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| Report date | Site | Event description | |
|---|---|---|---|
| 05000327/LER-2016-001 | 11 April 2016 | Sequoyah | On February 9, 2016, at 1415 Eastern Standard Time, Sequoyah Nuclear Plant (SQN) Unit 1 experienced a Low Steam Line Pressure Safety Injection (SI) signal. At the time of the event, Operations was warming the main steam (MS) line downstream of the main steam isolations valves (MSIV) via the Loop 2 MSIV bypass valve. During this controlled evolution, a sudden drop in MS line pressure occurred that actuated the two-out-of-three logic as sensed on all three Loop 2 steam line pressure bi-stables. All safety systems responded as designed and the SI was terminated per procedure. Prior to the event, Unit 1 was recovering from a forced outage involving a Main Generator Blower repair that began on December 26, 2016. Unit 1 was maintained in Mode 3 during this time. The most probable cause of the SI actuation was determined to be water accumulation in MS Loop 2 upstream of the MSIV as a result of steam condensation not being drained during the extended Mode 3 forced outage. Troubleshooting was initiated and Unit 1 was placed in Mode 4 to facilitate draining of Loop 2 and 3 MS lines. Corrective actions include actions to address operating for extended periods of time in Mode 4 and above with MSIVs closed. |
| 05000327/LER-2015-004 | 9 March 2016 | Sequoyah | On November 23, 2015, at 0844 Eastern Standard Time, Sequoyah Nuclear Plant (SQN) Unit 1 reactor was manually tripped due to plant parameters indicating that the Loop 3 Main Steam Isolation Valve (MSIV) had started drifting in the closed direction. Prior to the reactor trip, the open light indication on the main control board for the Loop 3 MSIV was noted to be extinguished. The light bulb was replaced with no change in indication. At the same time, the Post Accident Monitoring panel indicator for the Loop 3 MSIV displayed full open; however, within two to three minutes, the panel provided dual indication. Subsequently, Operators noted that the reactor coolant system temperature and Loop 3 Steam Generator (SG) pressure were both rising, and the Loop 3 SG flow was lowering. These indications confirmed the Loop 3 MSIV was drifting closed. Following the reactor trip, all plant safety systems operated as designed, all control rods fully inserted, and auxiliary feedwater automatically initiated from the feedwater isolation signal, as expected. Troubleshooting identified a loose termination associated with the Loop 3 MSIV handswitch that would result in a slow loss of air pressure and cause the MSIV to slowly drift in the closed direction. The direct cause was determined to be a loose electrical connection on the MSIV handswitch. The root cause was determined to be inadequate work practices during replacement of the MSIV handswitch in 1994 that resulted in the loose electrical connection. The corrective action to prevent recurrence is revision of the work control planning procedure to ensure specific connection fastener torque values are utilized during work order planning. SQN Unit 2 was unaffected by this event. |
| 05000328/LER-2015-002 | 6 January 2016 | Sequoyah F | On November 10, 2015, at 1502 Eastern Standard Time (EST), two cold weather suits were inadvertently dropped into the equipment pit portion of the Sequoyah Nuclear Plant Unit 2 reactor cavity, resulting in two containment recirculation drains being declared inoperable. Technical Specification (TS) Limiting Condition for Operation (LCO) 3.6.15, "Containment Recirculation Drains," and TS LCO 3.0.3 were entered. The first suit was removed from the equipment pit at 1553 EST. At that time, only one of the drains remained inoperable and LCO 3.0.3 was exited. The remaining suit was removed from the equipment pit at 1556 EST, and LCO 3.6.15 was exited. Plant conditions were restored to normal within the allowed LCO times and no plant shutdown was required. The two cold weather suits in the Unit 2 reactor cavity area created the potential for obstructing the flow path for containment recirculation adversely affecting the safety function of the Containment Spray and Emergency Core Cooling Systems that are needed to mitigate the consequences of a design basis accident. The effect of this condition resulted in an unanalyzed condition that significantly degraded plant safety. The apparent cause was failure of the Maintenance personnel to identify and mitigate potential hazards and risks during the pre-job briefs, 2-minute rule, and walk downs. Corrective action includes addition of risk mitigation strategies to the containment access control procedure. Unit 1 was unaffected by this event. |
