|Report date||Site||Event description|
|05000251/LER-2017-001||7 November 2017||Turkey Point|
On September 10, 2017 at approximately 1855 hours, the Turkey Point Unit 4 reactor was manually tripped from 88% power due to lowering level in Steam Generator (SG) C. The reactor was stabilized in Mode 3.
Auxiliary Feed Water actuated as expected on low level in SG C and was secured at approximately 1933 hours. At the time of the event, the Turkey Point site was experiencing high winds with rain associated with Hurricane Irma. The B and C Main Feedwater Regulating Valves (MFRV) had been in manual control when the C MFRV failed closed. The cause of the event was a degraded signal due to water intrusion into the C MFRV valve positioner hand selector switch enclosure resulting from a less than adequate design and installation. Corrective actions include modifications to the Unit 3 and 4 MFRV hand selector switch enclosures and enclosure penetrations, and repair of a failed component associated with the 4C MFRV. Additionally, the terminal/pull box specifications will be revised to improve direction for installation activities. Safety significance is very low because the unit responded as designed to the trip.
|05000250/LER-2017-001||16 May 2017||Turkey Point||On March 18, 2017 at approximately 1107 hours, the Turkey Point Unit 3 reactor tripped from 100% power as a result of an electrical fault on the 3A 4kV vital bus. The Auxiliary Feed Water System actuated as expected, and the 3A Emergency Diesel Generator started but did not load, as designed, due to the lockout of the 3A 4kV bus. The 3A 4kV bus remained de-energized and the reactor was stabilized in Mode 3. Both Unit 4 High Head Safety Injection (HHSI) pumps were out of service for maintenance. The 3A HHSI pump was unable to be powered from the 3A 4kV bus resulting in a loss of the Safety Injection safety function for approximately 2.5 hours on both Units 3 and 4. The safety function is achieved by operation of two of the four pumps which are shared by both units. The loss of the 3A 4kV bus was caused by an electrical fault created by a conductive foreign material that had entered the current-limiting reactor cubicle that bridged an air gap between an uninsulated bus bar and the cubicle wall. The foreign material was a carbon fiber mesh used to reinforce a Thermo-Lag installation taking place in the 3A 4kV switchgear room. Corrective actions include: 1) The Thermo-Lag installation procedure will be revised to incorporate additional precautions for handling Thermo-Lag materials, and 2) the Engineering product risk and consequence assessment process will be revised to ensure a review is conducted of Safety Data Sheets for material being considered in the design. This event had no effect on the health and safety of the public.|
|05000251/LER-2016-001||30 June 2016||Turkey Point|
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
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.
|05000250/LER-2015-001||19 January 2016||Turkey Point|
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).
|05000251/LER-2015-002||13 July 2015||Turkey Point||On May 12, 2015 at approximately 0430 hours with Unit 4 at approximately 80% rated thermal power, an automatic reactor trip occurred in response to a turbine trip. The turbine trip was caused by a generator differential lockout that opened the generator output breaker. During the reactor trip response, the Auxiliary Feedwater System automatically initiated as expected. The unit was subsequently stabilized in Mode 3. All systems responded correctly to the trip. The direct cause of the event was an open circuit caused by a loose connection at a main generator current transformer (CT). The root cause was that the vendor recommended torque value for a stud lugged connection was not used during the engineering change (EC) and work order planning process. The tightening requirement for this type of connection is considered to be skill of the craft; therefore, no torque specification was listed in the EC or work instructions. Corrective action includes: 1) The preventive maintenance procedure and electrical specification will be revised to include connection torque requirements per the vendor work instruction manual for the type of terminal used in the and 4 main generator CT connections.|
|05000251/LER-2015-001||29 January 2015||Turkey Point|
On November 30, 2014, at approximately 1354 the Unit 4 reactor was manually tripped as a pre-planned evolution to facilitate the repair of an unidentified steam leak in the High Pressure (HP) Turbine. While Unit 4 was in Mode 3, at approximately 1358 hours, the Auxiliary Feedwater System initiated when the 4C Steam Generator (SG) level reached the low-low SG level setpoint setting. The AFW system was restored to standby alignment at approximately 1454 hours. The causal analysis determined that: 1) The appropriate operating margin to prevent AFW actuation was not established prior to the reactor trip for the planned shutdown, and 2) The just-in-time training did not prepare crews to reduce the probability of having an unnecessary AFW actuation on a planned reactor trip. Corrective actions include: 1) Change the applicable operating procedures to establish available margin to avoid unnecessary AFW actuation during a planned reactor trip, and 2) Develop simulator scenarios that more closely model the plant response during a planned shutdown and train Operators to reduce the probability of an AFW actuation during a planned reactor trip.
