|Report date||Site||Event description|
|05000461/LER-2017-010||5 February 2018||Clinton|
On December 9, 2017 at 1347 CDT the Main Control Room received annunciators that indicated a trip of a 4160V 1A1 Breaker, the 480V transformer 1A and Al feed breaker. The loss of Division 1 480V power caused the instrument air (IA) containment isolation valves to fail close as designed. The loss of IA affected various containment loads, including the scram pilot air header and containment isolation valves. Another consequence of this event was that secondary containment differential pressure became positive due to fuel building ventilation dampers failing closed by design due to the loss of power. Operations entered Emergency Operating Procedure (EOP) -08, Secondary Containment Control, and Technical Specification (TS) Limiting Condition for Operation (LCO), 22.214.171.124 Action A.1. Division 2 Standby Gas Treatment System was activated at 1350 and restored secondary containment differential pressure within allowable TS values at 1351. The TS LCO and EOP were exited when allowable TS values were restored. Due to the loss of IA, a manual reactor scram was inserted at 1353 when two control rods began drifting in as expected.
A phase to ground fault was identified on 480V transformer 1A (1AP11E). On December 14, the 480V transformer was replaced and the plant returned to Mode 1 operations on December 15. The condition described in this report was determined to be reportable under 10 CFR50.73(a)(2)(iv)(A), 10 CFR 50.73(a)(2)(v)(C) and 10 CFR 50.73 (a)(2)(ii)(B). The cause of the transformer failure is currently under investigation and will be provided in a supplemental report. This event is classified as an unplanned scram with complications due to the loss of the Division 1 480V power.
|05000461/LER-2017-009||4 January 2018||Clinton Power Station, Unit 1 .|
On November 5, 2017, at approximately 1240 CDT, the Main Control Room (MCR) received numerous annunciators that indicated a trip of the Emergency Reserve Auxiliary Transformer (ERAT) Static VAR Compensator (SVC) caused by a voltage transient on the 138 kV offsite supply. Technical Specification (TS) Limiting Condition for Operation (LCO) 3.8.1, AC Sources-Operating, Required Action A.1 and A.2 were entered. As a result of the voltage transient, the Division 1 Fuel Building ventilation (VF) system isolation dampers closed causing a trip of VF supply and exhaust fans. With no operating VF fans, Secondary Containment (SC) vacuum rose to slightly greater than 0 inches water gauge (WG) at 1241 CDT which exceeded the TS requirement of greater than 0.25 inches vacuum WG. The MCR entered Emergency Operating Procedure (EOP)-8, Secondary Containment Control and TS LCO 126.96.36.199, Secondary Containment, Required Action A.1. The cause of the SC differential pressure becoming positive is that the circuit design of VF is not adequately robust to withstand loss of the 138 kV feed. At the time, the Division 1 safety bus was being fed from the ERAT.
Secondary Containment vacuum was restored within TS requirements at 1242 CDT by starting the Standby Gas Treatment System. A modification will be installed to prevent tripping VF during a momentary loss of power. Installation of a 138 kV Ring Bus is scheduled that is intended to improve the reliability of the radial feed of the 138 kV line. This event is being reported as a condition that could have prevented fulfillment of a safety function under 10 CFR 50.73(a)(2)(v)(C).
|05000461/LER-2017-004||22 November 2017||Clinton||During the Clinton Power Station (CPS) Refueling Outage (C1 R17) on May 12, 2017 at 0045 (CDT), CPS tested its Main Steam Isolation Valves (MSIV) and discovered the as-found leakage for main steam line (MSL) `D' exceeded the Technical Specifications (TS) 188.8.131.52, Primary Containment Isolation Valves, Surveillance Requirement (SR) 184.108.40.206.9 limit placed on an individual MSL and total leakage from all four MSLs. During Modes 1, 2, and 3, TS SR 220.127.116.11.9 requires MSIV leakage for a single MSL to be less than or equal to 100 standard cubic feet per hour (scfh) (47,195 standard cubic centimeters per minute (sccm)) and requires the combined leakage rate for all MSLs to be less than or equal to 200 scfh (94,390 sccm) when tested at 9 psig. The as-found leakage for the 'D' MSL was 53,921.61 sccm for the 'D' inboard MSIV (1 B21 F022D) and 59,698.8 sccm for the 'D' outboard MSIV (1B21F028D). The as-found combined min-path leakage for all four MSLs was 102,463 sccm. An event investigation determined the as found condition of MSIVs 1B21F022D and 1B21F028D did not reveal any damage, only normal wear indications. Thus, the apparent cause for the excessive leakage past all affected MSIVs is expected wear. Valves 1621F028A, 1B21F022D, and 1B21F028D were repaired so that as-left leakage values complied with limits established by TS SR 18.104.22.168.9. This event is reportable due to principle plant safety barriers being seriously degraded, under the provisions of 10 CFR 50.73(a)(2)(ii)(A) and a condition prohibited by TS under 10CFR50.73(a)(2)(i)(B).|
|05000461/LER-2017-007||9 November 2017||Clinton||On June 10, 2017, at 2256 CDT, Clinton Power Station (CPS) experienced a complete loss of the 'A' feedwater (FW) heater string. The operators received numerous FW trouble alarms on FW string 'A' and low pressure heater 1N1B bypass opened (1CB004). The operators entered procedure CPS 4005.01, "Loss of FW Heating," which directs the operators to restore and maintain power at or below the original power level. The operators lowered core flow and inserted all CRAM rods, and then observed that FW temperature had dropped greater than 100°F. As directed by CPS 4005.01, at 2306 hours the reactor mode switch was placed into the shutdown position and procedure 4100.01, "Reactor Scram," was entered. All systems operated as expected following the scram. At 0100 EDT, June 11, 2017; Event Notification 52800 was made. The loss of FW heating transient was caused by a loss of power to Moore trip units caused by a shorted condition on the Moore trip unit associated with the Hi-Hi level in the 4A FW heater. The root cause is that the design of the FW heater level control trip circuitry was not adequate to prevent scrams due to an unevaluated single point vulnerability. Prior to startup, CPS modified the circuit card locations and thereby diversified the power supplies so that the trip units have less dependency on common fuses. Additional corrective actions include performing an engineering evaluation to determine if there are additional single component failures, operator errors, or events for the FW heating system that could result in a drop in FW temperature of greater than 100°F.|
