|Report date||Site||Event description|
|05000455/LER-2016-001||15 February 2017||Byron|
On October 12, 2016 at 1338 hours, Byron Station Operations initiated a manual reactor trip of Unit 2 due to decreasing water levels in the loop B and loop C Steam Generators. A trip of a bus feed breaker resulted in the loss of power feed to multiple normally energized relays associated with the Feedwater (FW) Water Hammer Prevention System (WHPS) circuit, which resulted in automatic closure of related Feedwater Isolation Valves.
The apparent cause of the feed breaker trip was due to a manufacturing defect on the feed breaker amptector circuit board.
The corrective actions planned include revising refurbishment testing requirements for the main feed breaker and performing modifications in subsequent refuel outages to the FW Water Hammer Prevention System to address power supply single point vulnerability.
The Unit 2 Reactor Protection System was actuated by the manual reactor trip and the Auxiliary Feedwater system actuated automatically as expected. This condition is reportable in accordance with 10 CFR 50.73(a)(2)(iv)(A) for any event or condition that resulted in manual or automatic actuation of any of the systems listed in 10 CFR 50.73(a)(2)(iv)(B).
|05000454/LER-2015-006||30 November 2015||Byron|
On October 1, 2015 at 0906, while in Mode 3, Byron Station determined that Unit 1 was in a condition that could have prevented fulfillment of the turbine trip safety function. Electrical leads had been lifted to disable the turbine trip function on both Solid State Protection System (SSPS) trains while Unit 1 was in Mode 5 to support Instrument Maintenance calibrations on turbine generator throttle valves and governor valves. These leads were not re- installed prior to Mode 3 entry, which occurred at 0059 on October 1, 2015. From the time Mode 3 was entered, Byron Unit 1 was not in compliance with Byron technical specification (TS) 3.3.2, "ESFAS Instrumentation," Condition G.
This event is being reported under 10 CFR 50.73(a)(2)(v)(D) for any event or condition that could have prevented the fulfillment of a safety function to mitigate the consequences of an accident, and under 10 CFR 50.73(a)(2)(i)(B) for any operation or condition which was prohibited by the plant's technical specifications.
This LER is being submitted in follow-up to ENS 51436 made on October 1, 2015.
The cause of the event was the Exceptions Checklist, 1BGP 100-1T3, " Mode 4 to 3 Checklist," utilized for mode changes, lacks the appropriate rigor to ensure exceptions are resolved and challenged prior to removal from the list.
|05000454/LER-2015-005||17 November 2015||Byron|
On September 18, 2015 at 2000 hours, during the Byron Station fall 2015 Unit 1 refueling outage (B1R20), in-service liquid penetration (PT) examinations were performed on the previously repaired control rod drive mechanisms (CRDMs) at penetrations 31 and 43. During the examination of the repair for CRDM penetration 31, one 9/32 inch rounded indication and one 0.010 inch linear indication were documented, exceeding the acceptance criteria of dimensions greater than 3/16 inch for rounded indications and linear indications of any size. The linear indication was repaired with buffing only, while the rounded indication was repaired using both buffing and welding.
There were no rejectable indications found on penetration 43. This LER is being submitted in follow-up to ENS 51410 made on September 18, 2015.
The cause of these flaws is attributed to existing weld discontinuities and minor subsurface voids opening to the surface or enlarging due to thermal and/or pressure stresses during plant operation.
This event is being reported under 10CFR50.73(a)(2)(ii)(A) for any event or condition that results in the condition of the nuclear power plant, including its principal safety barriers being seriously degraded.
|05000454/LER-2015-004||19 October 2015||Byron|
On August 20, 2015 at 1755 hours, a design deficiency associated with pressurizer power operated relief valve (PORV) block valve control circuitry was confirmed in which a design basis fire in the main control room (MCR) or cable spreading rooms (CSR) could prevent the credited fire safe shutdown action (i.e., locally close pressurizer PORV block valve) mitigating a spurious pressurizer PORV opening.
On September 2, 2015, during an extent of condition review, an additional design deficiency was confirmed in which credited fire safe shutdown action (i.e., removing 125 Vdc control power fuses) mitigating a spurious opening of the pressurizer PORVs during design basis fire does not adequately mitigate design basis fire induced hot short.
