|Report date||Site||Event description|
|05000298/LER-2016-008||5 January 2017||Cooper|
On November 8, 2016 at 11:27 hours, Cooper Nuclear Station (CNS) declared Reactor Core Isolation Cooling (RCIC) inoperable for surveillance testing and entered Technical Specification (TS) Limiting Condition for Operation (LCO) 3.5.3, Condition A. Subsequently at 11:41 hours, RCIC was declared inoperable due to a water leak from the lube oiler cooler lower flange.
During investigation it was determined that valve RCIC-AOV-PCV23, which was replaced during Refueling Outage 29, was full open causing excessive cooling water pressure to the lube oil cooler. This valve regulates cooling water to the lube oil cooler. Initial examination revealed that the actuator was purchased with a closed travel stop instead of the required open travel stop. The work order was revised to fabricate and install an open travel stop. On November 10, 2016, following valve modification, RCIC passed surveillance testing, was declared operable, and TS LCO 3.5.3, Condition A, exited.
To prevent recurrence, CNS will revise the material master purchase order text to state that the valve includes a travel stop in the open direction to limit valve travel. In addition, the drawing will be modified to show the correct travel stop with a note emphasizing the design function of the travel stop.
|05000298/LER-2016-006||19 December 2016||Cooper|
On October 23, 2016, while conducting refueling and Operations with a Potential for Draining the Reactor Vessel activities, Control Room Emergency Filter System (CREFS) Supply Fan A (SF-C-1A) experienced high vibration. A vibration analysis was performed and results indicated that vibration readings were elevated across all points for the motor and fan. Consequently, Operations declared CREFS inoperable at 19:08 hours. At 19:53 hours, SF-C-1B was started, CREFS was transferred to the alternate supply, and SF-C-1A was secured. At 23:41, Event Notification 52315 was made to the Nuclear Regulatory Commission Operations Center.
The fan was repaired on October 24 and 25, 2016, and a vibration analysis was performed on October 26, 2016, with satisfactory results. Operations declared CREFS operable at 1341 on October 27, 2016.
The root cause was the preventive maintenance strategy for the fan was ineffective to ensure shaft to bearing engagement is maintained. To prevent recurrence, the applicable maintenance plan will be revised to include verification that the bearings are adequately engaged to the fan shaft.
This is a Safety System Functional Failure.
3. LER NUMBER 2. DOCKET NUMBER 05000- 298 Cooper Nuclear Station -00 2016 - 006
|05000298/LER-2016-004||22 November 2016||Cooper|
On September 24, 2016, at 20:40 hours, during reactor cooldown for Refueling Outage 29, Cooper Nuclear Station control room operators closed the inboard Main Steam Isolation Valves (MSIV) to minimize steam flow to control the reactor cooldown rate. Reactor pressure was controlled using the Main Steam Line Drains; and the condensate/feed system was available for reactor water level control.
On September 25, 2016, at 01:03 hours, while equalizing pressure across the MSIVs to below 200 psid, a differential pressure of 190 psid was established. Upon opening MS-AO-80A, a Group 1 isolation was immediately received due to a Main Steam Line high flow signal. The control room operators subsequently equalized pressure and successfully opened MS-AO-80A, as well as the remaining MSIVs, at 18:52 hours.
The cause of the event was insufficient procedure guidance exists regarding limitations on opening the MSIVs. To correct this, the applicable procedure has been revised to change the differential pressure limitations for opening MSIVs from 200 psid to 80 psid.
The safety significance of the event is low and did not pose a threat to the health and safety of the public.
|05000298/LER-2016-005||22 November 2016||Cooper|
During Refueling Outage 29 (RE-29), Cooper Nuclear Station implemented the guidance of Enforcement Guidance Memorandum (EGM) 11-003, Revision 3, "Dispositioning Boiling Water Reactor Licensee Noncompliance with Technical Specification Containment Requirements During Operations with a Potential for Draining the Reactor Vessel," dated January 15, 2016. Consistent with EGM 11-003, Revision 3, secondary containment operability was not maintained during Operations with a Potential for Draining the Reactor Vessel activities, and Required Action C.2 of Technical Specification (TS) 126.96.36.199 was not completed.
EGM 11-003, Revision 3, was implemented four times during RE-29. These conditions are being reported as conditions prohibited by TS.