|05000461/LER-2017-005||28 September 2017||Clinton||On May 30, 2017 at 2038 CDT, with the reactor at approximately 28% thermal power Clinton Power Station (CPS) experienced an automatic reactor scram while conducting scram time testing (STT). Plant systems responded as expected and functioned properly following the automatic scram. The automatic scram signal was generated by the Oscillation Power Range Monitor (OPRM) Growth Rate Algorithm (GRA). An evaluation confirmed that the reactor was operating in a very stable core condition and that the event did not occur due to an actual core thermal hydraulic instability. The cause of the event was that the OPRM GRA trip function design is unable to distinguish between plant response to system perturbations and onset of thermal-hydraulic instabilities. Interim actions were implemented to increase operating margin to trip setpoints to support reactor startup and completion of STT. They included a revision to a plant procedure to establish an operating strategy when performing STT in the OPRM enabled region, implementing a monitoring strategy to assess the effectiveness of the operating strategy and monitoring for expected plant response, and raising OPRM Amplitude and GRA set points. Planned corrective actions include working with the industry, as needed, to develop and implement an industry solution for the design of the OPRM GRA to prevent false, spurious trip signals. The automatic scram is reportable under 10 CFR 50.73(a)(2)(iv)(A) as an event or condition that resulted in a manual or automatic actuation of the reactor protection system.|
|05000461/LER-2017-008||11 August 2017||Clinton||On June 15, 2017, Clinton Power Station (CPS) commenced procedure CPS 9069.01, Shutdown Service Water Operability Test. The purpose of this procedure is to verify operability of the Division 3 Shutdown Service Water (SX) System Pump 1SX01PC and selected valves per the Inservice Testing program on a quarterly basis. At 0958, SX pump 1SX01PC was started and after approximately 30 seconds, it tripped due to thermal overload. The pump was declared inoperable and operations entered Technical Specifications (TS) Limiting Condition for Operation (LCO) 3.7.2, Condition A which requires the High Pressure Core Spray (HPCS) system to be declared inoperable and enter TS LCO 3.5.1 Condition B which requires verification by administrative means that the Reactor Core Isolation Cooling (RCIC) system is operable and within 14 days restore the HPCS system to operable status. The cause of the event is under investigation. A supplemental report will be provided when the cause has been established. An ENS notification was made at 1214 (EN 52806). Because the HPCS system is a single train safety system, this event is reportable under 10 CFR 50.73(a)(2)(v)(D) as a condition that could have prevented the fulfilment of a safety function to mitigate the consequences of an accident.|
|05000461/LER-2017-006||1 August 2017||Clinton|
On June 2, 2017, plant personnel were performing welding activities on the 'B' Reactor Water Cleanup System (RT) pump while the plant was in operating Mode 4. The Operations Work Control Supervisor (WCS) had given maintenance personnel authorization to prop both 'B' RT pump room doors open so that welding cables could extend through both doors in support of maintenance activities. The doors are part of the plant secondary containment boundary. Authorization granted by the WCS was executed without utilizing the plant barrier impairment process (PBI) per plant procedures. Prior to the plant's transition to operating Mode 2, Operations personnel made a plant announcement requiring the establishment of primary and secondary containment. The plant then transitioned to operating Mode 2 at 0241. However, both RT Pump 'B' doors remained propped open during the plant mode change.
This condition was discovered by shift personnel at 0300 (CDT) and secondary containment was declared inoperable.
The loss of secondary containment was caused by personnel not following the FBI per plant procedure. Secondary containment was subsequently restored twenty four minutes after discovery of the open 'B' RT doors. Corrective actions taken and planned include implementing management action response checklist (MARC) principles for the responsible supervisor and completing a read and sign for planners and schedulers associated with the PBI process.
|05000461/LER-2017-003||3 July 2017||Clinton||The condition reported by this LER is the result of planned activities in support of Refueling Outage C1 R17 at Clinton Power Station (CPS). As described in the LER, the NRC provided enforcement guidance, applicable to boiling water reactor licensees, that addresses the reported condition. Although this allowance is provided by the NRC's enforcement guidance, the planned activities are still considered reportable in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by Technical Specifications (TS). On May 9 through May 28, 2017 CPS performed Operations with the Potential for Draining the Reactor Vessel (OPDRV) activities while in Mode 5 without an operable Secondary Containment. These activities were performed within the guidelines of NRC Enforcement Guidance Memorandum (EGM) 11-003, Revision 3 which allows the implementation of interim actions as an alternative to full compliance, provided several conditions are met. The OPDRV activities were planned activities that were completed following the guidance of the EGM and are considered to have low safety significance based on interim actions taken. Since these actions were preplanned, no cause determination was necessary. As required by the EGM, a license amendment request was submitted on May 1, 2017 which follows the guidance in Technical Specifications Task Force traveler TSTF-542 which is the agreed-upon generic resolution of this issue.|
|05000461/LER-2017-001||21 April 2017||Clinton||On February 24, 2017 at approximately 2239 hours (CDT), the Main Control Room (MCR) received numerous annunciators which indicated a loss of the 138 kV off-site supply to the Emergency Reserve Auxiliary Transformer (ERAT). The MCR entered Technical Specification (TS) Limiting Condition for Operation (LCO) 3.8.1, AC Sources- Operating, Required Actions A.1 and A.2. The Division 1 Fuel Building ventilation (VF) system isolation dampers closed due to the voltage transient causing a trip of the VF supply and exhaust fans and Secondary Containment (SC) vacuum to rise to slightly greater than 0 inches water gauge (WG), exceeding the TS requirement of greater than 0.25 inches vacuum WG. The MCR entered Emergency Operating Procedure (EOP)-8, Secondary Containment Control, and TS LCO 22.214.171.124, Secondary Containment, Required Action A.1. SC vacuum was restored within TS requirements at approximately 2242 hours by starting the Standby Gas Treatment (VG) system. The Transmission System Operator confirmed that the loss of the 138 kV line was due to a line fault external to the Station. The 138 kV line was successfully re-energized at 0053 hours on February 25, 2017 and the ERAT off-site source was restored and declared OPERABLE at 0300 hours. This event is reportable per 10CFR50.73(a)(2)(v)(C).|
|05000461/LER-2016-010||6 March 2017||Clinton|
On October 14, 2016, Clinton Power Station (CPS) determined subsequent to the 3rd Quarter NRC Exit Meeting that a condition prohibited by Technical Specification (TS) 3.7.6, "Main Turbine Bypass System," had occurred associated with a failure to complete a TS Required Action within the associated Completion Time.
Specifically, testing of Main Steam Turbine Bypass Valve (TBV) Numbers 4, 5, and 6 was not performed within the required test' interval and the TBVs were appropriately declared inoperable as required by TS Surveillance Requirement.(SR) 3.0.1.
Thermal Limit penalties were applied as required by Limiting Condition for Operation (LCO) 3.7.6. A Surveillance Frequency Change was processed in accordance with TS Program 5.5.16, "Surveillance Frequency Control Program," in June 2016 to change the Frequency for SR 126.96.36.199 from 31 days to 12 months. TBVs 5 and 6 were subsequently declared OPERABLE and the thermal limit penalties removed without performing the required SR 188.8.131.52, contrary to TS SR 3.0.1 Bases.