| 05000327/LER-2015-003 | 13 November 2015 | Sequoyah | On September 14, 2015, at 0426 Eastern Daylight Time, Sequoyah Nuclear Plant (SQN) Unit 1 reactor was manually tripped due to a loss of power to the Vital Instrument. Power Board (VIPB) 1-11. Prior to the reactor trip, operators were in the process of realigning Vital Inverter 1-II for planned maintenance. During this evolution, VIPB 1-11 became de-energized. Operators entered Abnormal Operating Procedure AOP-P.03, "Loss of Unit 1 Vital Instrument Power Board" which required a manual reactor trip. Following the reactor trip, operators restored power to VIPB 1-Il with the normal supply at 0550. All plant safety systems responded as designed, all control rods fully inserted, and auxiliary feedwater automatically initiated from the feedwater isolation signal as expected. It was determined that an Alternating Current (AC) output switch failed causing the loss of power to the VIPB 1-11. The direct cause of the switch failure was due to increased friction of bearing surfaces caused by lack of appropriate lubrication. The lack of lubrication was related to a failure to implement a corrective action following an operating experience review at SQN in 2000 of a' similar event at McGuire Nuclear Station. The failure to implement a corrective action was determined to be the root cause of this event. Corrective actions to prevent recurrence include ensuring the existing requirement for management review of all corrective action closures remains in the Corrective Action Program. Unit 2 was unaffected by this event. |
| 05000327/LER-2015-002 | 22 September 2015 | Sequoyah | On July 24, 2015, at 1351 Eastern Daylight Time (EDT), Sequoyah Nuclear Plant (SQN) Unit 1 reactor automatically tripped following a turbine trip due to actuation of the generator backup relay. The relay actuation was a result of voltage variations on the main generator. A malfunctioning base adjuster follower card was was connected to the grid and ascending in power. On July 27, 2015, at 1040 EDT SQN Unit 1 reactor was at 82 percent power when it automatically tripped following a turbine trip due to actuation of the generator backup relay. An improperly terminated wire was found in the voltage regulator logic drawer which caused high resistance. Prior to restart, the wire was properly connected. Following each of the reactor trips, all safety related equipment operated as designed, all control rods fully inserted as required, and auxiliary feedwater automatically initiated from the feedwater isolation signal as expected. The cause of each of the reactor trips was determined to be inadequate standards for multi-wire terminations and verification at the time of the original improper wire termination event in the mid-1990s. Corrective actions to prevent recurrence include adding guidance for multi-wire terminations to Modifications and Additions Instruction M&AI-7.1, Cable Terminations and Repairing Damaged Cables. The condition described in this LER did not have an impact on |
| 05000327/LER-2015-001 | 11 May 2015 | Sequoyah | On March 11, 2015, at 0621 Eastern Daylight Time Sequoyah Nuclear Plant Unit 1 reactor automatically tripped due to a Negative Rate Trip as a result of Control Bank D Control Rod H-8 dropping into the core. Initial investigation revealed Control Rod H-8 dropped into the core approximately one second before the reactor trip. The dropped control rod caused a rapid decrease in power which was sensed by all four nuclear instrumentation system power range channels. Reactor trip logic is two out of four channels. No power changes or control rod motion were in progress prior to the reactor trip. All safety related equipment operated as designed, all control rods fully inserted as required, and auxiliary feedwater automatically initiated as expected. Unit 1 was stabilized in hot standby following the automatic reactor trip. The cause of the reactor trip was due to Control Rod H-8 failing to maintain its commanded position. Trouble shooting was performed on the electrical components associated with Control Rod H-8. The direct cause was a compressed four- pronged pin inside a connector for the control rod drive mechanism (CRDM) circuit. The root cause was failure of a maintenance procedure to provide inspection guidance and acceptance criteria on CRDM vertical panel connections. The corrective action to prevent recurrence includes revising the maintenance procedure and periodic preventive maintenance of CRDM connections. Unit 2 was unaffected by this event. |