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. 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-1 0202, (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.
|05000251/LER-2015-001, Automatic Auxiliary Feedwater System Actuation during a Planned Reactor Trip||29 January 2015||Turkey Point|
|05000251/LER-2014-003||10 November 2014||Turkey Point|
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.
|05000250/LER-2014-005||10 October 2014||Turkey Point||On August 11, 2014 at approximately 1028 hours with Unit 3 at approximately 100% reactor power, a manual reactor trip was initiated in response to a loss of instrument air (IA). The Auxiliary Feedwater System automatically initiated as designed. The unit was subsequently stabilized in Mode 3 with IA restored. An automatic safety injection (SI) actuation occurred as a result of main steamline high differential pressure. High head safety injection (HHSI) pumps, residual heat removal (RHR) pumps, and emergency diesel generators (EDG) automatically started as designed due to the SI signal. Based on plant conditions, the HHSI and RHR pumps did not inject into the reactor coolant system. The running compressor was unloaded inadvertantly at approximately 1020 hours and the standby compressors started but did not load due to a latent design error in the start logic. Although the standby compressors were restarted and loaded by approximately 1029 hours, IA decreased below the pressure required for the reactor trip. The SI actuation was caused by inadequate control of primary plant parameters during a loss of IA to containment. Corrective actions include: Removing an unneeded permissive in the standby compressor control logic which prevented the compressor from loading, and revising the loss of IA procedure to provide additional guidance on control of pressurizer level and pressure when IA is lost.|
|05000250/LER-2014-004||18 September 2014||Turkey Point|
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
|05000251/LER-2014-002||24 July 2014||Turkey Point|
On May 25, 2014, with Unit 4 at approximately 20% reactor power during a shutdown to repair an unrelated equipment issue, an automatic reactor trip occurred due to low condenser vacuum. The transfer of steam supply to the gland sealing steam system from the Unit 4 main steam system to the Unit 3 auxiliary steam system while the unit was on-line caused the decrease in main condenser vacuum. Main condenser vacuum reached the turbine trip setpoint, which resulted in the automatic reactor trip. Trip response was uncomplicated.
The root cause was operations personnel did not adequately address the integrated system status as part of the decision making process used to realign the steam supply to the gland sealing steam system. Corrective actions include: 1) Revising procedural guidance to specify that steam supply to the gland sealing steam system cannot be transferred from the main steam system to the auxiliary steam system with a unit in Mode 1 or 2, and 2) Providing training to all licensed operators to demonstrate the integrated system response aspect of risk-based decision making.
APPROVED BY OMB: NO. 3150-0104 EXPIRES: 01/31/2017 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 (1-5 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.
|05000251/LER-2014-001||24 June 2014||Turkey Point||On April 25, 2014, it was identified that three feedwater flow transmitters were incorrectly calibrated during the Unit 4 startup in April 2013. The transmitters' zero calibration point had been shifted to the high end of the calibration tolerance as provided in the setpoint methodology. The impact of the calibration was to shift the actuation point of the Steam/Feedwater flow mismatch reactor trip beyond that specified in Technical Specifications (TS). The condition existed longer than allowed by the TS with the required actions not taken. An extent of condition review identified a similar condition existed on one Unit 3 feedwater flow transmitter following that unit's startup in August 2012. The causes are that the Engineering Technical Response Memorandum (ETRM now ETR) form has a missing barrier to provide defense-in-depth to prevent inappropriate usage, and lack of technical rigor and knowledge regarding the design basis impact of the flow transmitter calibration change. Corrective actions include: 1) Revise fleet procedure and form for ETRs to specifically state restrictions for which ETRs cannot be used, and 2) provide training to appropriate Engineering personnel regarding proper scope and usage of ETRs, and scaling and channel uncertainties used to define the design and licensing basis for the reactor protection system and engineered safety feature actuation system instrumentation.|
|05000250/LER-2014-003||18 June 2014||Turkey Point||On April 23, 2014 at approximately 1302 hours, Unit 3 entered Technical Specification (TS) 18.104.22.168 Action as a result of the Shutdown Bank B Group 1 step counter failing to increment. The reactor was subcritical in Mode 3 progressing to reactor startup. The reactor trip breakers were opened as required by the Action of TS 22.214.171.124. The TS requires that the reactor trip breakers be opened if the group step counter demand position indicator (group 1 and group 2) are not within ± 2 steps of each other. All rods fully inserted. The unit remained in Mode 3. This was a manual actuation of the Reactor Protection System. Therefore, an 8- hour report (EN# 50054) was made in accordance with 10 CFR 50.72(b)(3)(iv) to the NRC Operations Center. The cause of the event was a supervisory data logging card not fully seated in the circuit card rack because of insufficient instruction in a functional test procedure. The supervisory data logging card was re- seated and the testing sequence continued successfully. A revision to the procedure will require a visual inspection and independent verification to verify proper engagement of the printed circuit cards.|
|05000250/LER-2014-002||15 May 2014||Turkey Point|
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.