The apparent cause of this event was determined to be that no specific requirement exists in either plant procedures or industry guidance which prohibits declaring a component or system OPERABLE based solely on an extension of the required surveillance test interval. Corrective actions include testing the valves with an alternate method and completing administrative procedure changes. This event is reportable under 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by TS.
|05000461/LER-2016-012||1 February 2017||Clinton|
On December 5, 2016 at 2011 hours during a surveillance test of the Residual Heat Removal (RHR) "C" pump, a Westinghouse DHP Breaker for the RHR "C" pump failed to close. This occurrence resulted in a failure of RHR "C" pump to start. The pump was declared INOPERABLE and Technical Specification (TS) Limiting Condition of Operation (LCO) 3.5.1, "Emergency Core Cooling System -Operating," Required Action A.1 was entered to restore the pump to OPERABLE status in seven days. Performance records indicate the breaker was installed on March 11, 2016 in the RHR "C" pump cubicle and successfully operated on March 11, June 9, and September 6, 2016, prior to failure.
An investigation determined that the breaker latch check switch contacts were not closed and that the latch check switch setting was out of procedural limits. The most likely time that the switch would have become out of adjustment would have been during transport of the breaker to the RHR "C" pump breaker cubicle on March 11, 2016. The apparent cause of the failure was an inadequate verification of the latch check switch setting performed prior to installation of the breaker in the cubicle. Corrective measures have been initiated that include revising plant procedures to record latch check switch adjustment value. The condition described in this report is reportable under 10CFR50.73(a)(2)(i)(B) as an "operation or condition which was prohibited by the plant's Technical Specifications.
|05000461/LER-2016-011||13 January 2017||Clinton||On November 17, 2016, during the NRC Component Design Basis Inspection (CDBI), Clinton'Power Station (CPS) determined that design calculation C-020 "Reanalysis of Loss of Coolant Accident (LOCA) Using Alternate Source Terms," incorrectly took credit for the dual Main Control Room ventilation (VC) supply inlets being single failure proof (SFP). This assumption allowed the calculation to reduce one of the dose terms by a factor of 4 in accordance with the guidance of Regulatory Guide 1.194, "Atmospheric Relative Concentrations for Control Room Radiological Habitability Assessments at Nuclear Power Plants". However, the inlets to VC at CPS are not SFP. This calculational error, when corrected, resulted in a calculated dose of greater than the 5 rem Total Effective Dose Equivalent (TEDE) allowable dose to occupants of the control room. A cause evaluation identified USAR sections that described the VC system were not clear regarding whether the intake structures were SFP. A standing order was issued for compensatory measures in the event of an emergency until calculations were prepared to demonstrate MCR operator dose limits can be met without compensatory measures. Actions have been initiated to finalize the MCR Operator dose analysis assuming single failure of outside air intake dampers and to revise the USAR to indicate that intake structures are not independently SFP. This event is reportable under 10 CFR 50.73(a)(2)(ii)(B), "Any event or condition that results in the nuclear power plant being in an unanalyzed condition that significantly degrades plant safety.|
|05000461/LER-2016-007||15 July 2016||Clinton||On May 17, 2016 with the plant in Mode 4 during Refueling Outage C1R16 personnel entered the drywell to perform a system walkdown. At 0945 CDT water was identified leaking from flexible hoses located at the inner elbows of main steam line (MSL) B and MSL C. It was determined that the leakage was from the flexible hoses associated with the MSL flow instrumentation. The degraded flexible hose on MSL B was previously replaced in 2008 and on MSL C in 2007. An analysis determined the failure mechanism of the degraded flexible hoses as Intergranular Stress Corrosion Cracking (IGSCC). Main Steam Line C flexible hose had previously failed in 2007 due to IGSCC. Corrective actions taken for that event did not prevent a recurrence of the condition identified during C1R16. The leaking flexible main steam line hoses and the remaining flexible hoses on the MSLs B and C were replaced during C1R16. The remaining inner elbow flexible hoses on MSLs A and D have been scheduled for replacement during the next refueling outage C1R17. This condition is reportable under 10 CFR 50.73(a)(2)(ii)(A), as a condition that resulted in the condition of the nuclear power plant, including its principal safety barriers being seriously degraded.|
|05000461/LER-2016-008||15 July 2016||Clinton||The condition reported by this LER is the result of planned activities in support of Refueling Outage C1 R16 at Clinton Power Station (CPS). As described in the LER, the NRC provided enforcement guidance, applicable to boiling water reactor licensees, that addresses the reported condition. Although this allowance is provided by the NRC's enforcement guidance, the planned activities are still considered reportable in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by Technical Specifications (TS). On May 18, 2016 and May 23, 2016, CPS performed Operations with the Potential for Draining the Reactor Vessel (OPDRV) activities while in Mode 5 without an operable Secondary Containment. These activities were performed within the guidelines of NRC Enforcement Guidance Memorandum (EGM) 11-003, Revision 3 which allows the implementation of interim actions as an alternative to full compliance, provided several conditions are met. The OPDRV activities were planned activities that were completed following the guidance of the EGM and are considered to have low safety significance based on interim actions taken. Since these actions were preplanned, no cause determination was necessary. As required by the EGM, a license amendment request will be submitted following NRC approval of the Technical Specifications Task Force traveler associated with generic resolution of this issue.|
|05000461/LER-2013-008||28 June 2016||Clinton|
On 12/8/13 at 2026 hours with the plant in Mode 1 at 97.3 percent reactor power, operators received multiple alarms due to the trip of 4160 volt 1A1 breaker which resulted in a loss of power to two Division 1 480 volt unit substations.
