actions were not taken. During the five-day period, an additional channel was inoperable and not tripped during test/adjustment activities for a cumulative period of approximately four hours. This resulted in a loss of the specified safety function during the four-hour period. The root cause is the absence of a controlled engineering document describing the derivation of RTD coefficient data.

Corrective actions: 1) Revise the RTD replacement procedure to require validation of the correct methodology for deriving RTD coefficients, and 2) Establish a controlled calculation that contains the basis and methodology for deriving RTD coefficients.

On September 3, 2014, the 4C Emergency Containment Cooler (ECC) fan was removed from service for breaker cubicle replacement. When the control wires were disconnected for the cubicle replacement, the auto-start feature of the 4A ECC fan was also lost. As a result, both ECC fans in the B Train were inoperable for a period exceeding the one hour Technical Specification (TS) allowed outage time (AOT). In addition, the 4A ECC fan was inoperable for a period exceeding the 72 hour TS AOT because the control wires were not re-terminated due to a latent design error caused by ineffective design verification. The impact of performing the breaker replacement on the operability of both ECC fans was not recognized in the work planning process due to a lack of understanding of the design details. In addition, the work order (WO) implementing the breaker cubicle replacement did not contain the correct plant mode restrictions specified in the design package. Corrective actions include: 1) The procedure for performing design verification was revised to require that engineers performing verifications must be qualified, 2) A Responsible Engineer (RE) will be assigned to all Approved and Active major modifications such that each RE understands the design details sufficient to provide implementation support, and 3) Revise the WO planning procedure to ensure that WOs do not alter/change design requirements and are consistent with specified plant restrictions in the design. Safety significance is minimal as margins in the safety analysis support ECC function.

APPROVED BY OMB: NO. 3150-0104 EXPIRES: 01/31/2017 80 hours.

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. 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, 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 October 31, 2005 at approximately 2227 hours, Unit 4 was in Mode.3 hot standby when the 240 kV switchyard protective relays actuated causing a loss of offsite power (LOOP) to the Unit 4 startup transformer.

Unit 3 was in Mode 1 at about 60% power at the time and was unaffected by the LOOP to Unit 4. As expected, the Auxiliary Feedwater System actuated, steam generator blowdown isolated and the emergency diesel generators started and loaded their respective electrical buses (4A and 4B). The 4C bus remained energized during the event. Natural circulation was established and decay heat removal was via atmospheric steam dump valves. The cause of this event is a failure to identify the extent of salt contamination due to hurricane Wilma on the 240 kV switchyard line insulators that resulted in untimely maintenance. The insulators were cleaned and the startup transformer was returned to service. Long term corrective actions include: 1) the line insulators will be incorporated into the System Performance Monitoring Program, 2) the switchyard insulators will be replaced with resistive glazed insulators with priority given to replacing the insulators associated with nuclear startup transformers, 3) a second remote contamination monitor (RCM) will be installed in the PTN switchyard, and 4) grid operations procedures will be revised to verify functionality of the RCMs and to perform swipe checks on the test insulator if an RCM is found defective or there is any other indication of abnormality. As all systems required to respond to the LOOP actuated as designed, the health and safety of the public and plant personnel were not affected.

On November 18, 2015 at approximately 23:33 hours with Unit 3 in Mode 5 during a refueling outage, the 3B Emergency Diesel Generator (EDG) automatically started and loaded on the 3B bus. The cause of the EDG start was a loss of offsite power to the 3A and 3B 4160V busses when the supply breakers to the Unit switchyard. When the 3A and 3B busses were deenergized, the 3B EDG re-energized the 3B bus, but the 3A sequencer was out of service for preplanned work so the 3A bus was not immediately reenergized. The unit remained in Mode 5 with core decay heat removal provided by the 3B Residual Heat Removal loop.

The cause of the event was the unexpected actuation of the protective relay during switchyard work.

The automatic EDG start is being reported pursuant to 10 CFR 50.73(a)(2)(iv)(A).

On July 20, 26, 27, 28 and August 7, 2014, Turkey Point Units 3 and 4 entered and exited the Action for Technical Specification (TS) 3.7.4, Ultimate Heat Sink, once each day for periods of up to 8 hours because the 100 degree F limit for ultimate heat sink (UHS) temperature was exceeded. The 12 hour requirement to be in Hot Standby was not exceeded during these events and so there was no condition prohibited by the TS.

On July 20, 2014, the NRC granted enforcement discretion (NOED No. 14-2-001) to allow the Turkey Point units to continue operation with UHS temperature up to 103 degrees F provided certain compensatory measures were implemented and termination criteria were met. License amendments were issued by the NRC on August 8, 2014, which increased the UHS temperature limit to 104 degrees F and terminated the NOED. Environmental conditions outside of management control negatively impacted UHS water quality (primarily an algae bloom) and the ability of the cooling canal system (CCS) to dissipate the heat rejected by plant operation. Corrective actions include biocide treatment of the CCS water, revision of the UHS temperature limit to 104 degrees F, and enhancement and integration of existing activities to improve the monitoring. of CCS capability to accomodate normal and accident plant heat loads. There were no safety

• consequences to plant or public safety as a result of these events.