The causes of these design deficiencies are legacy design errors made during original construction.
Corrective actions include plant configuration changes correcting the specific design deficiencies.
This condition is being reported in accordance with 10 CFR 50.73(a)(2)(ii)(B) for any event or condition that results in the nuclear power plant being in an unanalyzed condition that significantly degrades plant safety.
|05000454/LER-2015-003||27 August 2015||Byron|
On November 20, 2014 at 1248 hours, the Byron Station Main Control Room (MCR) received an alarm identifying that fuel oil level was low on one of two Diesel Oil Storage Tanks (DOSTs) associated with the Unit 1, B-train (1B) Emergency Diesel Generator (DG). At 1328 hours, the MCR received an alarm identifying level was also low in the second DOST associated with the 1B DG. Operators determined that the low level condition was due to leakage to the Unit 1, A-train (1A) fuel oil storage system through one of two 1A DOST inlet valves. The Corrective Action Program investigation identified that leakage initially occurred during the 1B DG monthly surveillance conducted on October 22, 2014.
Subsequent analysis concluded that the loss of inventory from the 1B DOSTs to the 1A DOSTs would result in the 1B DG not meeting its design mission time without operator intervention.
This event is reportable in accordance with 10 CFR 50.73(a)(2)(i)(B) for an operation or condition prohibited by Technical Specifications.
The cause of the event was a degraded DOST inlet valve that allowed fuel to transfer from the 1B DOSTs to the 1A DOSTs.
|05000454/LER-2015-002||1 May 2015||Byron|
At 1101 hours on March 3, 2015, Byron Station Unit 1 tripped from full power due to a phase to phase fault on the 1 E Main Power Transformer (MPT) between electrical Phase A and Phase B. Before this trip, the Byron area had experienced severe weather. At the time of the event, the temperature was approximately 30 degrees F; however, temperatures had been around 23 degrees F hours earlier. An ice formation on the Phase B Bus bar that is located directly above the high voltage bushings dropped and caused a phase to phase fault between Phase A and B.
This event is reportable in accordance with 10 CFR 50.73(a)(2)(iv)(A) for any event or condition that resulted in manual or automatic actuation of any of the systems listed in paragraph 10 CFR 50.73(a)(2)(iv)(B).
The cause of this event was due to latent design vulnerability that existed in the configuration of the Bus bar relative to the MPT bushings. The Bus bar location directly above and parallel to the MPT bushings created a condition that resulted in a phase to phase short when ice from the Bus bar fell across the bushings. The Bus bar is six inches in diameter and located approximately twenty-three feet above the top of the bushings. The 1 E MPT high voltage and was restarted.
|05000454/LER-2015-001||11 March 2015||Byron|
On January 11, 2015, at 2055 hours, Byron Station Unit 2 entered Technical Specification (TS) 3.7.2, "Main Steam Isolation Valves (MSIVs)," Condition A, with an associated 8 hour Completion Time for the Unit 2, Train 'A' MSIV due to one of the associated redundant actuator trains being inoperable. This action was consistent with an October 19, 2006 NRC staff interpretation that Surveillance Requirement 22.214.171.124 requires both actuator trains for a single valve to be tested and an MSIV shall be declared inoperable when one of its associated actuator trains is inoperable. A subsequent Byron Station extent of condition review identified two previous occurrences in the prior three years when an actuator train for an MSIV was inoperable and the inoperable train was not restored within the required 8 hour Completion Time. In these instances, TS requirements of 3.7.2 were inadequately applied and should have been imposed. This event is reportable in accordance with 10 CFR 50.73(a)(2)(i)(B) for any operation or condition which is prohibited by the plant's Technical Specifications.
The cause of the event was a departure from Byron Station's previous practice to one that was based on the October 19, 2006 NRC position in regard to entering TS 3.7.2, Condition A, under similar conditions. Corrective actions included communicating to operating crews, revising procedures and implementation of new TS for MSIVs.
|05000454/LER-2014-003||14 May 2014||Byron|
On March 15, 2014, at 1102 hours, Byron Station Unit 1 experienced a Loss of Off-site Power (LOOP) event.