Implementation of EGM 11-003, Revision 3, during RE-29 was a planned activity. As such, there were no root cause evaluations of the events. Consistent with the guidance provided in EGM 11-003, Revision 3, Nebraska Public Power District will submit a license amendment request to adopt a Technical Specifications Task Force (TSTF) traveler associated with generic resolution of this issue within 12 months after issuance of the Notice of Availability of the TSTF traveler.
- 005 -00 Cooper Nuclear Station 05000- 298 2016 Reported lessons learned are incorporated into the licensing process and fed back to industry. Send comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.
Cooper Nuclear Station (CNS) was in Mode 5, Refueling, at 0 percent power, at the time of the events.
On January 15, 2016, the Nuclear Regulatory Commission issued Enforcement Guidance Memorandum (EGM) 11-003, Revision 3, "Dispositioning Boiling Water Reactor Licensee Noncompliance with Technical Specification Containment Requirements During Operations with a Potential for Draining the Reactor Vessel." EGM 11-003, Revision 3, provides generic enforcement discretion to allow implementation of specific interim actions as an alternative to full compliance with plant technical specifications related to Secondary Containment operability during Mode 5 Operations with a Potential for Draining the Reactor Vessel (OPDRV) activities. To ensure compliance with interim actions specified in the EGM, CNS added guidance to plant Procedure 0.50.5, "Outage Shutdown Safety.
During Refueling Outage 29 (RE-29), CNS implemented the guidance of EGM 11-003, Revision 3, four times. Consistent with EGM 11-003, Revision 3, Secondary Containment operability was not maintained during OPDRV activities, and Required Action C.2 of Technical Specification (TS) 188.8.131.52 was not completed.
The following provides the dates which EGM 11-003 was implemented:
1. On October 1 and 2, 2016, the EGM was utilized to allow work on Reactor Recirculation Pump A (RR-P-A) and RR-P-B without the jet pump plugs installed while performing Surveillance Procedure 6.1SGT.401, "SGT A Fan Capacity Test, SGT B Cooling Flow Test and Check Valve 1ST (Div 1).
2. From October 2-5, 2016, the EGM was utilized to allow work on RR-P-A, RR-P-B, Control Rod Drive (CRD) withdrawal/bypass operations and Hydraulic Control Unit (HCU) 42-31 during repairs to Main Steam Air Operated Valve 86B.
3. On October 6, 2016, the EGM was utilized to work on RR-P-A and RR-P-B without the jet pump plugs installed while draining Reactor Core Isolation Cooling 12 Relief Valve and flushing Main Steam Isolation Valves (MSIV).
4. From October 19-25, 2016, the EGM was utilized to work on RR-P-A. While using the EGM, work was also performed on CRD-V-113s (freeze seal), CRD Drive Venting, and CRD-V-105 (10-43) (freeze seal). These OPDRVs were in progress while Secondary Containment was inoperable for MSIV 86A and 86B repair, Reactor Building (RB) personnel airlock seal repair, shift of RB ventilation, Service Water Valve 531 draining and Residual Heat Removal Valve 57/67 draining.
Reported lessons learned are incorporated into the licensing process and fed back to industry. Send comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.
05000- 298 Cooper Nuclear Station 2016 - 005 - 00
3. LER NUMBER
BASIS FOR REPORT
These events are reportable in accordance with 10 CFR 50.73(a)(2)(i)(B) as conditions prohibited by CNS TS 184.108.40.206, which prohibits performing activities identified as OPDRVs in MODE 5 while secondary containment is inoperable.
As discussed in EGM 11-003, Revision 3, enforcement discretion is appropriate because the issues have low safety significance since licensees must implement compensatory measures to provide an adequate level of safety when using the discretion. To ensure compliance with the interim actions specified in the EGM, CNS added guidance to plant Procedure 0.50.5. This procedure was implemented for the OPDRV activities during which Secondary Containment was not operable.
Implementation of EGM 11-003, Revision 3, during RE-29 was a planned activity. As such, there were no root cause evaluations of the events.
CNS will submit a license amendment request to adopt the Technical Specifications Task Force (TSTF) traveler associated with generic resolution of this issue, within 12 months after issuance of the Notice of Availability of the TSTF traveler.
