|Report date||Site||Event description|
|05000263/LER-2017-006||12 January 2018||Monticello|
On November 14, 2017, it was identified that the use of the Reactor Protection System (RPS) test fixture described in some operations procedures would result in the loss of two RPS reactor Scram functions. Technical Specification 220.127.116.11 requires that RPS Instrumentation for Table 18.104.22.168-1 Function 5, Main Steam Isolation Valve-Closure and Function 8, Turbine Stop Valve-Closure, remain operable. It was concluded that a closure of three of four Main Steam Lines or Turbine Stop Valves would not necessarily have resulted in a full Scram during testing depending on the combination of closed valves occurring during the bypass condition. Operations procedures were revised to incorporate the use of the test fixture in December, 2008 for the Turbine Stop Valve Closure Scram Test Procedure and February, 2009 for the Main Steam Isolation Valve Closure Scram Test Procedure. The operations procedures were inappropriately revised to allow use of the test fixture on all RPS functions to prevent a half Scram.
The operations procedures were quarantined until revisions were issued in December, 2017 that removed use of the test fixture.
|05000263/LER-2017-005||20 September 2017||Monticello||On July 23, 2017, the Emergency Diesel Generator (EDG) lube oil cooler immersion heater temperature switch failed (in the on position) which together with residual heat from 12 EDG operation actuated the EDG engine temperature switch resulting in a valid start signal to the 12 EDG Emergency Service Water (ESW) System pump and transfer of pump control to the Alternate Shutdown System panel. In accordance with 10 CFR 50.73(a)(2)(iv)(A) an automatic actuation of the ESW System is reportable. The apparent cause of the 12 EDG hot engine condition was a failed temperature switch for the immersion heater in concert with operating the 12 EDG. From the time of the problem identification through the 12 EDG surveillance test, lube oil temperature was monitored by Operations and never exceeded the normal operating band when the EDG was in the shutdown ready-to-start configuration and during the EDG monthly surveillance run. Therefore, the 12 EDG remained operable. The immediate corrective action was replacement of the failed temperature switch. A long-term corrective action is to evaluate the immersion heater and associated control circuit to determine if the temperature switch design and preventative maintenance frequency are appropriate. Corrective action will be taken based on the results of this evaluation.|
|05000263/LER-2017-004||16 August 2017||Monticello|
On June 19, 2017 following a planned High Pressure Coolant Injection (HPCI) system maintenance, a HPCI start attempt was performed per the quarterly test procedure. HPCI failed to start during the test due to the steam stop valve HO-7 not opening caused by HO-7 oil relay not functioning properly.
Since the component was not the subject of the maintenance activity, the HPCI failure was reported to the NRC under Emergency Notification System, Event Number 52814.
The HO-7 oil relay was repaired and the HPCI system was returned to operable status at 13:30 on June 23, 2017.
|05000263/LER-2017-003||14 June 2017||Monticello|
On April 20, 2017 during outage 1R28 Local Leak Rate Testing (Appendix J), AO-2-86C, "13 Outboard Main Steam Isolation Valve," had an unacceptable as-found leak rate. The measured leakage rate was 187.8 standard cubic feet per hour (scfh) which exceeds the Monticello Nuclear Generating (MNGP) Technical Specification (TS) Surveillance Requirement (SR) 22.214.171.124.12 limit of 100 scfh.
AO-2-86C was declared inoperable and the valve was subsequently disassembled to make repairs.
The valve's stem, discs, upper/lower wedges, disc retainer, and wedge pin were replaced and retested.
The as-left leak rate after completion of the work was 2.64 scfh.
This component failure is reportable in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by TS 126.96.36.199, "Primary Containment Isolation Valves," since AO-2-86C likely had been inoperable for greater than the TS 188.8.131.52, Required Action A.1, Completion Time of 8 hours to isolate a main steam line, and the Completion Time for TS 184.108.40.206, Required Action F, to be in Mode 3 in 12 hours and Mode 4 in 36 hours when the completion time of A.1 is not met. There were minimal safety consequences associated with the condition since the primary containment isolation function was maintained by the inboard valve.
|05000263/LER-2017-002||13 June 2017||Monticello|
On April 15, 2017 at approximately 10:56 am, with the plant at 0% power in Mode 4 (Shutdown), while performing a plant shutdown procedure the "D" outboard Main Steam Isolation Valve (MSIV), AO-2- 86D was functionally tested. The Monticello Nuclear Generating Plant (MNGP) Technical Specifications (TS) Surveillance Requirement (SR) 220.127.116.11.6 requires that the isolation time of each MSIV is > 3 seconds and ime was measured at approximately 40.7 seconds. The valve was declared inoperable and subsequently repaired. The failure was attributed to the air pack pilot valves.