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On March 19, 2014 with the Unit 3 reactor in Mode 5 at 0% power (Cold Shutdown), examination revealed evidence of leakage in the annulus between the outer surface of the Pressurizer heater sleeve and the lower head bore at heater penetration 11. Unit 3 was in Mode 5 in preparation for refueling. Non- destructive examination confirmed that there was no flaw in the heater sleeve indicating that the in-vessel attachment weld was the probable source of leakage. Because of the inability to characterize the flaw in the attachment weld, the most likely root cause is attributed to an original fabrication welding defect in the heater sleeve partial penetration weld further impacted by stress corrosion cracking and/or thermal fatigue.

Corrective action involved the installation of a half-nozzle ASME Code repair of heater sleeve 11, which relocated the reactor coolant system pressure boundary to the outside of the Pressurizer lower head at the heater sleeve penetration. Relief was authorized to leave the flaw in place for one operating cycle.

On June 7, 2013, with the Unit 3 reactor at 100% power, leakage at a threaded vent line connection on the 3A Component Cooling Water (CCW) pump casing was identified. A condition report and work request were initiated. By June 19, 2013, the leakage had increased from approximately 100 drops per minute to a steady stream and the pump was removed from service and isolated for repair. Examination of the 3/4 inch nipple removed from the pump casing revealed a through-wall flaw whose length exceeded structural integrity requirements. The pump was determined to be inoperable from intial observation of leakage on June 7. This 12 day period exceeded the allowed outage time permitted by the Technical Specifications and the attendant shutdown actions were not met. The cause of the fitting flaw is high cycle fatigue.

Corrective actions include: 1) Repair the threaded connection, and 2) Modify the design to increase margin. Safety significance is considered to be low because the other two CCW pumps were available and capable of being powered by independent power supplies. The CCW safety function is accomplished with one pump operating.

On March 13, 2013 at approximately 1120 with Unit 3 in Mode 3, the Auxiliary Feed Water (AFW) System actuated. Subsequently, at approximately 1131 operators initiated a manual reactor trip. Just prior to these events, one Condensate Pump (CP) and one Steam Generator Feed Pump (SGFP) were in operation, when a field operator started a second SGFP for a one minute run to vent the supply header and casing. The plant is designed to only allow a single SGFP to operate with a single CP operating. This condition resulted in automatic trip of the running SGFP and AFW actuation. Operators then secured the just-started SGFP. AFW injected cooler water into the SGs reducing reactor coolant system temperature.

Operators opened the reactor trip breakers via the manual reactor trip switch to obtain additional shut down margin, as a conservative measure. Operators started a Standby Steam Generator Feed Pump to maintain level in the SGs and secured both trains of AFW. The cause of the event is that licensed unit operators did not maintain adequate command and control of activities outside the control room allowing a decision to start the second SGFP to be made at the wrong organizational level. Corrective action will include implementation and assessment of the effectiveness of the improvement plan to reinforce operational standards.

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• - - On February 17, 2013, with the Unit 3 reactor in Mode 1 at approximately 99% power, the 3A ,eactor Coolant Pump (RCP) No. 1 seal leak-off became elevated and erratic. A unit shutdown was commenced on 'February 18, 2013 at approximately 0055 when seal leak-off increased to 5.5 gpm. At approximately 0130, the reactor was manually tripped at approximately 72% power when seal leak-off flow reached 6 gpm. The 3A RCP was then secured and No. 1 seal leak-off was isolated. The Auxiliary Feedwater (AFW) System actuated as designed based on low steam generator (SG) levels as a result of the reactor trip. At approximately 0316, AFW was secured with main feedwater supplying the SGs and decay heat removed via the atmospheric relief valves. There were two causes: 1) The seal runner o-ring was damaged during installation. 2) The RCP shaft shoulder critical criterion of 60% minimum mating surface area was not attained after manual machining (stoning). Corrective actions include replacing the 3A RCP seal, review of performance of other RCP seals at both Turkey Point units, and revision of the RCP maintenance procedure to provide additional guidance for proper seal installation and post-machining inspections.

On January 3, 2013, it was discovered that an incorrect meter was used to test two Pressurizer High Water Level reactor trip instrument channels. Technicians used an incorrect multimeter for a Channel I operational test and subsequently adjusted the setpoint prior to returning it to service. Technicians performed the same test on Channel II and when they saw that it was also displaying similar values, they stopped the surveillance and Channel II was placed in trip to comply with a TS Action. The result was that Channel I was inoperable and not tripped for approximately 30.5 hours. TS requirements were exceeded for Channel I being inoperable and not tripped greater than 6 hours (Action duration) and Channel II taken out of service during the same period, which placed the unit in TS 3.0.3. However, that condition was not recognized and the required actions were not completed. The direct cause of the event is procedure noncompliance. Corrective actions include procedure revisions for use of multimeters on the EAGLE 21 system, revision of the Maintenance and Test Equipment (M&TE) procedure to address the use of replacement M&TE, and measures to strengthen Maintenance Department procedure use and adherence.