Operators were immediately dispatched and found a 4160/480 volt stepdown transformer failed. Many Division I components lost power. The loss of power caused an instrument air (IA) containment isolation. The loss of IA affected various containment loads, including the scram pilot air header, the main steam isolation valves and the reactor water cleanup system. At 2036 hours, the scram pilot air header low pressure alarm was received, and in response to an anticipated automatic reactor scram, operators immediately initiated a manual reactor scram. All control rods fully inserted into the core. Reactor pressure vessel water level dropped to the low reactor water level 3 setpoint (normal result of a scram from high power) and operators entered the Reactor Pressure Vessel Control Emergency Operating Procedure. The most probable cause of the transformer failure was a tum to turn failure of the high side windings due to insulation breakdown over time, prior to its expected end of life. An installed spare was connected to replace the failed Division 1 transformer.
|05000461/LER-2016-006||10 June 2016||Clinton||On April 21, 2016, in preparation to reduce power in order to restore the `B' turbine driven reactor feed pump (TDRFP) Operations detected that Technical Specification (TS) Surveillance Requirement (SR) 184.108.40.206.2 had not been performed eight days earlier. On April 13, 2016 Operations lowered reactor power below the Control Rod Withdrawal Limiter (RWL) High Power Setpoint (HPSP) to remove 'B' TDRFP from service due to high vibrations. TS SR 220.127.116.11.2 requires a functional test of the 4-Notch Control Rod Withdraw Limit of the RWL within one hour of resetting the HPSP during a power reduction; if it has not been completed within the previous 92 days. The SR was last performed on April 26th, 2015 and was required to be performed on April 13, 2016. TS 18.104.22.168 Required Action A.1 requires with one or more RWL channels inoperable, to immediately suspend control rod withdrawal. Contrary to this requirement, control rods were withdrawn to restore power above the HPSP following restoration of the 'B' TDRFP to service. The cause of the event was that the SRO responsible for the down power on April 13, 2016 did not validate, by preventative maintenance identifier (PMID), that the required surveillance was current. Corrective actions included applying Management Associated Results Company, Inc. (MARC) principles to the individuals involved.|
|05000461/LER-2016-005||31 May 2016||Docket-Number|
|On April 2, 2016, at approximately 1257 CDT the Main Control Room (MCR) received numerous annunciators that indicated a trip of the Reserve Auxiliary Transformer (RAT) and associated Static VAR Compensator (SVC). The MCR entered Technical Specification (TS) Limiting Condition for Operation (LCO) 3.8.1, AC Sources-Operating, Required Actions A.1 and A.2. The Division 1 Fuel Building ventilation (VF) system isolation dampers closed due to loss of power causing a trip of VF supply and exhaust fans. With the VF fans inoperable, Secondary Containment (SC) vacuum rose to slightly greater than 0 inches water gauge (WG) which exceeded the TS requirement of greater than 0.25 inches vacuum WG. The MCR entered Emergency Operating Procedure (EOP)-8, Secondary Containment Control, and TS LCO 22.214.171.124, Secondary Containment, Required Action A.1. SC vacuum was restored within TS requirements at 1300 by starting the Standby Gas Treatment (VG) system. The RAT was successfully returned to service following replacement of the broken 'A' phase insulator stack on the 345 kV Circuit Switcher 4538. The cause of this event was identified as the failure of the 'A' phase 4538, 345 kV Circuit Switcher insulator due to a manufacturing defect. The corrective actions included performing a risk review of all Ohio Brass Insulators for potential failure impact and creating a replacement strategy to replace the high risk and critical insulators. Replacement of the remaining Ohio Brass insulators in the switchyard will be completed by the end of C1R17.|
|05000461/LER-2016-004||27 May 2016||Clinton||On March 30, 2016, at approximately 1545 CDT, the Main Control Room (MCR) received numerous annunciators that indicated a trip of the Emergency Reserve Auxiliary Transformer (ERAT) Static VAR Compensator (SVC) caused by a voltage transient on the 138 kV supply. Technical Specification (TS) Limiting Condition for Operation (LCO) 3.8.1, AC Sources-Operating, Required Action A.1 and A.2 were entered. As a result of the voltage transient, the Division 1 Fuel Building ventilation (VF) system isolation dampers closed causing a trip of VF supply and exhaust fans. With no operating VF fans, Secondary Containment (SC) vacuum rose to slightly greater than 0 inches water gauge (WG) which exceeded the TS requirement of greater than 0.25 inches vacuum WG. The MCR entered Emergency Operating Procedure (EOP)-8, Secondary Containment Control and TS LCO 126.96.36.199, Secondary Containment, Required Action A.1. The likely cause of the voltage transient on the 138 kV line was a lightning strike that occurred during thunderstorms in the area on the day of the event. SC vacuum was restored within TS requirements at 1550 CDT by starting the Standby Gas Treatment System. Corrective actions have been initiated to improve reliability of the 138 kV source. This event is being reported as a condition that could have prevented fulfillment of a safety function under 10 CFR 50.73(a)(2)(v)(C).|
|05000461/LER-2016-003||23 May 2016||Clinton|
On March 24, 2016, it was determined that placing both Reactor Water Cleanup System (RT) Leak Detection System (LD) bypass switches in the Bypass position per plant procedure when the RT Filter/Demineralizer (F/D) was placed in service following backwash and pre-coat operations on- January 25, 2016 was a reportable condition. Both divisions of the RT LD were bypassed for seven minutes. Backwashing and pre-coating a RT F/D is a normal system operation and not considered maintenance.
A review of the Updated Safety Analysis Report (USAR) determined that the associated isolation functions are credited to mitigate the consequences of an RT pipe break accident described in USAR Chapter 6. Therefore, placing both divisions of RT LD in Bypass constituted a condition that could have prevented the fulfillment of the safety function of a system that is needed to mitigate the consequences of an accident. The direction for bypassing the RT LD system had been included in procedures since 1989 but did not constitute a reportable event until the issuance of NUREG-1022, Rev. 3 in 2013. The failure to report this condition was caused by not revising plant procedures when the Exelon fleet reporting requirements were revised to align with NUREG-1022, Rev. 3.
|05000461/LER-2016-002||13 April 2016||Clinton|
On 02/13/2016 at 0206 (CST) the plant was at 99 percent reactor power when Fuel Building Exhaust Fan "A" (1VFO4CA) tripped due to indicated high Secondary Containment (SC) vacuum during routine venting of the drywell per plant procedures. Following the fan trip, SC vacuum degraded, eventually exceeding the Technical Specification (TS) limit of 0.25 inch vacuum water gauge. The TS Limiting Condition for Operation (LCO) 188.8.131.52 Required Action A.1 and an Emergency Operating Procedure were entered. Plant Operations subsequently started the Standby Gas Treatment System (VG) and restored Secondary Containment within TS limits. An investigation determined that ice formed in the sensing line causing an inaccurate Secondary Containment vacuum reading on the indication and control loop for 1VFO4CA. This caused 1VFO4CA to trip which in turn led to a loss of Secondary Containment vacuum. A cause evaluation established that prior instrument sensing line designs did not recognize the potential to trap water in the sensing line to the Secondary Containment pressure instrumentation. Corrective actions will include completing an engineering change to install an alternate Fuel Building Ventilation (VF) system sensing line design to prevent moisture accumulation line to ensure accurate indication and control of Secondary Containment pressure.