During RE-28, CNS implemented EGM 11-003, Revision 2, seven times. These events were reported under one License Event Report, LER 2014-004-00.
|05000298/LER-2016-003||9 November 2016||Cooper|
On September 14, 2016, during testing of the Reactor Recirculation Motor Generator Ventilation Air Operated Isolation Valves (AOV), HV-AOV-265 failed to close as required by Technical Specifications. Operations declared HV-AOV-265 inoperable and entered Limiting Condition for Operation (LCO) 220.127.116.11, Condition A, and commenced preparations to transition the plant to single loop operation, including reducing the plant to approximately 50 percent power. Upon investigation, it was discovered that the air supply line to the valve was pinched between the valve actuator and a scaffold that was erected to support work on a nearby component. After modifying the scaffold and replacing the pinched airline, the valve was tested satisfactorily and Operations exited the LCO and activities to prepare for transition to single loop operation were terminated.
The root cause of the event is that personnel involved in the planning, construction, and inspection of the scaffold built for a nearby component were not aware of the unique external movement path of the valve actuator. To prevent recurrence, the procedure will be revised to include specific guidance for the planning, building and inspection of scaffolds in the vicinity of HV-AOV-265 and other AOVs having actuators of similar design. Signage has been installed to warn personnel of the external movement of these AOVs.
|05000298/LER-2016-002||27 June 2016||Cooper|
On April 26, 2016, it was noted that the green off light for High Pressure Coolant Injection (HPCI) auxiliary lube oil pump (ALOP) in the Control Room, was not illuminated. A non-licensed operator was dispatched to the HPCI ALOP starter and reported the green bulb appeared to have shattered in the socket. HPCI was declared inoperable at 1754 Central Daylight Time (CDT) resulting in entry into Technical Specifications Limiting Condition of Operation 3.5.1, Condition C, HPCI System Inoperable.
Investigation found the 125 volts direct current fuse open circuited and the local indication green light and socket were damaged. The cause of the failure was determined to be a lack of engineering knowledge which led to a design change in 1984 in the HPCI ALOP starter circuitry that diminished the robustness of the circuit with respect to a specific failure modality; direct short circuiting within the indication bulb itself. The HPCI system was restored to operable status on April 28, 2016, at 1245 CDT.
This event is being reported as a loss of safety function due to HPCI being a single-train safety system.
The potential safety consequences of this event were minimal due to the limited duration the condition existed and the redundant/diverse core cooling systems which remained operable.
3. LER NUMBER 2. DOCKET NUMBER 05000- 298 Cooper Nuclear Station 2016 - 002 - 00
|05000298/LER-2015-001||5 November 2015||Cooper|
On January 26 and February 11; 2015, five of eight Tatet Rock safety relief valve-(SRV) pilot valve assemblies, removed during Refueling Outage 28, failed to lift within Technical Specification (TS) lift setpoint requirements. The pressure setpoint of the first failed pilot assembly is 1090 psig; the SRV pilot assembly lifted at 1124 psig. The pressure setpoint of the second failed pilot assembly is 1100 psig; the SRV pilot assembly lifted at 1192 psig. The pressure setpoint of the third failed pilot assembly is 1090 psig; the SRV pilot assembly lifted at 1267.7 psig. The pressure setpoint of the fourth failed pilot assembly is 1100 psig; the SRV pilot assembly lifted at 1139 psig. The pressure setpoint of the fifth failed pilot assembly is 1090 psig; the SRV pilot assembly lifted at 1138 psig. Two subsequent lifts were performed for all failed SRV pilot assemblies and the results were within the TS pressure setpoint tolerances.
Initially, the probable cause was corrosion bonding with time being a possible exacerbating factor. Upon further investigation and testing, it has been determined that the direct cause of the failures is corrosion bonding.
Although the TS related to the set point lift pressures of the SRV pilot valve assemblies were exceeded, an analysis of this event indicates that the design basis pressures to ensure safety of the reactor vessel and its pressure related appurtenances were not challenged. Public safety was not at risk. Safety to plant personnel and plant equipment were not at risk.
|05000298/LER-2015-004||29 July 2015||Cooper|
On May 30, 2015, at 03:27, Cooper Nuclear Station placed the "B" Loop of Residual Heat Removal (RHR) in the Shutdown Cooling (SDC) mode of operations and entered Mode 4, Cold Shutdown, at 04:15. At 04:58, isolation signals from pressure switches (RR-PS-128A and/or RR-PS-128B) were received and, SDC suction isolation valves RHR-MO-17 and RHR-MO-18 closed, resulting in a loss of SDC.