Safety significance is considered low because Channel III remained operable and Channel II was subsequently determined to be functional, so that the safety function was not lost in the 2 out of 3 logic.

On 8/25/12, at approximately 1140, Turkey Point Unit 3 was in Mode 2. The Operations Department was performing the Main Turbine Valve Alignment, in preparation for turbine start-up following a refueling outage. During the alignment verification, Operations discovered the root isolation valves for the Turbine inlet pressure transmitters closed when they were required to be open. The Main Steam pressure transmitters, PT-3-446 and PT-3-447, provide input to various protection and control functions. Upon discovery of this condition, operators entered Technical Specification (TS) 3.0.3 for Unit 3 because the Minimum Channels Operable requirements of TS 3.3.2, Table 3.3-2, Functional Unit 1.f (Safety Injection, Steam Line flow - High coincident with SG pressure Low or Low Tavg) and TS 3.3.2, Table 3.3-2, Functional Unit 4.d (Steam Line Isolation) were not met. The isolation valves were then opened and TS 3.0.3 was exited at approximately 1239.

The cause was determined to be lack of rigor in ensuring a proper follow-up review of a modification, which added the new root isolation valves at the High Pressure Turbine inlet pressure tap locations.

At approximately 11:35 on March 6, 2011, a sodium spike was detected in the 3AS hotwell. Subsequently the 3A1 and 3A2 circulating water pumps (CWP) were stopped. A rapid power reduction was commenced after a second sodium spike was experienced, in accordance with plant procedures 3-ONOP-100, "Fast Load Reduction", to approximately 23% power. A manual reactor trip was initiated per procedure at 16:44 (EST).

Unit 3 was stabilized in Mode 3. All rods fully inserted and all safety systems functioned as required and there was no impact on the health and safety of the public. The NRC was notified of the event due to manual actuation of the Reactor Protection System (JC) (Event Number 46660) at approximately 19:38 (EST) on March 6, 2011.

The cause of the sodium intrusion event was due to a tube flaw near the tubesheet of tube (SG, COND) R305/T5 in the 3BS tube bundle. High cycle, low stress fatigue, and cold work induced residual stresses likely contributed to the event. Corrective actions involved plugging several tubes and applying an overcoat of Duromar after tube plugging. Eddy Current Testing was performed on a selected tube population. A combination of foam/dimple plug testing was performed. Several tubes in the 3AN and 3BS water boxes were plugged and coated. A root cause analysis was performed. Long term, the Unit 3 and Unit 4 condenser tube bundles will be replaced under the Extended Power Uprate Project.

On October 22, 2010, during the Unit 3 Cycle 25 Refueling Outage, containment liner plate degradation in the reactor pit area was detected during the ASME XI, IWE inspection. Augmented visual and ultrasonic examinations were performed. Thinning of the liner and twelve through wall holes (all in close proximity) were discovered. Design Features Technical Specification 5.2.1f requires a nominal thickness of the containment steel liner of 0.25 inches. This condition was reported to the NRC October 25, 2010 (Event number 46362) as a condition resulting in a serious degradation of the containment liner.

A liner plate section was replaced and inspected in accordance with the ASME Code. A root cause analysis was performed, including a metallurgical failure analysis. The root cause was determined to be failure of the coating system which was not designed for periodic immersion service. In order to prevent recurrence, the lower region of the reactor pit will have a coating system suitable for immersion applied. Previous boric acid inspections, ASME XI, subsection IWE, and Appendix J visual inspections did not detect this degradation. Actions have been identified to improve the liner inspection programs.

The root cause extent of condition analysis for this condition revealed that Unit 4 has had similar issues. A through wall hole about 1/16" in diameter was discovered November 25, 2006 in the Unit 4 reactor sump pit. The hole was evaluated as non-significant and repaired.

On February 26, 2008 at approximately 1309 hours, a momentary grid voltage disturbance occurred that caused a reactor trip of both Turkey Point Units 3 and 4 when both channels of safety-related 4 KV bus undervoltage relays for each unit actuated after a one second time delay. In addition, at approximately 1620, while shutting down the Unit 4 4A steam generator feed pump after transferring to standby feedwater, auxiliary feedwater (AFW) automatically actuated due to a red flag semaphore still present on the 4B SGFP control switch since the switch had not been taken to the stop position. This AFW actuation was inadvertent. The grid voltage disturbance occurred due to human error when a Protection and Control field engineer disabled both levels of local protection at an electrical substation which then failed to actuate when a fault occurred during equipment troubleshooting. The inadvertent AFW actuation occurred due to inadequate procedural guidance. Since plant response to the grid disturbance was as designed and AFW was not required to mitigate any plant condition at that time, the safety significance of the plant trips and inadvertent AFW actuation are minimal. Corrective actions relating to the grid disturbance include a new procedure setting requirements related to disabling protection.

Corrective action for the inadvertent AFW actuation entails future procedure changes to ensure the control switches for various components powered by the 4C 4 KV bus are placed in the appropriate position after a loss of power and to verify the control board switches are green flagged.