The event occurred during refuel outage B1R19 with Unit 1 in Mode 6 during reactor core offload activities.
Both Unit 1 Emergency Diesel Generators (DGs) auto-started and re-energized the safety related buses as designed. During the activity, the plant received a System Auxiliary Transformer (SAT) differential relay actuation that initiated a trip and lockout of the Unit 1 SAT feed breakers, thereby resulting in a Unit 1 LOOP with subsequent DG auto-start. This condition is reportable to the NRC in accordance with 10 CFR 50.73(a)(2)(iv)(A), °Any event or condition that resulted in manual or automatic actuation of any of the systems listed in paragraph (a)(2)(iv)(B) of this section".
The most probable cause of the LOOP with subsequent DG auto-start was a combination of equipment failures involving a faulty test switch that caused a charge to build up in the energized-open circuit and a subsequent electrical discharge when an over-current relay was reinstalled.
NRC FORM 386 (02-2014)
|05000454/LER-2014-002||21 April 2014||Byron|
On February 19, 2014, it was determined that the Byron Station has not complied with Technical Specifications (TS) 3.4.3, "RCS Pressure and Temperature (PIT) Limits,° between March 2011 and October 2013, during start-up of the plant following plant refueling outages. Byron TS 3.4.3 Limiting Condition for Operation (LCO) states that ARCS pressure, RCS temperature, and RCS heatup and cooldown rates shall be maintained within the limits specified in the PTLR.° During previous Reactor Coolant System (RCS) vacuum fill operations at Byron Station Unit 1 and Unit 2, RCS pressure exceeded the Pressure and Temperature Limits Report (PTLR) P/T curve lower bound in that the P/T curve does not indicate a limit below 0 psig. This TS non-compliance is reportable in accordance with 10 CFR 50.73(a)(2)(i)(B), °Any operation or condition prohibited by the plant's Technical Specifications°.
The cause of operation outside of the P/T curve limits is the application of an inadequate operating procedure that allowed the P/T lower pressure bound to be exceeded during RCS fill operations.
RCS fill pressures below the PfT curve lower bound did not affect the integrity of the RCS system.
NRC FORM 388 (02.2014) APPROVED BY OMB: NO. 3150-0104 EXPIRES: 01/31/2017 Estimated burden per response to cern with this mandatory collection request: 80 hours.
Reported lessons learned are irkarporated into the boensing process and fed back to industry.
Send comments reganing burden estimate to the MA, Privacy and Information Ccffections Branch (T-5 F53), U.S. Midear Regulatory Commission, Washington, DC 20556-0001, or by Internet e-mail to infocollects.Resourceffinrc.gor, and to the Desk Officer, Office of Information and Regulatory Affairs, NE013-1= (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information cdlececn does not display a currently yard OMB control number, the NRC may not conduot or sponsor, and a person is not required to respond to, the information collection.
|05000454/LER-2014-001||24 March 2014||Byron|
On January 23, 2014, Byron Unit 1 and Unit 2 were in Mode 1 with reactor power at 100 percent. At 0539, the OA Essential Service Water (SX) Makeup Pump auto-started while lowering basin level for the scheduled OB SX Makeup Pump monthly run surveillance. The OA SX Makeup Pump was running for approximately 21 minutes until it could be secured per the operating procedure. At the time of the OA SX Makeup Pump auto- start, SX tower basin levels were being lowered for a scheduled OB SX Makeup Pump auto-start per OBOSR 7.9.6-2, "Essential Service Water Makeup Pump OB Monthly Operability Surveillance".
Since the auto-start of the opposite train SX makeup pump was not part of a preplanned sequence during the surveillance, this is a reportable condition in accordance with 10 CFR 50.73(a)(2)(iv)(A) as an event or condition that resulted in manual or automatic actuation of an Emergency Service Water System that does not normally run and that serves as an ultimate heat sink, which is listed in paragraph 10 CFR 50.73(a)(2)(iv)(B).