This component failure is reportable in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by TS 18.104.22.168 "Primary Containment Isolation Valves," since AO-2-86D may have been inoperable for greater than the TS 22.214.171.124, Required Action A.1, Completion Time of 8 hours to isolate a main steam line, and the Completion Time for TS 126.96.36.199, Required Action F, to be in Mode 3 in 12 hours and Mode 4 in 36 hours when the completion time of A.1 is not met. There were minimal safety consequences associated with the condition since the primary containment isolation function was maintained.
|05000263/LER-2017-001||13 June 2017||Monticello||On April 15, 2017 at 0436 hours, the 11 Reactor Feedwater Pump (RFP) was removed from service and the discharge valve closed. With the discharge valve closed and 12 RFP previously isolated no flow path was lined-up for the Condensate pumps to supply water to the vessel. Reactor water level lowered resulting in valid Reactor Protection System (RPS) actuation and Primary Containment Group II Isolation signals. The 11 RFP discharge valve was reopened to reestablish a flowpath to restore level. The RPS and Group II isolation logic was reset when cleared. Two apparent causes were identified: 1) Failure to identify and address the unusual Feedwater System configuration prior to execution of the 11 RFP shutdown. 2) Guidance for shutdown of the RFP did not take into account the state of the other train when shutting down a RFP. The corrective actions were: 1) Revise plant startup and shutdown procedures to ensure abnormal equipment lineups are addressed to avoid unexpected interactions. 2) Revise the Feedwater System operation procedure to maintain a flow path when the opposite train Reactor Feed Pump is isolated|
|05000263/LER-2016-003||25 January 2017||Monticello|
On November 27, 2016, the Monticello Nuclear Generating Plant (MNGP) was operating at 100% power. While troubleshooting was in progress for a minor leak on the High Pressure Coolant Injection System (HPCI) turbine, it was discovered that the HPCI turbine exhaust drain pot level switch was not functioning per design to support removal of condensate from the HPCI turbine. Subsequently, HPCI was declared inoperable at 1447 hours due to excessive water level within the HPCI turbine.
Previously, on November 17, 2016, a steam leak was identified on the packing of the HPCI turbine steam supply valve. Following valve packing maintenance on November 21, 2016, the valve was cycled cold (without steam flow), resulting in seat leakage that slowly admitted steam into the HPCI exhaust piping. The steam condensed to water and accumulation began to form in the HPCI turbine. Subsequent troubleshooting found the HPCI exhaust drain pot level switch electrical rocker assembly off its pivot point due to a manufacturer defect (missing spot weld). With the inability to pivot, the level switch became non-functional and thus failed to alert the control room and provide the automatic function to drain condensate from the HPCI exhaust piping. The HPCI exhaust piping was drained of condensate and a temporary modification replaced level switch. HPCI was restored to operable status at 1726 hours on December 1, 2016.
|05000263/LER-2016-002||19 December 2016||Monticello|
On August 4, 2016, while performing a Fire Protection/Appendix R self-assessment, it was discovered that the floor between the Cable Spreading Room (CSR) and the Plant Administration Building (PAB) basement is not an adequate Appendix R fire barrier. Because the CSR and the PAB are located in the same Fire Area (FA), a fire in the PAB could spread to the CSR requiring evacuation of the control room (CR). When the CR is evacuated, alternate shutdown activities are performed at the Alternate Shutdown System (ASDS) Panel. The travel path used to access the ASDS Panel following control room evacuation traverses the same fire area in the PAB.
This unanalyzed condition resulted from the determination that because of the inadequate fire barrier, a fire in the PAB would now require use of an alternate shutdown strategy to safely shutdown the reactor. However, the alternate shutdown strategy requires that the operators traverse from the control room through the PAB Fire Area to access the alternate shutdown equipment. This path could be impacted by the PAB fire.
In response to this discovery an hourly fire watch was established.
|05000263/LER-2016-001||1 September 2016||Monticello|
The High Pressure Coolant Injection (HPCI) system was inoperable during a pre-planned maintenance activity when a significant oil leak in HPCI system oil piping occurred because of a cracked oil pipe nipple.
The leak was of sufficient size that if it occurred outside the pre-planned maintenance, HPCI would have been declared inoperable. The equipment failure analysis concluded that the most likely cause was that HPCI pipe nipple was exposed to significant loads, sufficient to initiate a crack, likely from applied wrench torques during oil leak repair activities in 2005. With the presence of the crack and crack propagation mechanism, the engineering evaluation determined that HPCI was inoperable from January 9 through March 24, 2016, i.e. 75 days. The organizational root cause was that management and individuals were tolerant of leaks on the HPCI system. As a result, station personnel did not effectively advocate prompt repair of the HPCI oil leak.