Investigation revealed the event was initiated by steam flashing in the SDC line. This flashing created pressure transients, causing RHR-MO-17 and RHR-MO-18 to close. The steam flashing occurred due to temperature in the SDC line being at or near saturation temperature causing localized boiling then void collapse with coolant being drawn from the reactor vessel thru the reactor recirculation system. SDC was restored at 05:20 on May 30, 2015. The root cause of the event was determined to be a design vulnerability and subsequent operation of the SDC system that resulted in a trip of the SDC suction valves due to sub-cooling and flashing in the RHR or Reactor Recirculation (RR) system. To prevent recurrence, CNS will initiate an Engineering Change request to move the location of the input pressure signals required to meet requirements of Technical Specification 18.104.22.168, Table 22.214.171.124-1, 6(a) from the RR line to the Vessel Steam Dome.
This is a Safety System Functional Failure.
|05000298/LER-2015-003||28 July 2015||Cooper|
In January 2015, during Quarterly Surveillance Testing on the Main Steam Isolation Valves (MSIVs), inboard MSIV C failed to actuate its associated Reactor Protection System (RPS) relay. The limit switch and associated RPS relay were declared inoperable and the associated RPS channel was placed in trip to satisfy Technical Specifications requirements.
In May 2015, during Quarterly Surveillance Testing on the MSIVs, the inboard MSIV A and inboard MSIV B also failed to actuate their associated RPS relay. The limit switches and associated RPS relay were declared inoperable and the associated RPS channel was placed in trip to satisfy Technical Specifications requirements.
As a result, the plant was in an increased risk of an inadvertent full scram. A decision was made to shut the plant down and replace the limit switches.
The limit switches were removed and are being evaluated for cause.
The event is currently under investigation. CNS will provide a supplement to this Licensee Event Report.
|05000298/LER-2015-002||16 April 2015||Cooper|
On February 19, 2015, during performance of surveillance procedures, three of eight Division 2 Main Steam Differential Pressure Indicating Switches failed to trip prior to exceeding limits set in Technical Specifications (TS).
Investigation revealed that the setpoint change calculations and surveillance procedures had been inappropriately revised during implementation of TSTF-493. The applicable setpoint change calculations and surveillance procedures have been revised to pre-TSTF-493 values.
This event is being reported as an operation or condition prohibited by TS, and also as a common cause inoperability of independent trains or channels.
The event has negligible safety significance based on the safety function associated with the main steam high flow isolation signal was preserved through successful testing of five of the eight Division 2 switches.
|05000298/LER-2014-004||24 November 2014||Cooper|
During Refueling Outage 28 (RE-28), Cooper Nuclear Station implemented the guidance of Enforcement Guidance Memorandum (EGM) 11-003, Revision 2, "Dispositioning Boiling Water Reactor Licensee Noncompliance with Technical Specification Containment Requirements During Operations with a Potential for Draining the Reactor Vessel," dated December 13, 2013. Consistent with EGM 11-003, Revision 2, secondary containment operability was not maintained during Operations with a Potential for Draining the Reactor Vessel activities, and Required Action C.2 of Technical Specification 126.96.36.199 was not completed.
EGM 11-003, Revision 2, was implemented seven times during RE-28. These conditions are being reported as conditions prohibited by Technical Specifications.
Implementation of EGM 11-003, Revision 2, during RE-28 was a planned activity. As such, there were no root cause evaluations of the events. Consistent with the guidance provided in EGM 11-003, Revision 2, Nebraska Public Power District will submit a license amendment request to adopt a Technical Specifications Task Force (TSTF) traveler associated with generic resolution of this issue within 12 months after the issuance of the Notice of Availability of the TSTF traveler.
|05000298/LER-2014-003||26 June 2014||Cooper|
On February 25, 2014, during planned Reactor Core Isolation Cooling (RCIC) system maintenance activities, a linkage pin in the RCIC trip and throttle valve, RCIC-MOV-M014, was found out of position and not properly retained.
The pin is part of the linkage assembly that ensures a successful valve reset following normal RCIC turbine trip situations. With the linkage pin in the as-found condition, it may have become disengaged during future RCIC system operation and prevented RCIC-MOV-M014 to automatically reset, thus causing a system failure.
