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Start date | Reporting criterion | Event description | |
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05000251/LER-2017-001 | 10 September 2017 7 November 2017 | 10 CFR 50.73(a)(2)(iv)(A), System Actuation | 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. |
05000251/LER-2016-001 | 3 May 2016 | 10 CFR 50.73(a)(2)(v)(A), Loss of Safety Function - Shutdown the Reactor 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications | 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. |
05000251/LER-2015-002 | 12 May 2015 | 10 CFR 50.73(a)(2)(iv)(A), System Actuation | 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, Automatic Auxiliary Feedwater System Actuation during a Planned Reactor Trip | 30 November 2014 | 10 CFR 50.73(a)(2)(iv)(A), System Actuation | |
05000251/LER-2015-001 | 30 November 2014 | 10 CFR 50.73(a)(2)(iv)(A), System Actuation | 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-2014-003 | 3 September 2014 | 10 CFR 50.73(a)(2)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications | 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. |
05000251/LER-2014-002 | 25 May 2014 | 10 CFR 50.73(a)(2)(iv)(A), System Actuation | 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 | 25 April 2014 | 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications | 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. |
05000251/LER-2010-006 | 10 CFR 50.73(a)(2)(iv)(A), System Actuation | On September 21, 2010, at approximately 2017, with Turkey Point Unit 4 operating at 100% power, an unplanned automatic reactor trip occurred while the quarterly surveillance for the Channel II High Pressurizer Pressure Protection Loop (P-4-456) was in progress. The cause of the trip was attributed to Channel I spurious trip signal of the High Pressurizer Pressure Protection Loop (P-4-455) coincident with Channel II being already tripped due to the surveillance procedure. All rods fully inserted and all systems responded as designed and the unit was stabilized in Mode 3. At 2228, a report (EN#46265) was made to the NRC per 10 CFR 50.72(b)(2)(iv)(B) for actuation of Reactor Protection System with the reactor critical and per 10 CFR 50.72(b)(3)(iv)(A) for actuation of the Auxiliary Feedwater System.EExcessive separation found in the electrical bifurcated pins of the ELCO connectors of the NUS instrument Comparator (PC-4-455A) module caused the Channel I spurious trip signal. Corrective actions include replacement of Comparator PC-4-455A, providing formal training for Maintenance personnel to properly inspect NUS modules with ELCO connectors, adding quantitative criteria in site procedures to perform connector inspection, and inspecting other NUS module connectors installed at the plant that could have electrical pins with excessive separation. �NRC FORM 366A U.S. NUCLEAR REGULATORY COMMISSION | |
05000251/LER-2010-002 | 11 January 2010 | 10 CFR 50.73(a)(2)(iv)(A), System Actuation | 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. |
05000251/LER-2008-002 | 10 CFR 50.73(a)(2)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications | Safety Injection (SI) cold leg injection isolation valve 4-867 to Unit 4 was discovered out of position (locked closed) on May 5, 2008 at approximately 1237 hours and placed in its correct position, locked open and backseated at approximately 1307. Valve 4-867 is required to be locked open and backseated when reactor coolant system (RCS) temperature is greater than 380 degrees F. The valve was out if its required position for approximately five hours 26 minutes, from 0741 on May 5, 2008 when RCS temperature was above 380 degrees F until the valve was repositioned at 1307. The SI System was inoperable during this time. The cause of the event is that current component alignment processes used to restore systems during outages do not contain the rigor and control necessary to maintain the proper physical configuration of the plant. Corrective actions include 1) procedure revisions to ensure mitigating system flow path verification surveillances are included, can not be waived during refueling outages and are completed prior to Shift Manager hold points, and 2) determination of safety significant systems that cannot be waived and are required to have a valve alignment performed prior to Mode changes when returning from a refueling outage. Safety significance is low due to the short period of time the valve was closed when required to be open and low decay heat levels coming out of an outage. | |
05000251/LER-2005-005 | 10 CFR 50.73(a)(2)(iv)(A), System Actuation | 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. | |