The cracked HPCI oil pipe nipple was replaced. Results of the extent of condition review identified two other pipe nipples and two elbows with thread leakage (no crack present). The pipe nipples were replaced and the elbows were reused. The HPCI system was tested successfully after the repairs.
|05000263/LER-2014-002||13 July 2016||Monticello|
On February 7, 2014, while performing the monthly torus to drywell vacuum breaker check procedure, vacuum breaker valve AO-2382A did not indicate closed as expected. The valve was cycled several times per an alarm response procedure for an open torus to drywell vacuum breaker until it indicated closed.
A causal evaluation has determined the cause of the observed indication for vacuum breaker valve AO-2382A after cycling to be interference between the vacuum breaker test lever and vacuum breaker test actuator stem.
This interference was introduced during the 2013 refueling outage when the lever arm was removed for seal replacements. The procedural guidance was not detailed enough to ensure the critical clearances were maintained during removal and replacement of the test lever. The condition was, resolved during the 2015 outage by establishing proper clearances between the test lever and actuator stem for all torus to drywell was removed. In addition, a revision to the torus to drywell vacuum breaker seal replacement procedure was made to ensure proper clearance between the test lever and test actuator stem would be maintained following maintenance activities.
|05000263/LER-2015-006||21 January 2016||Monticello|
On November 23, 2015, a trip of the # 11 Reactor Recirculation Pump occurred, followed by a Group 1 isolation which resulted in a reactor scram. A post scram troubleshooting investigation determined a large spike in differential pressure occurred in the 'C' main steam flow instrumentation line at the time of the Group 1 initiation event.
The root cause of this event was determined to be legacy foreign material present in the 'C' main steam flow instrumentation line. This foreign material obstructed the instrumentation line and resulted in the momentary sensed high steam flow. The sensed high steam flow was not due to an actual high steam flow condition in the 'C' main steam line.
Since the presence of foreign material in the instrument line is a legacy issue, the corrective action for the root cause was to remove the foreign material. The corrective action for the trip of the reactor recirculation pump, will be to revise the fleet procedure to require verification of torque on accessible electrical connections for critical components which are bench tested and also to ensure that accessible soldered and crimped electrical terminations are inspected for sians of dearadation durina bench testina.
|05000263/LER-2015-007||21 January 2016||Monticello|
On November 24, 2015 at 0534 hours, the Monticello Nuclear Generating Plant was at 0% power in Mode 3 (Hot Shutdown) for a forced outage. While initially placing Shutdown Cooling (SDC) in service, the 12 Residual Heat Removal (RHR) pump tripped approximately 8-10 seconds after start due to the closure of the RHR SDC suction isolation valves. When placing SDC in service, flow rapidly increased after opening the RHR Division 2 Low Pressure Coolant Injection (LPCI) outboard injection valve causing a localized pressure transient in the reactor recirculation pump suction piping that resulted in an isolation of the SDC suction line. Reactor pressure vessel (RPV) pressure remained stable at approximately 30 psig.
Prior to attempting to place 'B' SDC in service, the Condensate system and the 'F' Safety Relieve Valve were in service providing decay heat removal. Immediate actions were taken to restore 'B' RHR SDC to operable status, thus an alternative method of decay heat removal was already established by the Condensate system and `F' Safety Relief Valve.
|05000263/LER-2015-005||2 October 2015||Monticello|
On August 3, 2015, an extent of condition review for LER 2015-003, "Use of the Reactor Water Cleanup (RWCU) System to Lower Level without Declaring an Operation with a Potential to Drain the Reactor Vessel (OPDRV) with Secondary Containment Inoperable," identified two prior occurrences where this had occurred. On May 26, 2013, during the 2013 Refueling Outage, the RWCU System was used to lower reactor cavity level with the Secondary Containment (SCT) inoperable. On February 4, 2014, during the 2014 recirculation pump seal forced outage, reactor water level was lowered in preparation for startup using the RWCU System while the SCT and the B Standby Gas Treatment subsystem were inoperable. Each occurrence constitutes an operation or condition prohibited by the Technical Specifications, during OPDRV, which are reportable in accordance with 10 CFR 50.73(a)(2)(i)(B).