Investigation found the set screws loose with no thread locker applied.
The cause of the linkage pin being out of position is inadequate work instructions during the valve overhaul in September 2010. The inadequate work instructions led to the set screws being out of position, which eventually let the linkage pin move out of position.
Immediate corrective action was taken to properly reinstall the pin and operation of RCIC-MOV-M014 was tested satisfactorily on February 25, 2014. An additional corrective action was completed to revise the associated maintenance plan for RCIC-MOV-M014 to include guidance for installation of the linkage pin and set screws.
|05000298/LER-2014-002||11 April 2014||Cooper|
On October 7, 2013, Diesel Generator (DG) 1 was declared inoperable for the performance of the monthly operability test. During the test, indications of water intrusion into the DG1 lubricating oil system were observed. DG1 remained inoperable during troubleshooting activities. Upon further investigation, a crack in the liner wall was visible near the top of the 1-Left cylinder liner. The liner was removed and sent to Lucius Pitkin, Incorporated, for examination. A new liner was installed and DG I was declared operable on October 12, 2013.
The root cause of the event was that the subpar mechanical properties of the liner caused the cylinder liner to crack which then allowed jacket waterto leak into the engine lubrication oil.
To prevent recurrence of this condition, the test method(s) shall be specified to ensure that liners currently in inventory have sufficient material tensile strength to conform to the given requirements. A report that details the test methods used and the results of testing shall be reviewed prior to any liner from inventory being installed in either DG1 or DG2.
|05000298/LER-2014-001||6 March 2014||Cooper|
On January 6, 2014, the differential pressure (DP) in the reactor building rose above the requirement of -0.25 inches of water column DP, causing entry into Limiting Condition of Operation (LCO) 188.8.131.52, Condition A.
Secondary containment was declared inoperable at 02:45.
The DP transient occurred when a non-licensed plant operator (NLO) was hanging tags in support of maintenance work. During the process of hanging tags, the NLO inadvertently opened the wrong drain valve.
When the wrong drain valve was open, the reactor recirculation motor generator (RRMG) exhaust fan discharge damper that was operating closed. The NLO felt the change in DP and closed the drain valve, which opened the RRMG exhaust fan discharge damper, restoring ventilation. DP was restored, secondary containment was declared operable at 03:02, and the LCO was exited. During this event, DP remained negative at all times.
The root cause is the organization was not fully aware of the effects of the cross-over leakage between the reactor building envelope and the RRMG exhaust system. To prevent recurrence of this event, procedures will be revised to ensure adequate precautions are taken to avoid exceeding the -0.25 inches of water column DP requirement, information about the effects of cross-over leakage will be incorporated into the appropriate training materials, and a procedure to directly measure air leakage will be developed.
|05000298/LER-2011-001||14 March 2011||Cooper|
On January 18, 2011, the open position indication light for Reactor Recirculation Pump "A" Discharge valve (RR-MO-53A) was discovered de-energized. Investigation found a damaged socket resistor for the bulb, causing fuses to the control power circuit for the valve to be open- circuited, preventing RR-MO-53A from closing to support the Residual Heat Removal (RHR) "A" Low Pressure Coolant Injection (LPCI) safety function, if needed. At the time of discovery, the
The fuses were replaced and the RR-MO-53A indication changed state from "closed" to "open" on the Plant Monitoring Information System (PMIS). After satisfactory completion of Post Maintenance Testing, RHR Loop "A" was declared operable.
The root cause of this event is that there were no significant barriers in existence that could have provided prompt indication that the starter circuit had become inoperable. To prevent recurrence, the station procedure was revised to include shiftly verification of this valve position and the PMIS will be upgraded to indicate power loss to the starter circuit for RR-MO-53A and RR-MO-53B.
CNS reported this event per Event Notification 46563. This event was not risk significant.
|05000298/LER-2007-001||23 May 2007||Cooper|
Between 0430 and 0457 Central Standard Time (CST) on February 7, 2007 High Pressure Coolant Injection (HPCI) inverter circuit failure alarms were received intermittently indicating a loss of the inverter output. HPCI was in a standby status at the time of the alarms. The loss of inverter output was confirmed by the HPCI flow controller output lowering to approximately 30% and returning to 100% upon, alarm reset. The power indicating light on the inverter was observed to go off on the last alarm, returning when the alarm was reset.