The cause of the event was that the operating procedure directs the controller to be set at a level that leaves little margin to the SX Makeup Pump automatic start level switch setpoint, especially when adverse environmental conditions such as high winds and wave action exist.
|05000455/LER-2013-003||25 November 2013||Byron|
On September 26, 2013, it was identified that a previous condition had existed where the Unit 2, A-Train (2A), Diesel Generator (DG) Ventilation Fan did not automatically start in support of a DG surveillance.
On August 15, 2011, with Byron Station Unit 2 operating in Mode 1 at 100 percent reactor power, the 2A DG Ventilation Fan was left in a condition that made it unable to automatically start on an emergency actuation.
The error was discovered two days later during a routine scheduled DG surveillance. As a result, the 2A DG was discovered to have been inoperable for two days and the station did not perform the required Technical Specification surveillances for one DG inoperable. This condition resulted in a violation of Technical Specification 3.8.1, "AC Sources - Operating", Required Condition B, and is a reportable condition in accordance with 10 CFR 50.73 (a)(2)(i)(B) as any event or condition that was prohibited by Technical Specifications.
The cause was that the Post Maintenance Test (PMT) work instructions did not identify the need to reset the High Differential Pressure (D/P) trip signal by placing the Ventilation Fan Control Switch in Pull-to-Lock (PTL) and did not validate that the ventilation fan would restart after a High D/P Trip.
NRC FORM 368 (10-2010)
|05000455/LER-2013-002||18 November 2013||Byron|
On September 18, 2013, the plant was in Mode 1 with reactor power at 100 percent. At 1555, an unqualified valve diaphragm was identified to have been installed on Air Operated Valve 2RE9160A, Reactor Coolant Drain Tank to Waste Gas (GW) Compressor Inside Containment Isolation Valve, during the 2011 refuel outage.
The 2RE9160A valve was immediately declared inoperable based on the unqualified valve diaphragm. The associated containment penetration was isolated per the required actions in Byron Technical Specification (TS) 3.6.3, Condition A. Since the condition existed for longer than allowed by TS 3.6.3 (Containment Isolation Valves), Required Action A.1, i.e., for more than 4 hours, this is a reportable condition per 10 CFR 50.73 (a)(2)(i)(B) as any event or condition that was prohibited by Technical Specifications.
The cause of the event was an incorrect assumption made by the Maintenance Work Planner to use an unqualified valve diaphragm in a qualified application.
|05000454/LER-2013-001||18 November 2013||Byron||At 1140 hours on September 17, 2013, with Byron Station Unit 1 operating in Mode 1 at 100 percent power, a charcoal filter sample was drawn from the A Train Control Room Emergency Filtration System (CREFS). On September 26, 2013, Engineering was notified by the testing vendor that the methyl iodide penetration test performed on the charcoal filter sample had failed. Accordingly, it was concluded that the A Train CREFS had actually been inoperable since September 17, 2013, when the sample was originally removed from the filter unit. Operators were notified, and the A Train CREFS was declared inoperable in accordance with Byron Technical Specification (TS) 3.7.10, on September 26, 2013, at 0645 hours. The charcoal filter was replaced and retested satisfactorily. The A Train CREFS was declared operable on September 27, 2013, at 2057 hours. Since the condition existed for longer than allowed by TS 3.7.10, Required Action (A.1), i.e., for more than 7 days, this is a reportable condition per 10 CFR 50.73 (a)(2)(i)(B) as any event or condition that was prohibited by Technical Specifications. The cause of the unsatisfactory sample test result is that the applicable charcoal banks had reached their end of life.|
|05000455/LER-2011-001||22 June 2011||Byron||On November 17, 2010, during a surveillance run, the Unit 2 "A" (2A) Emergency Diesel Generator (DG) was operating when the Equipment Operator (EO), assigned to monitor the 2A DG, identified a significant lubricating oil leak from the upper oil cooler. The EO tripped the DG by depressing the emergency stop pushbutton. The 2A DG was declared inoperable and Technical Specifications 3.8.1, "AC Sources - Operating" Condition B was entered. The oil leak source was determined to be coming from the upper lubricating oil cooler at the bolted flange connection between the cooler's shell and the stationary channel head. The as-found bolt torque values were found to be significantly less than the expected value of 110 foot pounds. It was determined the bolt loosening was caused by the torquing of another