The cause was determined to be that the plant procedure controlling OPDRVs failed to provide adequate guidance to determine an OPDRV activity which resulted in actions taken that were not in accordance with NRC Enforcement Guidance Memorandum (EGM) 11-003, Revision 2. The plant OPDRV procedure has been revised to reflect the guidance of the EGM.
|05000263/LER-2015-003||11 September 2015||Monticello||On May 13, 2015, and on April 13 and April 14, 2015 (identified during an extent of condition review), the Reactor Water Cleanup (RWCU) System was used to perform reactor cavity and dryer-separator storage pool inventory reductions. Use of RWCU System constituted an Operation with a Potential to Drain the Reactor Vessel (OPDRV). However, the plant OPDRV procedural guidance did not identify this as an OPDRV. These occurrences are being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as an operation or condition prohibited by the Technical Specifications. The cause was determined to be that the plant OPDRV procedure failed to provide adequate guidance to determine OPDRV activities which resulted in actions taken that were not in accordance with NRC Enforcement Guidance Memorandum (EGM) 11-003, Revision 2. The plant OPDRV procedure has been revised to reflect the guidance of the EGM.|
|05000263/LER-2015-004||21 August 2015||Monticello|
On June 24, 2015 during performance of turbine stop valve scram testing, the relay associated with the scram logic failed to de-energize as expected. Based on this failure to de-energize, stop valve 4 (SV-4) limit switch would not have contributed an input to the scram logic as designed.
The cause of the failure is unknown at this time but has been isolated to the limit switches through troubleshooting efforts. The limit switches are located in a high radiation area that precludes investigation during reactor operation. The fuse for the logic associated with SV-4 limit switch has been removed to meet Technical Specification requirements, thus there is a half subchannel trip in place on channels A2 and B2.
With the subchannels in trip, the likelihood of a scram is increased. The cause will be supplemented upon completion of investigation. A troubleshooting plan is in place to perform investigation of the limit switches at the next available opportunity.
|05000263/LER-2015-002||20 August 2015||Monticello|
On May 2, 2015, the Monticello Nuclear Generating Plant (MNGP) was in Mode 5 for a refueling outage.
During performance of surveillances of the non-credited 4kV essential Bus, MNGP experienced a loss of the 4kV Bus and essential Load Center due to an improperly landed jumper wire. Loss of the Load Center de- energized the valve position indication on the Residual Heat Removal (RHR) shutdown cooling inboard isolation valve, causing a subsequent trip of the RHR pump operating in shutdown cooling on a pump suction interlock and a loss of normal shutdown cooling. Control Room operators entered the appropriate abnormal procedures and verified alternate decay heat removal was in service until shutdown cooling could be restored.
Immediate corrective actions included suspension of all work pending approval of the shift manager to ensure outage activities did not further degrade plant conditions and electrical work was limited to protect shutdown cooling. The essential Load Centers were cross tied to restore normal shutdown cooling.
Corrective actions include revising procedures to reinforce human performance tools, adequately assess risk involved with electrical work, and ensuring effective barriers are in place to harden residual heat removal function durina shutdown conditions.
|05000263/LER-2015-001||16 June 2015||Monticello|
On April 23 and 25, 2015, during planned Reactor Recirculation System modifications and maintenance, the provisions of NRC Enforcement Guidance Memorandum (EGM) 11-003 (Revision 2) were invoked for Operations With a Potential to Drain the Reactor Vessel (OPDRV) in noncompliance with Technical Specification (TS) 188.8.131.52, "Secondary Containment." These conditions are being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as an operation or condition prohibited by the TS that is under enforcement discretion as specified in EGM 11-003.
The safety significance of these noncompliances is minimal as EGM 11-003 specifies interim actions that provide an adequate level of safety. Implementation of EGM 11-003 for these actions was a planned activity and as such, no cause determination was performed for the events. Following development of a Technical Specification Task Force traveler a license amendment request will be submitted to resolve this issue as required by EGM 11-003.
|05000263/LER-2015-001, Operations With A Potential To Drain The Reactor Vessel (OPDRV) Without Secondary Containment Operable||16 June 2015||Monticello|
|05000263/LER-2014-009||30 September 2014||Monticello|
On August 5, 2014, the 'A' emergency filtration train (EFT) was out of service for charcoal filter replacement work; during that time 13' EFT was placed in service to supply fresh filtered air to the Control Room. After the 13' EFT had run for 12 minutes, a low flow alarm occurred and the '13' EFT fan tripped. This resulted in both trains of emergency filtration being inoperable. Technical Specification Limiting Condition for Operation (LCO) 3.7.4 was not met and as a result, LCO 3.0.3 was entered at 16:01 hours which required the plant to be in Mode 4 within 37 hours.
The '13' EFT fan tripped because the damper actuator failed due to poor quality of vendor refurbishment. The 'B' EFT trip caused the plant to enter LCO 3.0.3 due to the legacy operating procedure that permitted Operators to start the 'B' EFT while 'A' EFT was inoperable for maintenance.
