|Report date||Site||Event description|
|05000244/LER-2017-001||15 June 2017||Ginna|
On April 23, 2017, with the plant in Mode 1, during in-place testing of main steam safety valve (MSSV) 3509, the as-found lift pressure did not meet the acceptance criteria of +1% / -3% of setpoint (1140 psig), required by Technical Specifications (TS) surveillance SR 188.8.131.52. This was the second unsatisfactory MSSV as-found lift pressure, as MSSV 3508 had failed to meet the same as-found acceptance criteria during earlier in-place sequential testing (on April 21, 2017). Later, on May 5, 2017, a third MSSV (3512) tested at a vendor's facility failed to meet the same as-found acceptance criteria. (All three of the MSSVs have the same manufacturer and model number.) The apparent cause of exceeding the MSSV upper acceptance limit is stiction in the disc area. The as-found settings of all three MSSVs remained within analytical bounds; therefore, operation of the facility in this condition had no impact on the health and safety of the public.
TS LCO 3.7.1, "Main Steam Safety Valves (MSSVs)," requires eight MSSVs to be operable in Modes 1, 2, and 3. Since the stiction affecting the three lift pressures may have occurred over a period of time, it is assumed that at least one required MSSV was not operable in the past for a time greater than allowed. Therefore, this occurrence is considered reportable per 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by the plant's TS.
|05000244/LER-2016-001||7 April 2016||Ginna|
On 02/11/2016 at 2305, Ginna Station experienced a loss of Station Auxiliary Transformer 12A, causing Emergency Diesel Generator A to automatically start due to undervoltage signals to safeguards buses 14 and 18. Station Auxiliary Transformer 12A failed due to a high side phase to phase internal fault with relays for overcurrent and differential current actuated. All plant systems responded as designed. Control room operators stabilized the plant per abnormal operating procedures. The plant was placed in 100/0 electrical lineup on the off-site circuit 767 with Emergency Diesel Generator A secured. Station Auxiliary Transformer 12A was replaced with a spare and the plant was restored to normal off-site power line-up on 02/20/2016 at 0018.
This event is reportable under 10CFR50.73(a)(2)(iv)(A) as a valid system actuation that was not part of a pre-planned sequence during testing.
|05000244/LER-2015-001||24 September 2015||Ginna|
On June 30, 2015, during rod movement testing, it was discovered that the data recorder temporarily installed as a secondary method of monitoring the position of control rod L06 was not available due to an incorrect trigger setting. The cause of the incorrect trigger setting was a human performance error during manipulation of the data recorder on June 28, 2015. Prior to this event, the primary method of monitoring position indication for control rod L06, the Plant Process Computer System (PPCS), had also been declared inoperable to perform maintenance due to a hardware malfunction. The malfunction had been resolved prior to this event and PPCS indication was available. However, at the time of the data recorder unavailability PPCS indication for control rod L06 was still administratively considered to be inoperable. Therefore, Ginna was administratively not reviewing the rod control system for indications of rod movement for a rod with an inoperable position indicator (control rod L06) during the time the data recorder was unavailable. It was later determined this condition existed for approximately 36 hours. This was not in accordance with requirements stated in Technical Specification (TS) Limiting Condition for Operation (LCO) 3.1.7.A.3.2 Rod Position Indication.
This event is reportable under 10CFR50.73(a)(2)(i)(B) as a condition prohibited by Technical Specifications.
|05000244/LER-2014-003||6 November 2014||Ginna|
On September 10, 2014, during performance of a routine, scheduled surveillance test (STP-0-12.1) on the "A" Emergency Diesel Generator (EDG), the output supply breaker to safeguards Bus 14 failed to close on demand.
Non-intrusive troubleshooting revealed no obvious issues with the breaker, and the output supply breaker functioned as required during a second test. A spare breaker was installed and tested satisfactorily on September 11, 2014.
An inspection of the original breaker conducted with the assistance of an original equipment manufacturer (OEM) engineer determined the apparent cause of the failure to be misalignment and lack of end to end play of the tripper bar within the breaker operating mechanism. Corrective actions included installing a spare circuit breaker and performing STP-0-12.1 to verify satisfactory operation Testing procedures have been modified to include post-test inspections to ensure the tripper bar is properly aligned for operation.
Maintenance procedures will be modified to verify proper end to end play alignment. This event is not considered to have had any significant effect on the health and safety of the public.
|05000244/LER-2013-003||12 September 2014||Ginna|
On September 20, 2013, R.E. Ginna Nuclear Power Plant determined that there was a potential for flooding of both battery rooms during a design basis flood due to unqualified wall penetration material. A flow test was performed to verify functionality of cable vault drains. Accumulation of water in the cable vault could potentially challenge unqualified penetration barriers between the manhole and "B" Battery Room, leading to flooding of the "A" Battery Room under the normally closed fire door. Flooding from these penetrations has not been previously evaluated. In addition, during the extent of condition review, two smaller conduit penetrations were discovered that were not sealed.
The apparent cause of this condition is inadequate re-evaluation of new flood level impacts during the 1981- 1983 Systematic Evaluation Program review.