|05000250/LER-2014-001||4 March 2014||Turkey Point||On January 3, 2014 with the Unit 3 reactor in Mode 1 at 100% power, the instrument channel associated with Main Steam Line Pressure Transmitter PT-3-495 was found outside procedural acceptance criteria due to PT drift. PT-3-495 was replaced, calibrated successfully, and returned to service on January 4, 2014. Subsequent review determined the instrument channel was inoperable from March 9, 2013 to January 3, 2014. During the period of inoperability, the allowed outage time of 6 hours was exceeded without taking the required action to place the channel in the tripped condition and the shutdown actions of Technical Specification (TS) 3.0.3 were not entered. This event is reportable in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by the TS. The root cause is attributed to a deviation from the normal process of using a dedicated work order (WO) to satisfy surveillance requirements. As result, Instrumentation and Control supervision failed to validate WO activities credited for satisfying TS requirements. As corrective action, the surveillance tracking program procedure will be revised to state that an independent verification is to be performed and documented prior to approval that a surveillance test has been completed when crediting non-dedicated WOs. An extent of condition review was also performed. Safety significance remained low during the period the instrument channel was inoperable because both redundant channels remained available.|
|05000250/LER-2013-008||19 August 2013||Turkey Point|
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.
|05000250/LER-2013-007||8 July 2013||Turkey Point|
On May 10, 2013, Unit 3 reactor was manually tripped in response to a sudden loss of turbine load at approximately 25% reactor power. Plant power was being reduced during a controlled shutdown for planned maintenance. The operating crew observed generator megawatts suddenly reduced to zero, with no operator action. The crew manually tripped the reactor. All systems responded as expected, except for source range nuclear instrument N-3-32 which experienced a loss of detector voltage.
The root cause was determined to be an incorrect deadband pressure value of the Load Drop Anticipatory (LDA) circuit in the turbine control system.
Corrective actions included reducing the dead band of the LDA pressure arming setpoint and adding indicator lights to the turbine control system display to identify armed status.
|05000250/LER-2013-006||13 May 2013||Turkey Point|
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.
|05000250/LER-2013-003||19 April 2013||Turkey Point|
|05000250/LER-2013-002||11 April 2013||Turkey Point|
On February 11, 2013, a turbine gland sealing steam spillover valve was being bypassed in preparation for calibration of the actuator. Opening the bypass valve created a flow path for gland steam to the condenser, which caused a reduction in gland sealing steam pressure and decrease in main condenser vacuum. Main condenser vacuum reached the turbine trip setpoint, which caused an automatic reactor trip. The Auxiliary Feedwater (AFW) System actuated automatically due to low steam generator (SG) levels following the reactor trip. Recovery from the reactor trip was uncomplicated. AFW was secured and main feedwater was used for SG water level control. Decay heat removal was to atmosphere via the steam dump valves.