The failed actuator was subsequently replaced and post maintenance testing was satisfactorily completed.
The EFT procedures will also be revised to restrict operation of the standby train while in protected status.
|05000263/LER-2014-008||14 July 2014||Monticello|
On May 15, 2014, an unsealed conduit penetration was identified between two fire zones, Division I and Division II of safe shutdown equipment in the Emergency Filtration (EFT) Building, which does not meet the two hour fire barrier rating of the wall required per the Fire Hazards Analysis.
The cause of the unsealed penetration is unknown and is considered a legacy issue as this conduit was routed prior to 1991.
The EFT fire protection barrier will be restored to functional status and the penetration will be periodically inspected. The Fire Barrier Wall, Damper and Floor Inspection procedure will be revised to add use of additional tools (e.g., cameras or boroscope) to perform inspections on portions of fire barriers that are not easily accessed.
|05000263/LER-2014-007||12 June 2014||Monticello|
On April 17, 2014, plant personnel discovered a previously unrecognized failure to take appropriate actions of Technical Specification (TS) Limiting Condition for Operation 3.4.9. This failure occurred on seven prior occasions when the Reactor Pressure Vessel (RPV) pressure dropped below 0 psig.
The cause of the failure to take the appropriate TS actions was that station personnel did not recognize a vacuum was drawn on the RPV and the implications for compliance with Pressure-Temperature curves.
The Pressure Temperature Limits Report curves will be updated to recognize that the RPV may be operated at a vacuum.
|05000263/LER-2014-006||23 May 2014||Monticello|
On March 28, 2014, two secondary containment doors in the main access airlock were opened at the same time. With both doors open, Technical Specification Surveillance Requirement 184.108.40.206.3 was not met and secondary containment was declared inoperable. Interviews with individuals involved indicate the doors were open for approximately two seconds.
The cause was determined to be plant employees do not have secondary containment airlock training, and the airlock interlock did not have posted operating instructions.
Corrective actions include affixing permanent labels next to the interlock push button which provide instructions on how to appropriately open the doors. As an additional measure, plans are in place to replace the doors with doors that have windows. The need for training on proper airlock operation will also be evaluated for inclusion in general access training.
|05000263/LER-2014-005||19 May 2014||Monticello|
On March 20, 2014, during performance of the semi-annual fire door inspection, an Appendix R fire door did not latch as required and divisional separation could not be assured in the event of a fire. A continuous fire watch was established within the required timeframe once the deficiency was discovered.
The cause of door-410B failure to close and latch during performance of the surveillance was determined to be insufficient closing force.
Immediate corrective actions were to repair door-410B by adjusting the door closer and lubrication of the door latch. The door was then satisfactorily tested and declared functional. Long term corrective actions include door closer force adjustments on a periodic basis.
|05000263/LER-2014-004||11 April 2014||Monticello|
On February 10, 2014, Monticello personnel identified that the Emergency Diesel Generators (EDGs) would not energize permanently connected loads until 10.2 or 10.34 seconds for Division I and Division II, respectively, which exceeded the 10 second limitation of Monticello Technical Specification (TS) Surveillance Requirement (SR) 220.127.116.11. As a result, both EDGs were declared inoperable.
The apparent cause of this event is that the description of the EDG TS SR was inadvertently changed during transition from custom TS 4.9.B.3 to improved TS SR 18.104.22.168 due to improper verification and validation practices of the Improved TS preparation team in 2004-2006.
The set-points for the applicable relays have been revised. The time delay set-point change provides a setting to support EDG performance meeting the 10 second acceptance criterion of SR 22.214.171.124. Additionally, the surveillance procedure will be revised as necessary to implement correct testing for SR 126.96.36.199.
|05000263/LER-2014-001||14 March 2014||Monticello|
On January 17, 2014, leakage into the Reactor Building Closed Cooling Water (RBCCW) System was determined to be Reactor Coolant Pressure Boundary (RCPB) leakage as identified by the Monticello Nuclear Generating Plant (MNGP) Technical Specifications (TS). Based on this, the TS limiting condition for operation was not met and a plant shutdown was required. The plant shutdown commenced at 2029 on January 17, 2014. There was no radioactive release from the plant. The plant was shut down without incident to repair the source of the inleakage.
The apparent cause for the RCPB leak was the lack of an established maintenance strategy in place to periodically check the condition of the heat exchanger or replace it. A crack formed in the #12 Recirculation Pump Upper Seal Heat Exchanger coil due to intergranular stress corrosion cracking.