flange that was misaligned during 2A DG maintenance in January 2010. It was also identified that the Electric Power Research Institute (EPRI) provided recommendations for assembly of misaligned joints to prevent short term relaxation. This recommendation was not incorporated into the appropriate maintenance procedure for work on DG oil coolers. The cause was determined to be a lack of a formal process to ensure EPRI documents are systematically reviewed for good practices and then incorporated into maintenance procedures. Corrective actions include revising the maintenance procedure for assembly of bolted connections to incorporate the EPRI recommendations and revising the Operating Experience program to include EPRI documents. The 2A DG was restored to operable status on November 22, 2010.|
|05000455/LER-2010-001||18 June 2010||Byron|
On April 19, 2010, Byron Station Unit 2 was shutting down for a refuel outage and was in Mode 4. An outage activity during Mode 4 was to perform the Feedwater Isolation Valve (FWIV) surveillance procedure. At 0503, during the restoration section of the test procedure, a low level condition on the 2D Steam Generator (SG) inadvertently occurred which resulted in the generation of Reactor Protection trip initiation, Auxiliary Feedwater initiation, and SG Blowdown isolation signals. Due to shutdown conditions, the control rods were already fully inserted, the Reactor Trip breakers positioned open and the Auxiliary Feedwater pumps were removed from service.
The causes of the inadvertent actuation signals include Operations supervisory oversight of the FWIV testing activity was less that adequate, and the FWIV surveillance procedure was inadequate in that it did not provide for the specific recovery of SG level during the conduct of the procedure if levels were approaching the low actuation setpoint.
Corrective actions include reinforcing the roles and responsibilities of key outage Operations positions, and revising the FWIV stroke procedure to incorporate steps that allow for SG level recovery strategies to manage system parameters to avoid challenges to actuation setpoints.
NRC FORM 266 9-2007, PRINTED ON RECYCLED PAPER
|05000454/LER-2009-001||9 June 2010||Byron|
On October 27, 2009, an on-line planned work window began for the Unit 1 Train B Residual Heat Removal (RH) suction line to replace the water as a dose reduction effort and to perform required valve stroke tests on the Sump Isolation Valve (i.e., 1S18811B). The 1SI8811B valve receives an automatic open signal during a Loss of Coolant Accident (LOCA) to switch the Train B Emergency Core Cooling System pumps' suction to the sump. Byron Operating Procedure (BOP) RH-4, "Draining of the RH System," was initiated to drain the Unit 1 Train B RH suction line. The BOP RH-4 requires the 1S18811B valve to be closed but it does not require it to be de- energized. On October 28, 2009, at 0027, the drain and vent valves were opened to start the draining evolution.
During the draining, a Reactor Operator identified a concern that with the 1S18811B not de-energized it was still capable of opening in response to a LOCA. This would create a leak path of radioactive sump water outside of Containment into the Auxiliary Building while the drain and vent valves were open. The cause was determined to be an inadequate drain procedure in that it did not require the 1 S18811B to be de-energized while the RH suction line was breached. Corrective actions include revising the procedure and performing an extent of condition assessment. This condition was subsequently determined to be an unanalyzed condition; however, there were no actual safety consequences since at no time was an SI8811 valve open when the suction line was breached.
NRC FORM 3-66 9-2.r.„4Th RRtNT ED ON R ECYF:La p Fz 374
|05000455/LER-2009-001||10 February 2010||Byron|
On June 24, 2009, at approximately 1:00 pm, a small pinhole leak was identified in a coupling weld connection of a 3/8 inch diameter Process Sampling (PS) tube which is connected to the Unit 2 Reactor Coolant System (RCS). The leak rate was characterized as less than one drop in five minutes which is estimated to be approximately 0.005 gallons per day. This pinhole leak was in a non- ASME code line and was isolated from the RCS via an ASME Class 2 closed sample control air operated valve. After a review of the appropriate Technical Specifications (TS), Shift Management concluded this small leak was considered RCS "identified" leakage and not RCS "pressure boundary" leakage. Therefore, no TS actions were deemed to be necessary for this condition, The NRC Senior Resident Inspector challenged the characterization of the leak as RCS "identified" leakage versus RCS "pressure boundary" leakage.