| 05000328/LER-2015-001 | 1 May 2015 | Sequoyah | On March 2, 2015, at 0645 Eastern Standard Time, Sequoyah Nuclear Plant (SQN) Unit 2 reactor automatically tripped following a turbine trip due to actuation of the main generator 287G differential relay. The relay actuation was a result of a failure of the main generator C-phase neutral current transformer (CT) cable. All safety related equipment operated as designed, all control rods fully inserted as required, and auxiliary feedwater automatically initiated from the feedwater isolation signal as expected. A broken splice connection was identified between the 287G differential relay and the C- phase CT. This main generator C-phase neutral CT cable failed open due to a combination of corrosion and periodic physical manipulation. The cause of this event was a lack of inspections in the preventive maintenance (PM) procedure to identify potential failure mechanisms. Prior to restart, both Unit 2 C- phase neutral CTs and one B-phase neutral CT along with all associated neutral side field cables were replaced. Corrective actions to prevent recurrence include replacement of all Unit 1 and Unit 2 main generator CT bolted connections with solder filled splices, covered in Raychem to prevent water intrusion. The condition described in this LER did not have an impact to SQN Unit 1. |
| 05000328/LER-2014-001 | 25 June 2014 | Sequoyah | On April 29, 2014, during the performance of 0-SO-30-3, "Containment Purge System Operation," the two containment purge air exhaust radiation monitors were discovered aligned to train A containment purge. From April 8 to April 28, 2014, train B containment purge was operated three times with the radiation monitors aligned to train A purge. These radiation monitors provide containment ventilation isolation (CVI) signals upon a high radiation condition to mitigate the release of radioactivity from inside containment. With the radiation monitors not aligned to the train of containment purge exhaust being operated, the ability to signal a CVI from the containment purge exhaust monitors was lost. However, during the time frame the purge monitors were misaligned, alternate automatic and manual means of performing a CVI were available. The cause of this event was operators failing to perform verbatim procedure compliance when ensuring the containment purge radiation monitor alignment prior to placing containment purge in service. Corrective actions include reinforcement of management expectations for procedure use and adherence with shift managers and crew operators. |
| 05000327/LER-2013-004 | 27 March 2014 | Sequoyah | Between October 21-28, 2013, workers breached SQN Unit 1 containment penetration X-108 several times during fuel movement while performing plant maintenance. Technical Specification 3.9.4, Containment Building Penetrations, requires that containment building penetrations providing direct access from the containment atmosphere to the outside atmosphere shall be closed during fuel movement. Workers were not aware that use of X-108 penetration was not allowed during movement of irradiated fuel. On October 27, 2013, a Senior Reactor Operator identified penetration X-108, affecting the auxiliary building secondary containment enclosure (ABSCE), was breached without required compensatory measures. The penetration manual valves were subsequently closed and secured. The root cause is ineffective procedures for controlling containment penetration breaches during Modes 5 and 6. A governing procedure will be developed and implemented for controlling breaches of the shield building, ABSCE, control room boundaries, and design basis flood barriers. ... |
| 05000327/LER-2014-001 | 26 March 2014 | Sequoyah | On December 19, 2013, an initial license operator trainee discovered a lack of procedural guidance to perform Technical Specification (TS) Surveillance Requirement (SR) 4.7.3 b, which requires Unit 1 safety injection signal (SIS) start testing for the common spare component cooling system (C-S CCS) (CC) pump. Specifically, procedure, 1-SI-OPS-082-026.B, did not verify an SIS would start the C-S CCS pump and supply the Unit 1 B train header. All other SIS configurations for starting the C-S CCS pumps were previously accounted for and verified. Initially, SQN classified the condition as a missed surveillance, as the intended aspects of SR 4.7.3 b were not satisfied. Operations invoked TS 4.0.3 to allow testing in accordance with a missed surveillance and a risk evaluation was performed. A procedure change was implemented to provide for testing SIS start of the C-S CCS pump with both units on-line. The test was performed satisfactorily and SR 4.7.3 b requirements were met. The SQN investigation revealed the omission of the C-S CCS pump from the SIS testing dated back to the development of the initial plant surveillance documents. With no record of the SR 4.7.3 b ever being satisfied for the Unit 1 B train, the condition was re-classified as a never performed surveillance on January 30, 2014. 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 (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 current y valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection. |