The leaking # 12 Recirculation Pump Upper Seal Heat Exchanger was removed and the system was modified to operate without this heat exchanger by utilizing the excess capacity of the #12 Recirculation Pump Lower Seal Heat Exchanger.
|05000263/LER-2011-009||1 March 2012||Monticello|
On November 19, 2011, at approximately 2312 CST, during performance of regularly scheduled Turbine- Generator Quarterly Surveillance, an unplanned reactor scram occurred. Following the reactor scram, reactor water level lowered below the Group II isolation initiation setpoint (+9") and an actuation of Primary Containment Isolation System occurred.
The direct cause of the scram was the actuation of the Main Turbine acceleration relay (load rejection) pressure switches. The root cause was ineffective management of Turbine Lube Oil (TLO) Tank Vacuum which resulted in oil build up on the turbine shaft resulting in fouled grounding braids. The shaft grounding device is intended to prevent damage to turbine generator components caused by circulating currents.
Resulting circulating currents degraded the speed governor drive gear which resulted in governor oscillations ("bobble") that manifested itself during speed load changer testing and caused pressure oscillations at the acceleration relay (load rejection) pressure switches.
Corrective actions include replacing the TLO Tank Vacuum Indicator with High Accuracy Device, and updating the operator round sheet to reflect new control bands as required. Repairs were also made to the speed governor gear drive components and main shaft oil pump components which were damaged by electrolysis and a modification was performed to install a more robust grounding apparatus.
|05000263/LER-2011-006||28 February 2012||Monticello|
On September 2, 2011, at approximately 1600, Mechanical Maintenance personnel informed Operations that portions of the Intake Structure sprinkler system piping were found to be partially blocked and incapable of passing flow. The Intake Structure sprinkler system is relied upon in part to satisfy an approved exemption to 10 CFR 50 Appendix R, Section III.G.2.b concerning separation of components in the Intake Structure.
Installation of the Intake Structure sprinkler system in 1983 did not comply with design requirements for providing required pipe slope to ensure proper draining. This condition allowed excessive water to remain in the system which then contributed to accelerated internal corrosion and accumulation of corrosion byproducts in the piping system.
Immediate corrective actions taken included flushing the sprinkler system and performing internal inspections to confirm removal of blockage before returning the system to service.
|05000263/LER-2011-007||28 February 2012||Monticello|
On September 29, 2011, at 1700 hours CDT, Monticello Nuclear Generating Plant (MNGP) determined that the surveillance test procedure used to demonstrate compliance with Technical Specification (TS) surveillance requirement (SR) 188.8.131.52 involving load reject testing of the Emergency Diesel Generators (EDGs) with the single largest post-accident load did not fully satisfy the TS surveillance requirement. This condition resulted in both EDGs being declared inoperable. MNGP requested and was granted enforcement discretion to permit development and performance of a new surveillance test that meets the surveillance requirement.
The cause of the event was an inadequate surveillance test procedure resulting from a failure to fully reflect the changes enacted through the implementation of the Improved Standard Technical Specifications in 2006.
On October 2, 2011, the 12 EDG was successfully tested in accordance with the new surveillance test procedure at which time 12 EDG was declared Operable and the enforcement discretion period exited.
|05000263/LER-2011-008||28 February 2012||Monticello|
At 1250 on October 21, 2011, at the Monticello Nuclear Generating Plant, a 2R Auxiliary Transformer lockout unexpectedly occurred causing off-site power to automatically transfer to the 1R Auxiliary Transformer, which resulted in a reactor scram.
One cable of the "A" phase conductor, supplying power from 2RS to 2R Transformer, faulted to ground, resulting in the 3N4 breaker opening, as designed, to protect 2RS Transformer and other equipment from fault current damage. Subsequent testing indicates the cable suffered from environmental and age-related degradation.
Implementation efforts to replace the cables between 2R Transformer and 2RS Transformer were in progress at the time of the event. A portion of the new raceway was under construction.
The cables were replaced entirely employing a route designed to avoid cable submergence in water.
Subsequent to installation, cables were successfully tested and returned to service.
|05000263/LER-2011-010||26 January 2012||Monticello|
On November 27, 2011, while performing the Rod Worth Minimizer (RWM) Operability Test as part of startup activities, it was discovered that the RWM control switch was in Bypass. With the control switch in the Bypass position, the RWM was inoperable and did not enforce the pre-determined control rod withdrawal sequence.
The RWM control switch was restored to the Operate position and the RWM was verified to be operable.