This event is reportable under 10 CFR 50.73(a)(2)(v)(C).
|05000461/LER-2016-001||18 March 2016||Clinton||On January 20, 2016 at 1311, during planned clean and inspect maintenance activities on the 4160/480 Volt Unit Substation K (0AP52E), the Unit Substation K switchgear breaker OAP52E-5D for Continuous Containment Purge (CCP) exhaust fan "A" was racked out which resulted in tripping off the CCP "B" exhaust fan. This event caused Clinton Power Station (CPS) to enter one hour Required Action A.1 under Technical Specifications (TS) Limiting Condition for Operation (LCO) 184.108.40.206, Primary Containment Pressure, due to primary to secondary containment differential pressure being greater than +0.25 psid. Operations staff took appropriate actions to rack in breaker OAP52E-5D to restart CCP "B" exhaust fan, restore primary to secondary containment differential pressure within limits at 1339. Event Notification #51669 was transmitted to the NRC on January 20, 2016 at 1731. The root cause of this event is the station did not validate assumptions resulting in an inadequate work package. Corrective actions include updating the maintenance planning checklist, performing a read and sign and presenting a case study to maintenance planning personnel on this event. This event is reportable under 10 CFR 50.73(a)(2)(ii)(B) as an unanalyzed condition and 10 CFR 50.73(a)(2)(v)(D) as a condition that could have prevented fulfillment of a safety function.|
|05000461/LER-2015-001||7 April 2015||Clinton||On 2/6/15 at 2300 CST, the Division 1 Reactor Water Cleanup (RT) system differential flow indicator (1E31R614A) was observed to be reading greater than 10 gallons per minute (gpm) different from its sister channel, resulting in it failing its channel check. Operators declared this instrument inoperable in accordance with Clinton Power Station Technical Specification (TS) 220.127.116.11, Primary Containment and Drywell Isolation Instrumentation, requiring placing the channel in trip within 24 hours per Required Action D.1. At 2355, the Division 2 RT differential flow indicator (1E31R614B) indicated out of specification, requiring entry into Required Action E.1 for two channels inoperable. With both channels inoperable, the leakage detection system was incapable of performing its containment isolation function for RT differential flow. At 0036 on 2/7/15, a fill and vent of the Division 1 RT leak detection instrumentation was completed, restoring Division 1 to an operable status. At 0225 on 2/7/15, a fill and vent of the Division 2 RT leak detection instrumentation was completed, restoring Division 2 to an operable status. An eight-hour ENS notification (#50794) was made at 0637 CST in accordance with 10CFR50.72(b)(3)(v)(C). This event is also reportable under 10CFR50.73(a)(2)(v)(C).|
|05000461/LER-2014-002||22 May 2014||Clinton||On 3/25/14 the plant was in Mode 1, steady state at 85 percent reactor power. Operators in the Main Control Room (MCR) observed Offgas (OG) flow rate lowering, condenser vacuum lowering, and condensate water temperature rising. The 13' Steam Jet Air Ejector (SJAE) was in service at the time. As condenser vacuum lowered from 29 inches Mercury (Hg) to 27.4 inches Hg, Operators entered the Loss of Vacuum off-normal procedure and commenced a rapid power reduction. While reducing power, the MCR team began preparations to place the 'A' SJAE in service. At 1942 hours with Reactor power at 46 percent and vacuum at 24 inches Hg and lowering, Operators placed the Mode Switch in shutdown. All control rods were fully inserted. The plant responded as expected with no complications. No safety systems actuations occurred nor were required to place the plant in a safe and stable condition. The cause for this event is unstable pressure control of B SJAE due to a system resonance or instability. The root cause of the system resonance is indeterminate at this time pending additional testing. Corrective action for this event includes replacing the SJAE pressure controller and developing a comprehensive test plan that will dampen or eliminate the system resonance.|
|05000461/LER-2014-001||20 March 2014||Clinton|
|05000461/LER-2013-009||10 February 2014||Clinton||On 12/13/13 the plant was in Mode 1 at 18 percent reactor power with power ascension in progress. Operators were transitioning from the Motor Driven Reactor Feed Pump (MDRFP) to the 'A' Turbine Driven Reactor Feed Pump (TDRFP). Operators opened the 'A' TDRFP Discharge Valve and placed the 'A' TDRFP Recirculation Valve in Automatic, which positioned the recirculation valve to 25% open. When the `A' TDRFP began to feed, the MDRFP began to reduce flow as designed. Over the next few minutes, flow from the two feed pumps began to fluctuate, and reactor water level began to oscillate outside the normal control band. Operators recognized the level swings were growing in amplitude and took manual control of the MDRFP flow control valve (FCV). At this time, the speed of the 'A' TDRFP increased causing an increase in Reactor Water Level. As reactor water level approached the high Level 8 trip set point, operators placed the Reactor Mode Switch into the Shutdown position, initiating a manual scram. The cause for this event is errors in the recently installed digital feedwater control system software. The installed digital feedwater programming will be revised to correct the identified software errors. Interim actions were taken to revise operating procedures.|
|05000461/LER-2013-007||27 December 2013||Clinton|
On 10/28/13, reactor startup was in progress. At 2100 hours, reactor coolant temperature was 156 degrees Fahrenheit (F) and the reactor was at the point of adding heat. During this startup, the main steam isolation valves (MSIVs) could not be opened, as planned, due to the Main Steam Lines being full of water following the RPV pressure test and RPV temperature and pressure continued to rise. Operators attempted to slow the heatup by inserting a control rod, but were unsuccessful. At 2130 hours, the Shift Manager (SM) was notified of the heatup trend and that the reactor coolant temperature had increased by about 111 degrees F over a one-hour period. The SM determined the reactor pressure vessel (RPV) metal temperatures recorded on the log were still well under a rate of change of 100 degrees F per hour. The SM incorrectly applied the Technical Specification (TS) requirement for RPV coolant heatup as he applied this limit to the rate of change of metal temperatures. As a result, the TS required actions, including a requirement to complete a review for continued operation, were not entered or completed for exceeding the coolant heatup rate of 100 degrees F per hour.