HPCI was declared inoperable at 0430 resulting in entry into Technical Specification Limiting Condition for Operation 3.5.1 Condition C, HPCI System inoperable and 3.5.1 Condition D, HPCI System inoperable AND Condition A entered. Condition A was previously entered for Core Spray System Loop A, which was inoperable for planned maintenance. The failure was the result of an intermittent open circuit caused by corrosion which resulted from solder flux residue remaining on copper conductors during the manufacturing process. The inverter was replaced and HPCI was declared operable at 1602 on February 7, 2007. This LER also satisfies the reporting requirements of 10 CFR 21.
|05000298/LER-2004-002||27 May 2004||Cooper|
On March 23, 2004 diesel generator Division 1 was declared inoperable as a result of day tank float valve strainer fouling. As an interim compensatory measure to support Division 2 operability the diesel fuel oil storage tank cross-tie line valves were opened. On March 28, 2004, at 1303 CST while performing a routine surveillance to check availability of fuel oil for the diesel generators it was discovered that the storage tank levels were not equalized. During the subsequent investigation it was discovered that DGDO-V-23 had not been correctly verified to be in the open position and was, in fact, in the closed position. This resulted in both divisions of diesel generators being declared inoperable.
The condition is reportable in accordance with 10 CFR 50.73(a)(2)(v)(D) as, "Any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident".
The cause of the condition was a failure to follow procedural methods in checking valve position.
Contributing causes included an inconsistent labeling of valve position and a lack of independent verification of valve position when the valve position was checked. The closed valve was opened and diesel generator Division 2 was declared operable. Long-term corrective action is to correct the condition of the transfer valves to ensure that an obvious visible indication of valve position is available that allows ease of interpretation.
|05000298/LER-2004-001||8 April 2004||Cooper|
On February 11, 2004, during validation of a valve line-up on the Service Water (SW) Gland Water system, Cooper Nuclear Station discovered that the gland water piping was cross-connected with SW subsystem "A" safety related pump discharge supplying gland water to both SW subsystems. This resulted in SW subsystem "B" being declared inoperable and required entry into a 30 day Limiting Condition for Operation (LCO). Diesel Generator (DG) 2, which is cooled by SW subsystem "B", and the Control Room Emergency Filter System (CREFS), which was aligned to the DG 2 emergency bus, were declared inoperable and required entry into 7-day Shutdown LCOs. The LCOs were entered at 0310 hours. The gland water line-up was returned to the required configuration and the LCOs were exited at 0340 hours. Further investigation determined that the cross-connected configuration had existed since restoration of the system from planned maintenance performed 21 days earlier.
This event is reportable in accordance with 10 CFR 50.73(a)(2)(i)(B) as "Any operation or condition which was prohibited by the plant's Technical Specifications ((TS))," due to the length of time DG 2 and CREFS were inoperable, which exceeded the TS 7 day shutdown LCO.
The cause of this event was determined to be a process weakness in the Clearance Order program.
Additional instructions for development of clearance orders were issued on February 13, 2004 and a revision to the station procedure for development of clearance orders was completed on April 8, 2004.
|05000298/LER-2003-004||1 April 2004||Cooper|
On May 26, 2003, at 1321 hours, there was a step change in main turbine vibration indication from less than 4 mils to 10.2 mils. A manual reactor scram was initiated from 89% power. Subsequent to the scram, reactor vessel water level dropped to approximately 30 inches below instrument zero, resulting in Primary Containment Isolation System Group 2, 3, and 6 isolations, start of High Pressure Coolant Injection and Reactor Core Isolation Cooling systems, and trip of the Reactor Recirculation pumps. An evaluation of plant response determined all control rods fully inserted and systems controlling reactor pressure and level responded as designed.
The most probable cause for the turbine blade failure in the low pressure turbine is material condition. The failure mechanism is consistent with age-related/end-of-life type failures. Long term corrective action will be to replace the low pressure turbine rotors with new rotors during the next refueling outage.