| 05000327/LER-2013-003 | 21 October 2013 | Sequoyah | On August 8,2013, position indication for emergency core cooling system (ECCS) A-Train residual heat removal (RHR) Containment Sump Isolation Valve was found showing the valve to be in mid-position. The valve was verified to be in a closed position. On August 14, ECCS valve testing was conducted. Testing identified the 1A RHR Pump Suction Valve failed to close when requested. Operations personnel declared the valve inoperable and remained in the applicable LCO's. Maintenance troubleshooting determined that multiple grounds existed in the control circuits of each of the valves. Water was found in the motor limit-switch housing control circuit of the RHR Containment Sump Isolation Valve. The cause of the condition was that the conduit penetrations for RHR Containment Sump Isolation Valve were not designed to account for groundwater infiltration through the plant concrete structures resulting in leakage into the conduit. Actions are being taken to redesign the conduit penetrations for each Unit's RHR Containment Sump Isolation Valves, to ensure the penetrations are sealed and/or water tight to prevent water from entering the motor operator valve operator associated with each valve. |
| 05000327/LER-2013-002 | 29 April 2013 | Sequoyah | On February 26, 2013, it was determined the Sequoyah Unit 1 auxiliary feedwater (AFW) flow indicators in the auxiliary control room (ACR) had been inoperable from February 8, 2013, until February 16, 2013. The AFW flow indicators in the ACR normally indicate zero. WA was unable to identify evidence of when exactly they failed. Operators noticed that an Essential Raw Cooling Water indicator failed on February 8, 2013. During troubleshooting on February 15, 2013, it was discovered that two fuses in the circuit cleared. These fuses supply power to instrument loops including power to the AFW flow indicators. When these fuses are blown, power is lost to the flow modifiers that provide indication. The AFW flow indicators are fed from the same power supply that feeds two other instrument loops. A flow modifier that drives a plant computer data point failed resulting in the blown fuses. The fuses and flow modifier were replaced and the indicators were returned to operable status. Based on the review of the data, it was determined the AFW flow indicators had been out of service longer than allowed by Technical Specification 3.3.3.5. |
| 05000328/LER-2013-001 | 25 April 2013 | Sequoyah | On February 24, 2013, at 1205 Eastern Standard Time, Operations personnel manually tripped the Sequoyah Unit 2 reactor from approximately 19 percent rated thermal power on imminent loss of condenser hotwell level. Specifically, Operations personnel entered an abnormal operating procedure based on indications of rising condenser pressure. When Operations personnel determined the hotwell level in "B" Condenser could not be maintained, a manual reactor trip was initiated. Prior to the manual reactor trip, the Unit 2 reactor had been at approximately 24 percent power with the main turbine offline for maintenance activities. All control rods fully inserted as required. The auxiliary feedwater system automatically initiated and provided feed water to the steam generators. No complications were experienced during or after the reactor trip. The loss of condenser vacuum indication was caused by the pressure indicator's drain line breaking under cyclic fatigue. It is suspected that initial damage to the drain line was caused during the previous refueling outage. The drain line was replaced prior to restart of the unit. Corrective actions will be performed to provide shielding of the condenser pressure transmitters' drain line, and the surrounding area will be marked as a unit trip hazard. Employees are to receive a briefing regarding the requirement for providing adequate spacing between stored items and sensitive equipment. |