This error was identified on 11/1/13 during a review of the heatup logs. The cause of the failure to enter the appropriate TS was the SM did not reference the available guidance for acceptance criteria.
|05000461/LER-2013-006||11 December 2013||Clinton||The condition reported by this LER is the result of planned activities in support of Refueling Outage C1 R14 at Clinton Power Station (CPS). As described in the LER, the NRC provided enforcement guidance, applicable to boiling water reactor licensees, that allows the reported condition. Although this allowance is provided by the NBC's enforcement guidance, the planned activities are still considered reportable in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by Technical Specifications (TS). Between 10/13/2013 and 10/27/2013, CPS performed Operations With the Potential For Draining the Reactor Vessel (OPDRV) activities while in Mode 5 without an operable secondary containment, as expected and allowed by NRC Enforcement Guidance Memorandum (EGM) 11-003, Revision 1. The EGM allows the implementation of interim actions as an alternative to full compliance; however, this condition is still considered a condition prohibited by TS 18.104.22.168. The OPDRV activities were planned activities that were completed following the guidance of the EGM and are considered to have low safety significance based on interim actions taken. Since these actions were deliberate, no cause determination was necessary. A license amendment request will be submitted following NRC approval of the Technical Specifications Task Force traveler associated with generic resolution of this issue.|
|05000461/LER-2013-005||18 November 2013||Clinton||On September 20, 2013, a self assessment of the Clinton Power Station fire protection program identified a potential noncompliance with License Condition 2.F due to the inability to achieve safe shutdown in the event of a fire in Zones CB-1 e, CB-1f, CB-2, and CB-4. Circuit failure analysis and post-fire recovery guidance for the Diesel Generator (DG) room ventilation system were found to be technically incorrect, rendering the DG room ventilation systems unable to be restored for certain fire scenarios that credit them. Fire-induced circuit failures could inadvertently actuate the DG carbon dioxide (CO2) fire suppression system, which send a maintained-trip signal to the associated DG room ventilation system. The Safe Shutdown Analysis for this scenario directs operators to restart the fans from the main control room (MCR). However, this action will not bypass the CO2 trip signal to the fans, thus the affected DG unit(s) may eventually fail due to high room temperatures. This condition is reportable under 10 CFR 50.73(a)(2)(ii)(B) as an unanalyzed condition that significantly degraded plant safety. The cause of this event was determined to be an historical error that occurred in 1998. Plant procedures have been revised to direct operators to remove a fuse located in a MCR panel to enable the trip logic to be bypassed should a fire occur outside the DG rooms.|
|05000461/LER-2013-003||24 June 2013||Clinton||On 4/26/13, with the plant at 97 percent power, the Main Control Room received a Main Electro-Hydraulic Control (EHC) pressure alarm due to lowering level in the EHC Oil Reservoir. An operator reported Main EHC Oil Reservoir level was at minus 4.25 inches and rapidly lowering. In response, Operators initiated a manual reactor SCRAM. All control rods fully inserted and the plant responded as expected to the SCRAM. The EHC oil leak was caused by a broken socket head cap screw used to attach a hydraulic shutoff valve to a Main Steam Turbine Control Valve and three remaining cap screws were loose, with one slightly bent. The faulty shutoff valve was replaced, properly torqued, and the EHC system was pressurized to verify it was free of leaks. The bolting torque was verified to be proper for all hydraulic shutoff valves for control valves, stop valves, and intermediate valves. The most probable cause for this event is inadequate work instructions that led to failure to install appropriate lock washers on the shutoff valve connection, resulting in cap screws becoming loose and ultimately failing due to fatigue. Corrective action includes correcting work instructions, initiating work orders to install lock washers on hydraulic shutoff valves, and ensuring the bill of materials in model work orders specifies the appropriate lock washers for the application.|
|05000461/LER-2013-002||2 May 2013||Clinton||On 3/7/13, at 0756 hours, the main generator tripped followed by a main turbine trip and an automatic reactor SCRAM at 0758 hours. A troubleshooting team was immediately dispatched to investigate the cause of the event and found that a fuse was blown/open on the C phase of the main generator's voltage regulating potential transformer (PT). This fuse is designed to fast blow. A voltage balance relay is installed to sense a fast blow failure and prevent a generator trip. Investigation found that the fuse did not fast blow and instead degraded gradually and did not allow the voltage balance relay to detect a problem, thus the relay did not prevent the main generator trip and subsequent SCRAM. A failure analysis of the fuse identified that the cause of the C phase potential transformer fuse failure was a manufacturing defect in a solder connection in the fuse. The poor solder connection was caused by deficiencies in the manufacturing process. Corrective actions include replacing the fuse that failed with a fuse that was not manufactured at the affected facility. An evaluation is being performed to determine when to inspect and replace the population of other potentially affected fuses.|
|05000461/LER-2013-001||17 April 2013||Clinton||On 2/18/13, the Division 4 Nuclear System Protection System (NSPS) inverter transferred to its alternate power source. Instrument maintenance technicians were performing a surveillance when a technician inadvertently dropped a test cable and connector. The cable connector swung down and by pendulum motion went under a robust operational barrier in the cabinet coming in contact with the bottom edge of a fuse block staple jumper. The momentary shorting to ground caused the Division 4 NSPS bus to transfer from its normal inverter power source to its alternate power source. Per Technical Specifications (TS), the NSPS is inoperable when powered by its alternate source. With the NSPS inoperable, per the TS, operators declared the High pressure Core Spray System, a single train safety system, inoperable and reported the condition as a loss of safety function. The cause of this event was an inadequate risk identification related to pendulum motion of the cable connector during jobsite planning and set up for the job. Corrective actions include an Instrument Maintenance Department stand down, use of a checklist to aid in challenging jobsite conditions for risk/hazards assessment and management observations, and a case study of this event for Maintenance personnel. There were no safety consequences; the HPCS was capable of initiating with the operable Division 3 NSPS inverter.|
|05000461/LER-2012-002||27 November 2012||Clinton|
At 1212 on March 1, 2012, the Division 1 Emergency Diesel Generator (EDG) was started for monthly surveillance testing. At 1215, Operators in the EDG room reported a lack of expected air flow in the room.
The EDG Room supply air fan automatically started as expected, as evidenced by Main Control Room (MCR) and field indications. Investigation found the supply damper-to-hydramotor coupling disconnected, resulting in the supply damper remaining in the closed position. The cause of the event was a failure to ensure the lock nut on the coupling was sufficiently tightened during the previous hydramotor replacement.
Corrective action taken was to revise a site procedure to include supervisory oversight on the assembly of the coupling and allow the use of an engineered adhesive (i.e., Loctite®) for coupling lock nuts.