The apparent cause was determined to be the crew failed to precisely identify the sequence of surveillances/procedures required to be completed, prior to the mode change. The pre-job brief was inadequate in that the specific sequence and details were not discussed and the licensed operators on duty failed to identify that the RWM configuration did not support the mode change. Additionally, control room indications available to the operators were not properly utilized to prevent the out of sequence control rod withdrawal.
|05000263/LER-2011-011||26 January 2012||Monticello|
On November 30, 2011, the plant was in MODE 4 (cold shutdown) with the Reactor Mode Switch in Refuel position for a Control Rod Drive (CRD) exercise. The CRD exercise testing was being performed under Special Operations Technical Specification (TS) 3.10.4, "Single Control Rod Withdrawal - Cold Shutdown". TS Limiting Condition for Operation (LCO) 3.10.4 requires TS LCO 3.9.2, "Refuel Position One-Rod-Out Interlock" to be met. One of the Surveillance Requirements (SR) for TS 3.9.2, SR 184.108.40.206, requires verification every 12 hours that the Mode Switch be locked in the Refuel position. The TS Bases for SR 220.127.116.11 defines "locking" as removing the key from the Mode Switch. During a panel walkdown on December 1, 2011, the Control Room crew found the Reactor Mode Switch was unlocked in the Refuel position. While the Reactor Mode Switch remained in the Refuel position during the CRD exercises, the switch was not locked as required by SR 18.104.22.168. Failure to lock the Mode Switch in the Refuel position during the Control Rod Drive exercises was not in compliance with SR 22.214.171.124, and TS LCO 3.10.4.
The cause of this event was Operator work practices, and inadequate procedural requirements.
Personnel were remediated and applicable procedures were revised as part of the corrective actions for this event.
|05000263/LER-2011-005||26 August 2011||Monticello|
On June 30, 2011, at 0516 with the reactor operating at 80% power, three of four Average Power Range Monitors (APRMs) exceeded Technical Specification 126.96.36.199.2 surveillance requirement to maintain the absolute difference between the Average Power Range Monitor (APRM) channels and the calculated power at s 2% rated thermal power (RTP) while operating at z 25% RTP. The event occurred during a control rod pattern adjustment supporting plant restart following a brief maintenance outage.
The cause was a greater than typical change in APRM response due to a power shape change following the completion of a reactivity maneuvering step. The impact on the APRMs of the power shape change had not been determined in advance and was therefore not anticipated. No requirement existed to perform this calculation.
An interim corrective action includes revising reactivity management procedures to include guidance for monitoring and adjusting gains on APRM's prior to each reactivity maneuvering step which could challenge the +1- 2% criteria.
|05000263/LER-2011-004||8 August 2011||Monticello|
On June 8, 2011 at 0800, with the reactor operating at 100% power, secondary containment (SCT)(NG) was declared inoperable after swapping the operating refuel floor supply air handling unit from V-AH-4A(AHU) to V-AH-4B. SCT differential pressure (D/P) was reduced to 0.17 inches of water column (WC) vacuum, which did not meet Technical Specification (TS) surveillance requirement SR 188.8.131.52.1 to maintain secondary containment vacuum greater than or equal to 0.25 inches WC vacuum. Refuel floor ventilation was restored to the previous configuration and secondary containment D/P returned to greater than 0.25 inches of WC vacuum. Vacuum was less than 0.25 inches WC vacuum for approximately 4 minutes.
The event was caused by a change in supply air flow rates between V-AH-4A and V-AH-4B when swapped.
Corrective actions include repairing a seized bypass damper (CDMP) on V-AH-4A and a procedure change to add precautions to the operating procedure for transferring refuel floor fans.
NRC FORM 266 (10-2010)
|05000263/LER-2011-001||30 March 2011||Monticello|
During the performance of a fire protection assessment, a determination was made that the fire protection safe shut down analysis does not address a postulated reactor vessel overfill event.
In a postulated fire event that required the evacuation of the Control Room with a loss of offsite power, High Pressure Coolant Injection and Reactor Core Isolation Cooling pumps would start if the low reactor water level setpoint is reached. For this fire, damage could result in the failure of the high reactor water level trip circuit for the High Pressure Coolant Injection and Reactor Core Isolation Cooling systems. This could result in a reactor vessel overfill.