| 05000327/LER-2013-001 | 8 April 2013 | Sequoyah | On July 28, 2009, the Tennessee Valley Authority (TVA) identified latent design input inconsistencies in hydrological computer modeling used for probable maximum flood (PMF) calculations. The root causes of the condition were an organizational behavior which allowed the latent input inconsistencies to go undetected and management failure to provide oversight of the impact of river system changes on the calculated value of the PMF. The corrective actions to prevent recurrence are to procedurally require a Flood Protection Program, develop formal Flood Protection Program Management Implementing Procedure(s) and Design Standards/Guides, create a formal documented risk management process for all engineering products, formalize the elements of engineering technical rigor, and implement an upper tier integrated risk management process. Upon discovery, TVA implemented both immediate and interim corrective actions to ensure the Fort Loudoun, Cherokee, Tellico and Watts Bar dams would not overtop during an assumed PMF event. |
| 05000327/LER-2011-001 | 15 April 2011 | Sequoyah | On February 15, 2011, at 0705 Eastern Standard Time (EST), Sequoyah Nuclear Plant (SQN) Unit 1 and 2 entered Technical Specification Limiting Condition for Operation (LCO) 3.0.3 due to both trains of control room air conditioning systems inoperable. LCO 3.0.3 was entered because "B" train Main Control Room (MCR) chiller failed and "A" train MCR chiller was tagged out of service for scheduled maintenance. Actions were expedited to return both trains of MCR chillers to service. At 1005 EST on February 15, 2011, the "A" train MCR chiller was returned to operable status and LCO 3.0.3 was exited on both units. An investigation discovered that the "B" train MCR chiller failed because of a ruptured air supply line in a temperature transmitter on the chiller control circuit. The cause was determined to be an inadequate preventative maintenance procedure. The inoperability of both trains of control room air conditioning systems is reportable as a condition which was prohibited by Technical Specifications in accordance with 10 CFR 50.73(a)(2)(i)(B). In addition, this condition is reportable as a condition that could have prevented the fulfillment of the safety function per 10 CFR 50.73(a)(2)(v)(D). |
| 05000327/LER-2009-002 | 10 April 2009 | Sequoyah | On November 6, 2008, NRC verbally informed SQN that the lower containment atmosphere gaseous radioactivity monitors were considered inoperable. SQN subsequently declared the lower containment atmosphere gaseous radioactivity monitor channels inoperable and complied with the associated technical specification (TS) actions of Limiting Condition for Operation 3.4.6.1. On November 12, 2008, SQN submitted a license amendment request (LAR) to remove the lower containment atmosphere gaseous radioactivity monitor channels from the SQN TSs. NRC approved the SQN LAR on December 4, 2008. On February 11, 2009, NRC documented a violation of Units 1 and 2 TS 3.4.6.1, "Leakage Detection Instrumentation," for the SQN failure to maintain the gaseous lower containment atmosphere radioactivity monitors of the reactor coolant system (RCS) leakage detection instrumentation operable. NRC concluded that the Unit 1 and 2 monitors had been inoperable since June 1987 as a result of not being able to perform their safety function of detecting a RCS pressure boundary leak of 1 gallon per minute in one hour because of improvements in reactor fuel quality. In addition, NRC exercised enforcement discretion and did not issue enforcement action for this violation in accordance with Enforcement Guidance Memorandum 09-001, "Dispositioning Violations of NRC Requirements for Operability of Gaseous Monitors for Reactor Coolant System Leakage Detection. N■V |
| 05000328/LER-2008-001 | 19 December 2008 | Sequoyah | On November 3, 2008, at 2322 Eastern standard time with Unit 2 operating at 100 percent power, a manual reactor trip was initiated because of a partial loss of main feedwater flow to the steam generator Loop 4. The immediate cause was failure of the Loop 4 feedwater regulating valve controller. During normal power operations, operators received a steam generator level high-low deviation annunciation. An operator identified a decreasing level on the steam generator Loop 4. The controller was placed to manual, but the controller failed to respond to the operator's attempt to increase level. Operators took action to manually trip the reactor. Following the reactor trip, an RCS leak occurred. The leak was from an instrumentation sensing line to the pressurizer. The plant systems responded as designed. The K1 Relay to the Unit 2 Loop 4 main feedwater regulating valve flow indicating controller has been determined as the most probable root cause of this event. The relay failure is attributed to a failing contact connection, which resulted in a slow closing drift of the main feedwater regulating valve. ,- - |