The root cause was determined to be ineffective implementation of the operational standards as demonstrated by: 1) improper monitoring of plant parameters during the manipulation of the spillover bypass valve, and 2) utilizing an equipment clearance order in lieu of an operating procedure when bypassing the gland seal spillover valve. Corrective actions include: 1) Revise procedural guidance for bypassing spillover valves, and 2) Implement an improvement plan to reinforce operational standards.
|05000250/LER-2013-001||1 March 2013||Turkey Point|
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.
|05000250/LER-2012-004||5 November 2012||Turkey Point||On September 6, 2012 at approximately 2300, the indication associated with feedwater flow transmitter FT 3-476, (JB:FT) was noted to be reading lower than expected. After further assessment, on September 7, 2012 at approximately 0540 the associated Reactor Protection System channel was declared inoperable, and at approximately 0837 the channel was placed in the tripped condition. Troubleshooting determined the high and low side process tubing for the differential pressure transmitter was reversed. The tubing was repaired and FT-3-476 was returned to service at approximately 1100 on September 7, 2012. The tubing reversal occurred when it was replaced during the recent refueling outage. The causes of this event are: The work order task description (WOTD) specified "Skill-of-the-Craft", leading to a failure to use or ineffective use of human error prevention tools, and the post maintenance test did not provide for a positive method of tubing orientation verification after replacement. Corrective actions include addition of rule-based instructions in the WOTD. The event is reportable because FT-3-476 was inoperable for a time greater than allowed by Technical Specifications and the required actions were not taken. Because redundant and diverse reactor trip instrumentation was available, the safety significance is very low.|
|05000250/LER-2012-003||24 October 2012||Turkey Point|
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.
|05000250/LER-2011-001||27 October 2011||Turkey Point|
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.
|05000250/LER-2011-002||10 October 2011||Turkey Point|
On August 11, 2011 with Unit 3 at 100% power, Intake Cooling Water (ICW) System valve 3-50-406 (manually operated butterfly valve) failed in the closed position. Failure of this valve isolated the discharge flow path of ICW from the Component Cooling Water heat exchangers for approximately 28 minutes. During this period there was a loss of ICW function (communication with ultimate heat sink).
The root cause of the event was inadequate evaluation of a configuration change in 2005 resulting in the creation of a single failure vulnerability. A contributing cause was station personnel failed to adequately risk rank a known condition resulting in low corrective maintenance prioritization. The valve failure mechanism was cyclic fatigue due to valve flutter from worn actuator parts. The fluttering condition was known from about 2001. Corrective actions include: 1) An alternate discharge flow path was opened on both units; 2) the actuator of valve 3-50-406 was repaired; 3) revision of the procedure for procedure control to require Engineering review of procedure revisions that change plant configuration; 4) revise the system and program health reporting procedure to require validation of risk ranking for all work orders; 5) review open green and white work orders to validate current risk ranking; and, 6) revise and implement Engineering and Operations initial and continuing training programs regarding butterfly valve failure modes and effects of these valves failing closed. The total conditional core damage probability is 5.6E-08 for this event, well below the NRC threshold of 1E-06 for additional inspections.
|05000250/LER-2010-005||22 December 2010||Turkey Point|
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.
|05000251/LER-2010-002||11 March 2010||Turkey Point||On January 11, 2010, at approximately 1058 an unplanned manual reactor trip on Unit 4 was initiated due to Steam Generator (SG) level being greater than 75%. The unit was stabilized in Mode 3 on off- site power with main feed for decay heat removal. The unit trip was precipitated by the manual stop of the 4A SG feedwater pump (SGFP) due to a degrading oil inventory. Plant response to the loss of the 4A SGFP and the subsequent reactor trip was as expected. The root cause of the loss of the 4P1A SGFP lube oil level was determined to be unresponsive seal water injection controls to the pump outboard bearings which resulted in inadequate seal water injection flow to the 4P1A SGFP outboard seal coincident with SGFP bearing cavity drain blockage. Corrective actions include: 1) Replace obsolete Unit 3 and 4 SGFP seal water hand controller stations with more responsive controller stations. 2) A preventive maintenance activity will be established to verify the bearing seal cavity drains are clear on a periodic basis, after completion of maintenance and prior to SGFP start following an outage.|
|05000250/LER-2008-004||23 October 2008||Turkey Point|
On August 27, 2008, during the design of a control switch modification, Engineering personnel identified a voltage drop concern with the Unit 3 3B Emergency Containment Filter (ECF) control circuit. The ECF fans are required to automatically start upon a loss of coolant accident (LOCA) signal.