Compensatory measures for this issue have been implemented.
|05000263/LER-2011-003||30 March 2011||Monticello||On February 11, 2011, at 0327 hours, Secondary Containment isolation damper V-D-61 (Reactor Building Outboard Isolation Damper) was discovered frozen closed due to ice buildup, with the actuator broken. The inboard damper, V-D-62, was found blocked partially open, again due to icing. A Secondary Containment (SCT) penetration flow path with two isolation valves inoperable condition existed, and Limiting Condition for Operation (LCO) 184.108.40.206 was declared not met. Technical Specification Condition 220.127.116.11.B was entered for one or more penetration flow paths with two isolation valves inoperable. The ice was removed and V-D-62 was verified closed at about 0354 hours, isolating the affected penetration flow path by use of at least one closed and de-activated automatic valve and satisfying the required action of Condition 18.104.22.168.B. Repairs were completed, the system retested, and LCO 22.214.171.124 was met by about 2001 hours on February 11, 2011. On March 11, 2011, with SCT not required, the site tested V-D-61 with the actuator disconnected (event condition), Reactor Building 1027 Supply Fan V-AH-4A operating, and without ice on the damper. The test demonstrated that the damper would not open under these conditions, thereby validating that the safety function of the damper was maintained throughout the event.|
|05000263/LER-2011-002||17 February 2011||Monticello||At 0357 December 20, 2010, with the plant in Mode 1 operating at 100% reactor power, the 'A' division Fuel Pool/Reactor Building Exhaust Plenum Primary Power Supply failed. The failure resulted in upscale trips on both the Fuel Pool and Reactor Building Ventilation Plenum radiation monitors. This condition resulted in closure of the Group II Primary Containment Isolation Valves (PCIV), isolation of Secondary Containment (SCT), initiation of the Standby Gas Treatment System (SBGT), and a transfer of the Control Room Ventilation (CRV) and Control Room Emergency Filtration (CREF) systems to the High Radiation Mode. Conditions and Required Actions were entered for Technical Specification 126.96.36.199 (SCT Instrumentation), 3.31.1 (CREF Instrumentation), and 3.4.5 (RCS Leakage Detection - CAM). Radiation levels were verified to be normal in the affected areas. Isolation signals were reset and Secondary Containment ventilation systems were restored to a normal lineup. Repairs to the power supply were complete within the allowed completion times. All systems functioned properly and there were no human performance errors associated with this event.|
|05000263/LER-2003-001||11 May 2003||Monticello||On March 13, 2003 during a walkdown of fire barrier penetration FZ-4900 in the upper 4KV room it was discovered that a portion of a penetration seal was degraded allowing the upper and lower 4KV rooms to communicate with each other. The barrier was declared inoperable and a continuous fire watch was established. In accordance with 10 CFR 50.72(b)(3)(ii), an 8-hour event notification was made. The Updated Fire Hazards Analysis was reviewed to identify other locations where gypsum board assemblies are used as penetrations. No other penetrations were found to be inoperable as a result of this walk-down. On March 15, 2003 the barrier was repaired and declared operable.|
|05000263/LER-2002-005||20 September 2002||Monticello||While performing an Emergency Service Water (ESW) Valve and Pump Test with the B- division Control Room Ventilation (CRV) Inoperable as required per procedure, the A-division CRV compressor tripped on low cooling water flow. The A-division CRV was declared inoperable, and the station entered Technical Specification (T.S.) 3.17.A.3, which contained an action statement to restore one CRV train to operable within 24 hours. The B-division CRV was returned to an operable status at 1701. Both divisions of CRV were inoperable for 31 minutes. The cause of the event was excessive drift of the differential pressure switch (DPS), DPS-4029A. When DPS-4029A drifted high, the A-division CRV compressor tripped on low service water flow and could not be restarted. The A-division switch was recalibrated and the A-division CRV was restored to an operable status in approximately 24 hours.|
|05000263/LER-2002-003||20 May 2002||Monticello|
While operating at 100% power at 1727 on March 22, 2002, an automatic Group 3 containment isolation signal was generated after sensing high Reactor Water Cleanup (RWCU) system flow. At the time, operations personnel were in the process of restoring the RWCU system to service following investigation of leakage associated with filter demineralizer isolation valves.. The re-performance of the filling and venting portion of the restoration procedure was not performed, because personnel failed to realize that during the investigation process voids had been created within the system.
When repressurizing the system, high flow rates resulted in actuation of the protection logic. Following resolution of these issues and completion of maintenance, the RWCU system was pressurized and returned to service at 0310 on March 24, 2002.
|05000263/LER-2001-011||21 December 2001||Monticello|
While in coastdown for refueling, at 1712 on October 23, 2001, a human performance error caused a reactor scram. The scram was a result of inadvertent contact of a support brace attached to a sensitive instrument rack by an individual performing work in the area.
The primary cause of the event was determined to be inadequate work practices. Although the worker was aware of the sensitive nature of the instrumentation on the rack in the area in which he was working, the worker elected to transport heavy barrier stanchions through the narrow pathway immediately adjacent to a sensitive instrument rack. The worker lost his balance and bumped a support brace for the instrument rack.