The Division 1 EDG was previously run for a monthly surveillance test on January 25, 2012 with no problems noted. This date is the last date for which there is firm evidence that the supply air damper coupling was connected, had a demand occurred. Therefore, this event is being reported as a condition prohibited by Technical Specifications (TS) due to the EDG being inoperable for a period of time that greater than allowed by TS per 10 CFR 50.73(a)(2)(i)(B). This event is also being reported as a condition that could have prevented the fulfillment of a safety function per 10CFR 50.73(a)(2)(v)(B) due to the Division 2 EDG being inoperable for a period of the time the Division 1 EDG was inoperable.
|05000461/LER-2011-008||6 August 2012||Clinton||On 12/18/11, the plant was in Cold Shutdown conducting restoration activities following the Reactor Pressure Vessel (RPV) hydrostatic pressure test. While lowering RPV water level to a target level, a low RPV water level (Level 3) reactor protection system actuation occurred resulting in a residual heat removal (RHR) system isolation, and a subsequent loss of shutdown cooling. RPV water level was immediately restored above the Level 3 setpoint using the control rod drive system. Operators reset the RHR isolation logic within minutes of the scram signal, and shutdown cooling was fully restored in 26 minutes. Reactor coolant temperature increased approximately three degrees Fahrenheit during this event. The causes of this event were lack of rigorous process controls while removing and installing the permanent shutdown and upset level instruments reference leg pipe and not having an alternate for shutdown range level indication to allow monitoring reactor water level during times when the shutdown and upset level instruments are not in service. Corrective actions include revising the procedure to control the entire evolution of shutdown and upset level instruments reference leg pipe reassembly and recovery of vessel level indication, and developing an alternate method for determining RPV level during shutdown conditions.|
|05000461/LER-2011-009||11 April 2012||Clinton|
On December 1, 2011, with the reactor shutdown for refueling outage, an as-found Leak Rate Test (LRT) was performed for Residual Heat Removal "A" Reactor Pressure Vessel Isolation check valve 1E12-F041A. In accordance with the station reactor coolant system pressure isolation valve testing program this as-found test was required to be performed. The recorded leakage for the as-found LRT was not within acceptable limits due to the testing sequence of other system valves unseating 1E12-F041A prior to testing.
Following performance of procedure CPS 9053.05, RHR/LPCS Valve Operability (Shutdown), which stroked the valve with no additional closing force applied, the as-left LRT was completed with satisfactory results.
On February 13, 2012, during review of the performance of the LRT, a question arose regarding if stroking of the valve was acceptable preconditioning. A subsequent evaluation of this activity concluded that stroking of the valve was unacceptable preconditioning.
February 13, 2012, is used as the discovery date for this LER based on a review of the performance of the LRT that questioned if the valve was preconditioned prior to as-found testing.
|05000461/LER-2011-007||27 January 2012||Clinton|
During a Clinton Power Station (CPS) review of an event at the Browns Ferry Station (ENS 47374), CPS determined that the original plant wiring design for the station battery ammeter circuits contains a shunt in the current flow from each direct current (DC) battery. Bolted onto the shunt bar are two Institute of Electrical and Electronics Engineers (IEEE) IEEE-383 qualified leads to an ammeter in the main control room (MCR). The small difference in voltage between the two taps on the shunt is enough to deflect the current meter in the MCR when current flows from the battery through the shunt. The ammeter wiring attached to the shunt does not have fuses, and if one of the ammeter wires shorts to ground at the same time another DC wire from the opposite polarity on the same battery also shorts to ground, a ground loop through the unfused ammeter cable could occur. With enough current going through the cable, the potential exists that the overloaded ammeter wiring could damage safe shutdown wiring in direct physical contact with the cable resulting in a loss of the associated safe shutdown function/capability.
The cause of this deficiency is the original design criteria not specify protection for shunt fed ammeter circuits. A modification is planned to correct the deficiency. Compensatory measures have been established until the modification has been installed.
|05000461/LER-2011-006||26 January 2012||Clinton|
On December 7, 2011, Clinton Power Station (CPS) was in Mode 5 (Refueling) for refueling outage Cl R13. During leakage testing of Reactor Coolant System Pressure Isolation Valve (PIV), 1E12-F042C, Low Pressure Coolant Injection from Residual Heat Removal C Shutoff Valve, was performed in accordance with Technical Specification (TS) Surveillance Requirement (SR) 22.214.171.124. This test was performed in accordance with SR 3.0.3 to address a missed surveillance that was discovered on April 7, 2011. During the test, the valve would not pressurize due to the amount of water passing through the seat at low pressure. The test pressure for the surveillance test is 1000 to 1025 pounds per square inch gauge. Since the valve would not pressurize, the leakage was determined to be in excess of the specified leakage criteria of five gallons per minute and was declared an as-found failure.
The valve repair team identified wear on the guide ribs and excessive disc to rib clearances, which appeared to be original dimensional tolerances rather than recent wear. Engineering determined the cause of the as-found failure was that the disc became cocked during closing causing the valve to not fully seat. Corrective actions included repairing the valve and retesting the valve with satisfactory results.
|05000461/LER-2011-005||24 January 2012||Clinton|
On December 1, 2011, with the reactor shut down for refueling, an as-found Local Leak Rate Test (LLRT) was performed for Reactor Core Isolation Cooling turbine exhaust check valve 1E51-F040. The station primary containment leakage rate testing program which implements the requirements of 10 CFR 50, Appendix J, requires an as-found test to be performed prior to a scheduled maintenance activity to open and inspect the valve. The recorded leakage for the as-found LLRT was within acceptable limits. A step in the test procedure establishing the test lineup required the valve to be stroked open and shut by normal means.
A subsequent evaluation concluded that the pre-test stroking was unacceptable preconditioning; therefore, the as-found LLRT was invalid and considered to be a missed surveillance and a condition prohibited by Technical Specification 126.96.36.199. The test procedure incorrectly required the preconditioning and caused this event. Corrective actions include revising the test procedure and reviewing other similar check valve test procedures to determine the extent of this condition. An analysis to determine the actual impact of the valve stroke concluded that the preconditioning, although unnecessary to establish the test conditions, would have had little actual influence on the as-found test results.
|05000461/LER-2011-004||12 January 2012||Clinton||On November 29, 2011, with the reactor at 16.1 percent thermal power, Operators were reducing generator load to 50 Megawatts in order to trip the Main Turbine to start refueling outage C1R13. Turbine Bypass Valve (BPV) #1 had begun opening and was approximately 8 percent open when it ramped closed contrary to system demand. A Steam Bypass Control Pressure Regulator error alarm was received in the Main Control Room. Due to the loss of the steam flow path through the bypass valve to the Main Condenser, Reactor Pressure Vessel (RPV) pressure began to increase and subsequently reached the high reactor pressure scram setpoint resulting in an automatic reactor scram. Reactor pressure control was established manually utilizing the Steam Bypass Valve opening jack. Troubleshooting determined that BPV #1 closed due to failure of a Bypass Valve Demand (BVD) card in the Steam Bypass and Pressure Control (SBPC) System causing RPV pressure to increase. The cause of this event is attributed to the failure to replace or refurbish the BVD card prior to it failing. Corrective actions include replacement of both the A and B BVD cards, establishment of periodic preventive maintenance for the cards, and performing an extent of condition review for other cards in the SBPC system.|
|05000461/LER-2011-002||22 July 2011||Clinton|
On 5/23/11, Operators in the Main Control Room (MCR) noticed a change in noise levels originating from ventilation equipment outside the MCR. Investigation revealed the increased noise was from the MCR (VC) B Return Fan.