05000251/LER-2004-003 | 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications | The outboard bearing oiler for high head safety injection (HHSI) pump 4B was found empty on August 3, 2004. Subsequent investigation determined that the previously identified minor outboard bearing oil leak experienced a step change in leak rate rendering the pump inoperable on or about June 6, 2004. Therefore, the 4B HHSI pump was unavailable for 60 days due to the oil leak, which exceeds the Technical Specification allowed outage time of 30 days. Any one of the three remaining HHSI pumps was capable of performing the intended HHSI safety function. The cause of the oil leak was due to human performance deficiencies during the last pump overhaul assembly of the bearing housing. A contributing cause was insufficient guidance in the maintenance procedure for bearing housing work. Plant procedures have been revised to provide additional guidance in performing HHSI pump bearing maintenance. All other plant safety-related pumps have been inspected to ensure that no other similar oil leakage conditions exist. Oil addition program enhancements and trend plan development guidance for oil leak monitoring have been developed under the corrective action program to address generic implications. It was concluded that the health and safety of the public were not affected by this event. | |
05000251/LER-1986-020, Forwards LER 86-020-01.Rept Submitted as LER 86-21 on 861027 W/Ltr L-86-442.Event Should Have Been Reported as LER 86-20. Rev Corrects Numbering Discrepancy & Coding Errors | 31 October 1986 | ||
05000251/LER-1983-003, Forwards LER 83-003/01T-0 | 2 May 1983 | ||
05000251/LER-1983-001, Forwards LER 83-001/01T-0 | 14 April 1983 | ||
05000251/LER-1982-014, Forwards LER 82-014/03L-0 | 1 November 1982 | ||
05000251/LER-1982-013, Forwards LER 82-013/03L-0 | 1 October 1982 | ||
05000251/LER-1982-011, Forwards LER 82-011/03L-0 | 8 September 1982 | ||
05000251/LER-1982-010, Forwards LER 82-010/03L-0 | 12 August 1982 | ||
05000251/LER-1982-009, Forwards LER 82-009/03L-0 | 23 July 1982 | ||
05000251/LER-1982-008, Forwards LER 82-008/03L-0 | 28 June 1982 | ||
05000251/LER-1982-007, Forwards LER 82-007/01T-0 | 7 June 1982 | ||
05000251/LER-1982-006, Forwards LER 82-006/01T-0 | 24 May 1982 | ||
05000251/LER-1982-002, Forwards LER 82-002/01T-0 | 31 March 1982 | ||
05000251/LER-1981-014, Forwards LER 81-014/02T-0 | 7 December 1981 | ||
05000250/LER-2021-004, Cancelation of LER 2021-004, Through-Wall Leakage from Core Exit Thermocouple Tubing | 28 March 2022 | ||
05000250/LER-2017-001 | 18 March 2017 16 May 2017 | 10 CFR 50.73(a)(2)(iv)(A), System Actuation 10 CFR 50.73(a)(2)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident 10 CFR 50.73(a)(2)(v), Loss of Safety Function 10 CFR 50.73(a)(2)(i)(A), Completion of TS Shutdown | 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. |
05000250/LER-2016-001 | 7 April 2016 | 10 CFR 50.73(a)(2)(v)(D), Loss of Safety Function - Mitigate the Consequences of an Accident 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications | On February 8, 2016 at approximately 0147 hours, during a surveillance test, control room indications identified that 3B Emergency Containment Cooler (ECC) fan tripped. Troubleshooting found the control power fuse for the fan's power supply breaker was loose in its fuse holder. Investigation revealed that the fuse holder clips had been widened during work activities associated with the installation of the new breaker during the prior Unit 3 refueling and maintenance outage. The most probable cause of the loose fuse was improper insertion. The installation procedure did not validate fuse holder gap, fuse alignment, and fuse tightness after its last removal and insertion prior to placing the new breaker in service. Inadequate contact during the surveillance test caused the fan trip. The 3B ECC would not have reliably met its safety function mission time and so was determined to be inoperable for approximately 72 days exceeding the 72 hour Technical Specification allowed outage time. In addition, on several occasions during the 72-day period one of the other two ECCs was inoperable concurrently for testing. Corrective actions include: 1) The fuse holder clips were adjusted to provide a tight fit. 2) A review determined additional similar breakers will be inspected for fuse tightness. 3) Future installation and preventive maintenance of similar breakers will check for fuse tightness and correct if necessary. Safety significance is considered low based on a risk assessment showing - Incremental Conditional Core Damage Probability and Incremental Conditional Large Early Release Probability are below the NRC acceptance criteria for minimal risk impact. |
05000250/LER-2015-001 | 18 November 2015 19 January 2016 | 10 CFR 50.73(a)(2)(iv)(A), System Actuation | 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). |
05000250/LER-2014-005 | 11 August 2014 | 10 CFR 50.73(a)(2)(iv)(A), System Actuation | 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 | 20 July 2014 | 10 CFR 50.73(a)(2)(v)(B), Loss of Safety Function - Remove Residual Heat | 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