| 05000328/LER-2008-002 | 19 December 2008 | Sequoyah | On November 9, 2008, at 1821 Eastern standard time with Unit 2 in Mode 3, the Unit 2 reactor trip breakers were opened from the main control room (MCR) because of indications of Shutdown Bank "A" Rod E-11 dropping into the reactor core. At the time the reactor trip breakers were opened, the MCR operators were in the process of withdrawing shutdown banks in preparations for entry into Mode 2. Rod E-11 rod position indication (RPI) dropped to zero and the rod bottom light was lit. The MCR operators entered the appropriate abnormal operating procedure and opened the reactor trip breakers based on indications that were available. All other shutdown banks and control banks were inserted at the time the reactor trip breakers were opened. All safety-related equipment operated as designed. Subsequent to the manual reactor trip, investigation revealed that the plant computer trace for Rod E-11 showed that the failure was in the RPI system and was not a dropped rod. Further investigation showed that the problem was a broken wire on the E-11 RPI coil stack on top of the reactor head. The unit was cooled down to Mode 5 to repair the broken RPI coil stack wire for Rod E-11. The corrective action to prevent recurrence will be a modification to the reactor head to provide a new RPI coil stack top plate, connector, and cable to the vertical panel. ,- - |
| 05000327/LER-2008-001 | 4 March 2008 | Sequoyah | On January 16, 2008, at 1925 Eastern standard time, the Unit 1 reactor was manually tripped as a result of a low steam generator level on Loop 3. Maintenance personnel were performing a transmitter calibration on a Loop 3 steam generator pressure transmitter. During performance of the calibration, Maintenance personnel made an incorrect assumption that a place-keeping aid placed in the procedure was intended to be the procedure start point when in fact they should have started two pages previous to the place-keeping aid location. The two missed pages resulted in Operations not being notified to remove the channel being tested as a controlling channel. This resulted in performing testing on the pressure transmitter on a controlling channel, causing closure of the Loop 3 main feedwater regulating valve. Operations placed the feedwater regulating valve in manual to open the valve. However, before steam generator water level began to increase, the pre-established low steam generator level trigger-point was reached and the operating crew initiated a manual reactor trip. The cause was determined to be a failure to follow procedure because of personnel not performing proper place keeping during performance of a calibration procedure. Corrective actions include establishing and proceduralizing standard place- keeping requirements, strengthening and proceduralizing standard pre-job brief requirements, and training on these standard requirements. |
| 05000327/LER-2004-002 | 27 December 2004 | Sequoyah | On November 11, 2004, it was determined that there was a failure to comply with Technical Specification (TS) 3.9.1. TS 3.9.1 requires immediately initiating boration of the RCS after it is determined that the reactor coolant system (RCS) boron concentration is below TS limits. TVA personnel reviewed Operations logs and determined that compliance with TS had not been performed as required. On October 28, 2004, at approximately 0418 Eastern daylight time (EDT), Chemistry personnel notified Operations personnel that the Unit 1 RCS boron concentration had been at 1999 parts per million (ppm) as early as 0010. Operations personnel entered TS Limiting Condition for Operation (LCO) 3.9.1 action because the RCS boron concentration was below the TS limit of 2000 ppm. Operations personnel immediately initiated boration of Unit 1 RCS. This event is being reported as an operation prohibited by TS since the TS requires immediately suspending all operations involving core alterations or positive reactivity changes and initiate and continue boration at greater than or equal to 35 gallons per minute (gpm). Operations did not initiate boration of the RCS earlier because Chemistry personnel did not inform Operations of the out-of-limits condition. Chemistry personnel were unaware that Unit 1 had entered Mode 6 at 2357 on October 27, thus requiring a minimum RCS boron concentration of 2000 ppm. The cause of the event was failure to establish adequate margin to the RCS boron concentration limit prior to entering Mode 6. The personnel involved in the transition to Mode 6 were counseled on establishing adequate margins, anticipating changes in plant conditions and adequately communicating within and between departments; and appropriate procedures are being revised to provide provisions for requiring a margin to the 2000 ppm limit. |