Two of three ECF fans are required to accomplish the safety function. Calculations show that the voltage is not adequate to pickup the 3B ECF starter coil for a LOCA start signal at the minimum allowable post trip switchyard voltage. The 3B ECF was declared inoperable on August 27, 2008. The apparent cause for the 3B ECF being declared inoperable is a latent design error. An interposing relay was installed within the control circuit and the 3B ECF was declared operable on August 30, 2008. The control circuit length for starting the 3B ECF from the control switch is within the allowable length, therefore, the 3B ECF would have been able to be started manually in a low voltage situation. The ECF system does not play a role in the prevention of a core damage accident and the conditional containment failure probability given a LOCA or steam line break is very low, reducing significantly the risk importance of the ECF system function of removing radioactive gases and particulates from the containment.
|05000250/LER-2008-001||25 April 2008||Turkey Point|
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.
|05000250/LER-2005-004||12 August 2005||Turkey Point||On May 19, 2005, the Unit 3 3A Emergency Containment Filter (ECF) fan failed to start during a scheduled surveillance test due to a blown control circuit fuse. A replacement fuse of the same type and size also blew during a subsequent start of the 3A ECF fan. It was determined that the fuse type was marginal for the application and that similar fuses were installed on two additional ECF units, 3B ECF on Unit 3 and 4C ECF on Unit 4. Three ECFs are provided in each reactor containment building to remove radioactive iodine so that offsite radiation dose is maintained within regulatory guideline values during a maximum hypothetical accident (MHA). There was a potential for two of three Unit 3 ECFs not starting if needed to mitigate an MHA with concurrent degraded voltage conditions. Using best estimate methods, analysis showed a minimal increase in offsite thyroid dose while control room thyroid dose remained within regulatory guideline values. The apparent cause for ECF 3A starter control circuit fuse opening is insufficient margin in the fuse design to ensure that the ECFs will start reliably given variations in voltage, fuse tolerances and/or starter coil inrush currents. ATM-3 and KTK-3 fuses were replaced with time delay fuses in ECF 3A, 3B and 4C motor starter circuits. Since no actual event occurred which relied on the ECFs to perform their safety function and since potential consequences increased but did not exceed regulatory limits, the health and safety of the public and plant personnel were not affected by the ECF marginal fuse application.|
|05000250/LER-2004-003||7 December 2004||Turkey Point|
During a Unit 3 clearance review, a single failure vulnerability was identified in the dousing function of the Emergency Containment Filters (ECF). The loss of power to certain power panel breakers could inadvertently douse all three ECFs for Unit 3. A similar condition applies to Unit 4. Three ECFs are provided in each reactor containment building to remove radioactive iodine so that offsite radiation dose is maintained within regulatory guideline values during a maximum hypothetical accident. The ECF system is required to perform its safety related function of radioiodine removal, assuming a single active failure. The impact of the reduced capability of the doused ECF charcoal adsorbers to remove methyl iodide is an increase in offsite and control room dose to the thyroid. The increase in control room dose is greater than the increase in offsite dose; however, a realistic dose evaluation shows that the regulatory guideline value would not be exceeded in either case. The cause of the design deficiency is human error both in the original redesign of the dousing initiation system and in subsequent reviews of the single failure vulnerability. A modification to correct the design deficiency has been performed for both Units 3 and 4. Since no actual event occurred which relied on the ECFs to perform their safety function nor would the degraded performance of the ECFs result in doses above regulatory limits, it was concluded that the health and safety of the public were not affected by the ECF design deficiency.
|05000250/LER-2003-004||25 April 2003||Turkey Point|
On February 27, 2003, Turkey Point Unit 3 was in Mode 1 and holding at approximately 60 percent reactor power while performing Technical Specification surveillance testing of the Main Steam Safety Valves setpoints. T Three Main Steam Safety Valves lifted outside the Technical Specification limits of +/- 3% due to micro-bonding between the valve and the disc. T In each case, the unit entered then exited the applicable Technical Specification 126.96.36.199.b Action Statement as the valves were removed from service, then returned to service within the Technical Specification allowed outage time of 4 hours.
A fourth Main Steam Safety Valve lifted outside the Technical Specification Limit due to a misalignment of the valve yoke rod and nut and could not be returned to service.
The plant entered the Action Statement for Technical Specification 188.8.131.52.b and reactor power was reduced below 53 percent.
During the planned unit refueling shutdown which commenced on March 1, 2003, all four valves were disassembled, repaired, and returned to service prior to unit restart.
Operation of the facility with the Main Steam Safety Valves as-found settings was within analytical bounds; therefore, this event had no impact on the health and safety of the public.