The NRC's basis for this position was that the leak was not isolated because some leak by was occurring past the isolation valve's seat out through the fault.
After continued discussions with the NRC, the licensee acknowledged the NRC position and immediately entered TS 3.4.13 Condition B on Unit 2 for exceeding the RCS "pressure boundary" leakage limit at 4:30 pm on June 26, 2009. Condition B requires Unit 2 to be placed in Mode 3 in six hours and Mode 5 in 36 hours. In addition, an expedited repair effort of the PS line had been initiated earlier in the day. The repair to the line was successfully performed and tested by 8:07 pm, and TS 3.4.13 Condition B was exited prior to a power reduction.
Shift Management incorrectly characterized the RCS leakage as identified leakage. Shift Management personnel will be trained on how to correctly characterize RCS leakage of this nature. This event had very low safety significance due to the extremely small nature of the leakage past the seat of the closed isolation valve.
|05000454/LER-2001-002||26 November 2001||Byron|
At 1600 hours on September 26, 2001, it was determined that the two Surveillance Requirements (SR) for the Main Steam Isolation Valves (MSIVs) were not tested in Mode 3, as required. The failure to test the valves in Mode 3 resulted in missed Technical Specifications (TS) Surveillance Requirements (SRs) on all 4 MSIVs on each unit, which resulted in both units entering SR 3.0.3. SR 3.0.3 allows up to 24 hours to either perform the missed surveillances or take other remedial measures. In accordance with the TS Bases, these SRs must be performed in Mode 3. Byron Station has been previously testing the MSIVs in Mode 4. The surveillances can not be performed at power since the SRs require the MSIVs to close. Enforcement Discretion and a subsequent exigent License Amendment Request (LAR) were requested from the NRC to allow continued operations without satisfying the SRs in Mode 3. On September 27, 2001, the NRC granted verbal approval of the Notice of Enforcement Discretion (NOED). The LAR was approved on November 1, 2001. The cause of the missed SR occurred during the Improved Technical Specifications (ITS) implementation project. The procedure revision implementation for the MSIV SRs did not recognize that the more restrictive requirement (i.e., to perform the MSIV SR in Mode 3) was introduced into the TS Bases wording. The root cause of the implementation error was determined to be unknown. Corrective actions include correcting the outage schedule and procedures and reviewing for other potential ITS implementation errors. This event is being reported pursuant to 10CFR50.73(a)(2)(i)(b).
|05000455/LER-2001-003||17 October 2001||Byron|
On August 17, 2001, a human performance error occurred on Unit 2, leading to Technical Specification (TS) 3.6.3, Containment Isolation Valves (CIV) non-compliance. A Unit 2 'A' train CIV for the Hydrogen Monitor System was mistakenly identified and used as the isolation boundary for the 'B' train Hydrogen Monitor. In addition to the wrong train, the valve selected was a "fail open" valve and would not isolate the penetration upon being de-activated. Because of this error, the Station failed to correctly isolate the correct containment penetration for the 2B Hydrogen Monitor. In addition the containment penetration for the 'A' Hydrogen Monitor was also rendered inoperable since the 'A' train CIV failed open when power was removed and would not have closed upon receipt of a containment isolation signal. Neither penetration was isolated within the required four hours of the occurrence as required by TS. The error was discovered and rectified approximately 22 hours later. The root cause of this event was determined to be a failure of the licensed operators to follow standard operating practices in determining and implementing equipment isolation boundaries as expressed in departmental procedures and policies. The Operations department is currently developing an Operations Gap Analysis and Excellence Plan. This plan will identify areas where personnel performance is not meeting expectations. Following completion of the plan, implementation of actions necessary to achieve performance improvement will be undertaken. There were no safety consequences impacting plant or public safety as a result of this event. The Hydrogen Monitors and their associated CIVs do not impact core damage frequency.
This event is reportable to the NRC in accordance with 10 CFR 50.73 (a)(2)(i)(b).