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05000250/LER-2014-003 | 23 April 2014 | 10 CFR 50.73(a)(2)(iv)(A), System Actuation | On April 23, 2014 at approximately 1302 hours, Unit 3 entered Technical Specification (TS) 3.1.3.3 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 3.1.3.3. 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 | 19 March 2014 | 10 CFR 50.73(a)(2)(ii)(A), Seriously Degraded | 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 | 3 January 2014 | 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications | 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 June 2013 | 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications | 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 | 10 May 2013 | 10 CFR 50.73(a)(2)(iv)(A), System Actuation | 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 March 2013 | 10 CFR 50.73(a)(2)(iv)(A), System Actuation | 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-2013-004 | 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications | On February 27, 2013 at approximately 1750, with Unit 3 in Mode 5 power was restored to Reactor Coolant System hot leg injection isolation valve MOV-3-866A in preparation for inservice testing (IST). On February 28, 2013 commencing at approximately 0047 normally closed MOV-3-866A and MOV-3- 866B (parallel injection valves) were individually stroked for IST during which Pressurizer level increases were noted. Investigation revealed that recently installed remote manual valve 3-990 was not closed due to failure of a connection in the reach rod assembly. The remote operator had been used to close the valve and local verification was not employed. Valve 3-990 was being relied on for safety injection flow path isolation during the IST. MOV-3-866A and MOV-3-866B were verified closed with power removed at approximately 0230. Flow path isolation did not meet Technical Specification requirements for longer than the allowed four hours. Causes of this event include: 1) Reach rod universal joint connection failed as a result of failure to complete final installation steps at that location, and 2) The 3-990 valve was not verified to be closed locally. Corrective actions include: 1) Revising Operations procedures to provide additional guidance to verify reach rod valve operation, and 2) Establishing a means to better control work in the field that ensures critical installation steps are verified complete. | |
05000250/LER-2013-003 | 18 February 2013 | 10 CFR 50.73(a)(2)(iv)(A), System Actuation | t
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05000250/LER-2013-002 | 11 February 2013 | 10 CFR 50.73(a)(2)(iv)(A), System Actuation | 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 | 3 January 2013 | 10 CFR 50.73(a)(2)(vii), Common Cause Inoperability 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications | 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 | 6 September 2012 | 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications | 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 | 25 August 2012 | 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications | 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-2011-002 | 11 August 2011 | 10 CFR 50.73(a)(2)(v)(B), Loss of Safety Function - Remove Residual Heat | 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-2011-001 | 6 March 2011 | 10 CFR 50.73(a)(2)(iv)(A), System Actuation | 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-2010-006 | 10 CFR 50.73(a)(2)(iv)(A), System Actuation | With Unit 3 at 100% power, at approximately 0604 on November 15, 2010, the reactor was manually tripped when the 3A2 Circulating Water Pump was stopped due to an overheated packing gland. The manual trip was in anticipation of an automatic turbine/reactor trip on low condenser vacuum. While Auxiliary Feedwater automatically actuated, a train of normal feedwater remained available to feed the steam generators. During the reactor trip, the 3B Steam Dump to Atmosphere valve opened automatically, as designed, but failed to close on operator demand as required by procedure. It was locally isolated with a manual isolation valve stopping the cooldown. The reactor coolant system (RCS) temperature was stabilized at 487°F and borated as required by procedure. The RCS returned to normal operating temperature and pressure and the unit was stabilized in Mode 3. Two root causes were identified: 1) There were inadequate administrative controls for pump packing consolidation for applicable non-nuclear safety (NNS) related pumps, and 2) A healthy skepticism and recognition of risk was not adequately considered or communicated. Corrective actions include: 1) Incorporate information on packing consolidation break-in period, system perturbation information, temperature bands, and minimum/maximum levels for packing leak-off for NNS pumps into the post maintenance testing procedure, 2) implement plan for Recommendation 1 of SOER 10-2: Engaged, Thinking Organizations, 3) inspect Unit 3 and 4 pumps that utilize packing, 4) replace 3A2 CWP pump shaft packing and packing follower, and 5) repair 3B Steam Dump to Atmosphere valve. | |
05000250/LER-2010-005 | 5 February 2010 | 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications 10 CFR 50.73(a)(2)(ii)(A), Seriously Degraded | 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. |
05000250/LER-2008-004 | 27 August 2008 | 10 CFR 50.73(a)(2)(i)(B), Prohibited by Technical Specifications | 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 | 26 February 2008 | 10 CFR 50.73(a)(2)(iv)(A), System Actuation | 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. |