Immediate actions taken were to manually scram the reactor, trip the main turbine, and place the unit in a cold shutdown condition. An initial visual exam of the turbine blade root specimen was obtained, which concluded the crack is consistent with high cycle fatigue. Magnetic particle and eddy current testing were performed on both faces of the last four rows on both LP1 and LP2 spare rotors. Blades with crack indications on the spare rotors were replaced. The in-service LP1 and LP2 rotors were replaced with the spare rotors.
|05000298/LER-2003-006||19 December 2003||Cooper|
On October 28, 2003, at 0130 hours, a fire occurred on a wooden transmission structure located between the main generator output and the 345KV switchyard. Due to the imminent loss of the main generator output line to the switchyard, a manual scram was performed at 0200 hours. All control rods inserted and Primary Containment Isolation System Group Isolations for Primary Containment, Reactor Water Cleanup and Secondary Containment initiated as expected due to vessel level shrink. The Emergency Core Cooling Systems did not initiate. During water level recovery an overfeed condition caused the operating Reactor Feedwater pump to trip and a second manual scram was inserted in anticipation of a low level scram signal. Normal shutdown procedures were entered at 0300 hours and a vessel cool-down was initiated. The transmission structure fire was reported out at 0647 hours.
The fire occurred when dust accumulation on the insulators and structure became wetted and created a path for stray electrical currents from phase to phase, or phase to ground across the wooden cross arm.
The cause of this event is the failure to properly ground the insulator strings on the wooden structure.
The damaged wooden structure and associated line disconnect switch were removed on October 30, 2003. Grounding cables were installed on a similar structure on November 24, 2003.
, - - NRC FORM aES (7-100i)
|05000298/LER-2003-005||21 November 2003||Cooper|
On September 28, 2003 at 2345 hours, during turbine trip testing, the turbine trip block failed to actuate as demanded while testing the solenoid and low vacuum trip. Troubleshooting identified resistance in the movement of the trip plate in the trip direction. Repeated cycling of the trip plate resulted in no abnormal resistance and the surveillance was repeated and completed satisfactorily. Per Technical Specifications, reactor power was reduced to less than 25% power.
The most probable root cause was ester contamination of the turbine lubricating oil, combined with trace amounts of water, resulting in the formation of hydrolyzed esters that increased the forces required to open the trip valve. The source of the ester contamination is being investigated. In addition, particles collected in clearances around the trip valve.
Immediate actions were to designate an extra operator to trip the turbine locally until trip capability was restored.
An interim action is to perform the turbine trip functional test more frequently. The long-term corrective action is to remove particulate contamination from the turbine lube oil system.
|05000298/LER-2003-002||17 July 2003||Cooper|
On May 19, 2003, a review of Target Rock safety relief valve (SRV) test data, provided by Wyle Laboratories, determined that four of eight SRV pilot valve assemblies failed to lift within their Technical Specification (TS) lift setpoint. Specifically, one SRV with a setpoint of 1080 +1- 32.4 psig lifted at 1168 psig, two SRVs with a setpoint of 1090 +1- 32.7 psig lifted at 1130 psig and 1166 psig respectively and one SRV with a setpoint of 1100 +1- 33.0 psig lifted at 1228 psig. The discovery was made as a result of routine TS surveillance testing of the pilot valve assemblies. Cooper Nuclear Station (CNS) was at 100 percent rated reactor power at the time of the determination.
Examination determined that sufficient corrosion bonding existed between the SRV pilot valve assembly Stellite 21 disc and the pilot valve Stellite 6 in-body seat to cause the SRV pilot valves to lift outside TS setpoint tolerances. As documented in CNS Licensee Event Report 1999-004-01, this is a recurring problem at CNS and within the industry.
The valves were replaced with tested and certified spare valves.
This event is considered to have no safety significance from a Probabilistic Safety Assessment Risk evaluation standpoint. This event does not create a core damage scenario. There is no change to the CNS core damage frequency or the large early release frequency. This condition also has no impact on the Reactor Pressure Vessel pressure relief function capability. Even under postulated failure conditions, there is no associated risk increase to the plant.
|05000298/LER-2003-001||28 April 2003||Cooper|
On February 28, 2003, at 0857 Central Standard Time (CST), with Cooper Nuclear Station (CNS) in cold shutdown, diesel generator (DG) 1 and DG2 were inoperable at the same time. The DGs are the standby source of emergency Alternating Current (AC) power. DG1 was inoperable at the time due to failure of the fuel oil transfer system to deliver required flow during a routine inservice test. DG2 was declared inoperable as a result of discovering that a time delay relay in the diesel room ventilation system had been in service in excess of its qualified life as stated by the manufacturer. Declaring the relay inoperable resulted in the diesel room ventilation system being inoperable. The diesel room ventilation is a required support system for the diesel generator.