Vibration readings on the fan assembly were in the alert range, but not in the shutdown range.
Vibration readings were taken over an 8-hour period after the increase in vibration was noted. During that time, vibration levels remained constant. All other MCR Ventilation parameters for the VC B train were normal and unchanged. After this run, VC B train was placed in standby and VC A train was placed in service. An operability evaluation was completed for VC B which concluded VC B was operable.
On 6/7/11, an inspection of the fan was performed. The inspection identified a crack in the fan hub. A new fan was installed and the system was restored to an operable status on 6/10/11.
The fan hub was sent offsite for failure analysis, which concluded that the crack was the result of end-of-life fatigue, caused by low stress, high cycle loading. Analysis concluded that the hub assembly could not support the ability of the fan to perform its specified safety function over the designed mission time of 30 days, and thus the fan was inoperable.
The VC A system was operable during this period; therefore, no loss of safety function occurred during the period of inoperability.
|05000461/LER-2010-003||21 February 2011||Clinton||On 3/15/10, during full power operations, Division 2 Drywell Ventilation and Drywell Cooling Primary Containment Isolation Valves (PCIVs) closed for isolation Groups 11 and 17 and shunt trip devices for the breakers of several components were tripped. The actuations were a result of a Division 2 load driver card that spuriously actuated its loads without a valid Loss of Coolant Accident signal or a manual initiation signal present. This event was reported to the NRC by Event Notification 45901 on 5/5/10. The cause of the card failure could not be determined at the time; however during a recent investigation performed following further spurious actuations of Division 1 that occurred between 8/24/10 and 8/26/10, it was determined that the 3/15/10 event was most likely caused by degradation of the Division 2 Self Test System (STS) power supply, resulting in the misoperation of the Nuclear Systems Protection System (NSPS) load driver card. The cause of this event is that the STS has a design deficiency related to its power supplies and NSPS has a design deficiency related to its load driver cards which do not allow the STS to meet its design specification when a power supply is degraded. Corrective action for this event includes replacing STS power supplies with low voltage protection and presenting options for the STS issues to the Plant Health Committee for approval.|
|05000461/LER-2010-001||26 January 2011||Clinton||On October 7, 2009, an unanalyzed leakage pathway affecting the flooding analysis associated with a postulated piping break in the Residual Heat Removal (RHR) A pump room was discovered involving a drain line connecting the RHR A pump room to the radwaste pipe tunnel leading outside secondary containment. Actions were taken on October 8, 2009, to permanently plug the line to eliminate this pathway. This as-found condition had the potential, given a postulated pipe rupture of the RHR A pump suction line, to drain the suppression pool until the level was below the lowest level assumed in the accident analysis. This condition resulted in the plant being in an unanalyzed condition that significantly degraded plant safety and could have prevented the fulfillment of the safety function of the emergency core cooling system. The cause of this event was determined to be a historical design oversight during plant construction that allowed the RHR A pump room floor drains to be connected to the radwaste pipe tunnel.|
|05000461/LER-2008-003||23 August 2010||Clinton||On 1/28/08, primary containment local leak rate test (LLRT) performed on feedwater check valve, 1B21-F032A, exceeded acceptance criteria. Technical Specification (TS) Surveillance Requirement (SR) 188.8.131.52.11 requires that the combined leakage rate for both primary containment feedwater penetrations to be less than or equal to 2 gallons per minute (gpm) for the worst of the isolation valves. The measured leakage rate for 1B21-F032A was reported to be 3.75 gpm. Following the identification of the excessive leakage, an internal inspection of the valve was performed and the disc and seat conditions were found satisfactory. The air actuator was stroked with the top of the valve removed and was found not stroking consistently and evenly. The air actuator linkages were cleaned and lubricated resulting in the disc seating properly. The LLRT was performed with satisfactory results on 1/26/08, prior to plant startup. The cause of check valve 1B21-F032A failing leak rate testing is considered to be age-related degradation of lubrication causing increased friction in the actuator. Corrective action includes establishing preventive maintenance activities to lubricate and overhaul the actuators. Reportability of this event was not discovered until 3/24/10 during review of the cause evaluation for another LLRT failure.|
|05000461/LER-2010-002||23 August 2010||Clinton|
On February 3, 2010, after entering Mode 2 (Startup) following refueling outage C1R12, it was discovered that a primary containment local leak rate test (LLRT) performed on feedwater check valve, 1B21-F032B, exceeded its acceptance criteria. Technical Specification (TS) Surveillance Requirement (SR) 184.108.40.206.11 requires that the combined leakage rate for both primary containment feedwater penetrations to be less than or equal to 2 gallons per minute (gpm) for the worst of the isolation valves. The measured leakage rate for 1B21-F032B was reported to be 2.5 gpm. This leakage rate is greater than that assumed in the plant safety analysis.
The unit was placed in Mode 4 (Cold Shutdown) to repair the valve and to re-perform the LLRT. After lubricating the valve actuator and stroking the check valve, the LLRT was performed to confirm the valve could meet its safety function for the Feedwater Leakage Control System (FWLCS). Following the satisfactory completion of the LLRT, plant startup was re-commenced on February 4, 2010.
The cause of the 1B21-F032B.check valve to fail its leak rate test was age-related degradation of the lubrication causing increased friction in the actuator.
Corrective action for this event includes establishing preventive maintenance activities to lubricate and overhaul the actuators.
|05000461/LER-2007-001||20 August 716 JL||Clinton|
On February 7, 2007, the Nuclear Regulatory Commission (NRC) issued a White Finding and Notice of Violation, for failure to select an appropriate method for calculating the minimum elevation (i.e., the analytical level) of water above the high pressure core spray (HPCS) pump suction line to preclude vortex formation and subsequent air entrainment in the pump's suction. The finding identified that prior to August 12, 2006, the initiation of suction transfer from the reactor core isolation cooling (RCIC) water storage tank to the suppression pool, as derived by calculation, may not prevent significant air entrainment in the suction of the HPCS pump and subsequent loss of function of the HPCS pump. As a result, the analytical level could have resulted in significant air entrainment potentially causing the HPCS system to be incapable of completing its safety function. A root cause evaluation determined that the cause of this event was the failure to adequately evaluate the uncertainties and associated margins in the calculation used to determine the suction transfer point.
Corrective action for this event includes installation of a plant modification to increase the submergence of the suction piping in the RCIC water storage tank to preclude possible vortex formation and air entrainment. This modification was installed August 12, 2006.
NRC FORM 366 (6-2004) PRINTED ON RECYCLED PAPER