Immediate corrective action was to replace the relay with one that was within its service life. DG2 was returned to operable status on February 28, 2003, at 1937 CST.
The relay qualified life issue has been entered into the CNS Corrective Action Program.
The root cause of this event is inadequate communication between the Operations and Engineering departments in that the possibility that analyses could be performed that would extend the qualified life of the relay was not communicated. Corrective actions to preclude recurrence are to establish, implement, and reinforce standards for formal communication between Operations and Engineering when preparing Operability Determinations.
|05000298/LER-2002-001||29 January 2003||Cooper|
On September 18, 2002, at 1425 Central Daylight Time (CDT), with Cooper Nuclear Station (CNS) in Mode 1, Power Operation, at approximately 100 percent power (steady state), the Control Room received annunciator, "High Pressure Coolant Injection (HPCI) Gland Seal Condenser Hotwell High Level.' In accordance with the alarm response procedure, the HPCI Auxiliary Oil Pump switch was placed in the Pull-to-Lock (PTL) position at 1428 CDT. The HPCI system was declared inoperable per Technical Specification.
This event was initiated by the failure of a non-essential Gland Seal Condenser level switch. Upon completion of replacement of the level switch and post work testing of the system, HPCI was restored to operable status at 1339 CDT on September 20, 2002.
The cause of the event is attributed to the procedure change process in place during 1993, which lacked the necessary rigor to ensure the design function of the Gland Seal Condenser was understood before adding the step to inhibit HPCI. The extent of condition was confined to this procedure. Process improvements since 1993 have corrected this deficiency.
The alarm response procedure was revised to remove the step to inhibit HPCI which caused this event.
The procedure revision was effective on December 27, 2002.
|05000298/LER-2001-006||28 December 2001||Cooper|
On November 2, 2001, the plant was operating at 94 percent power during end-of-cycle coast down when both reactor building-to-suppression chamber vacuum relief lines were made inoperable for opening. The control switches for the air operated vacuum breaker valves in each line were simultaneously placed in the "Close" position thereby precluding the ability to automatically relieve vacuum in the suppression chamber. This action was taken in conjunction with performing a tagout for a local leak rate test (LLRT) which was to be performed while the plant was operating. The planned LLRT would have affected only one vacuum relief line at a time, necessitating only one switch at a time to be placed in "Close." However, the action to place both control switches from "Auto" to "Close" was specified on the clearance order, which would have been appropriate for only cold shutdown or refueling conditions. This improper planning was identified as the first root cause.
Subsequently, the senior reactor operator responsible for authorizing the clearance did not recognize the impact on the vacuum relief function of placing both control switches to "Close." This personnel error was identified as the second root cause. Immediate corrective action involved returning the vacuum breaker control switches to "Auto." Interim corrective actions were taken to prevent recurrence during the current outage. Additional corrective actions to prevent recurrence involve process and procedure improvements. Reference LER 2000- 009 for similar event.
|05000298/LER-2001-004||6 November 2001||Cooper|
On September 7, 2001, the plant was operating at 100% power during an early evening lightning storm. A combination of a lightning strike occurring on a 161 kilovolt (kV) transmission line, with equipment malfunctions, resulted in the loss of the preferred offsite alternating current (AC) source at 1750 Central Standard Time (CST). Subsequent voltage perturbations, due to the storm, on the 69 kV sub-transmission system which supplies the emergency offsite AC source, resulted in the loss of the second offsite AC source at 1754 CST due to low voltage. A complete loss of the second offsite AC source occurred at 2230 CST.
The cause of the loss of both offsite power sources during the lightning strikes was that standards, policies and administrative controls to ensure maintenance and testing of switchyard equipment were not adequate to detect degradation of certain key equipment important to offsite power prior to failure. Thus, the offsite power switching circuitry was vulnerable to perturbations and failure.
Immediate corrective actions included inspection, testing, restoring equipment to service, replacing and repairing equipment and revising equipment testing. Long term corrective actions include determining acceptance criteria, identifying major switchyard equipment important to offsite power and reviewing procedures for test adequacy, acceptance criteria and test frequency.