The penetrations into the battery room have since been sealed watertight. Additionally, the drain line in the cable vault has been cleared of obstruction.
|05000244/LER-2014-002||8 May 2014||Ginna|
On March 13, 2014 during an industry Operating Experience review, a postulated Appendix R fire scenario was identified that could potentially impact several fire areas and potentially affect safe shutdown equipment. The postulated scenario could allow fire spread via unprotected DC control circuit for non-safety related circulating water pump discharge motor operated valves (MOV). The affected wiring is routed through the screenhouse, "B" Emergency Diesel Generator room, turbine building, air handling room, relay room, and control room.
Compensatory actions taken include hourly fire tours in the potentially impacted areas.
Corrective action to install fuses to protect the circuits for the Circulating Water Pump Discharge MOVs was completed.
|05000244/LER-2014-001||18 March 2014||Ginna|
On January 7, 2014, a fuel oil sample was collected from "B" Emergency Diesel Generator (EDG) fuel oil storage tank (TDGO1B) per Technical Specification (TS) Surveillance Requirement (SR) 184.108.40.206, for routine testing. The sample was shipped to an off-site laboratory for analysis; the analytical results were received at Ginna on January 20, 2014. The report indicated that the total particulate concentration in TDGO1B exceeded the acceptance criteria established by TS 5.5.12, "Diesel Fuel Oil Testing Program." Due to the 13 day lapse between sample collection and licensee receipt of analytical results, the Completion Time of seven (7) days for TS Limiting Condition for Operation (LCO) 3.8.3, "Diesel Fuel Oil," Condition B, "Restore fuel oil total particulates within limit," had been exceeded.
Upon identification of the unacceptable total particulate concentration, a work order was implemented to establish continuous filtration of TDGO1B. Samples collected from the discharge of the filter indicated that the filtration was not achieving a satisfactory reduction in total particulate concentration; therefore, the filtration was secured. After further evaluation, the decision was made to replace the fuel oil in the tank.
The cause of the event was attributed to contamination from a temporary storage tank used in previous maintenance.
To prevent re-occurrence of this event, guidance will be added to the procedure controlling work utilizing temporary storage containers or tanks to ensure the temporary tanks meet the same cleanliness criteria as the systems they are being used to service.
|05000244/LER-2013-002||17 September 2013||Ginna|
On July 24, 2013 at 1419, the R.E. Ginna Nuclear Power Plant (Ginna) experienced an automatic Reactor Trip from full power during Main Generator Reactive Power Testing.
The Reactor Trip was caused by a reactor protection system (RPS) actuation signal from a Turbine Trip, which was caused by a Generator Trip. All Control Rods inserted on the trip, and Auxiliary Feedwater started automatically, as expected. The cause of the generator trip was determined to be an incorrect configuration of two generator protection digital relays while implementing a modification during the 2012 refueling outage. An alarm was expected while raising voltage during reactive power testing, but due to the incorrect configuration of the relays, a trip signal was received which tripped the main generator. The protective relays' outputs were configured incorrectly to trip at the alarm setpoint.
The trip functions of the digital relays were removed, returning Ginna to the alarm indication and trip protections prior to the 2012 refueling outage.
|05000244/LER-2013-001||31 May 2013||Ginna|
On April 12, 2013, a system engineer performing a walkdown of backflow prevention devices discovered that the check valve that was expected to be found installed in a floor drain in the Intermediate Building Basement had been removed. The check valve was designed as a barrier to prevent the flow of flammable liquid from the Turbine Building Basement to the Intermediate Building Basement where safe shutdown equipment is located.
In accordance with the Technical Requirements Manual (TRM), immediate compensatory actions were initiated. These actions were a fire detector operability verification and an hourly fire watch inspection.
Additionally, a plug was installed in the floor drain to prevent the backflow of flammable liquid.
The apparent cause of this event is removal of the check valve due to housekeeping issues because it would not allow water to pass due to the unique design of the valve. The check valve appears to have been removed at some point in the past to prevent water accumulation in the floor drain without sufficient review of the impact. This event was entered into the Station's Corrective Action Program and a plant modification will be performed to replace the valve, addressing the original design deficiencies.
|05000244/LER-2011-003||2 December 2011||Ginna|
On October 11, 2011, the R.E. Ginna Nuclear Power Plant experienced an automatic reactor trip from 100% power. The trip was caused by a failure of the turbine lube oil piping internal to the turbine lube oil reservoir. The failed piping resulted in the main turbine Auto Stop Trip oil pressure switches activating on low oil pressure. The control room operators performed the appropriate actions of procedures E-0, Reactor Trip or Safety Injection and ES-0.1, Reactor Trip Response. Following the reactor trip, all safety systems operated as designed. The reactor was stabilized in Mode 3 while repairs were performed.
The cause of the piping failure was determined to be high piping stresses from original construction in combination with substandard welding, routine maintenance, and cyclical fatigue.
Corrective actions to prevent recurrence include a redesign of the piping to facilitate maintenance of associated check valves and to eliminate stress risers inherent to the original weld configuration.
Additional corrective actions are summarized in section IV.B.
|05000244/LER-2011-002||17 October 2011||Ginna|
On June 11, 2011, shortly after the 2011 Refueling outage, the "B" Main Steam Isolation Valve (MSIV) position indicating lights on the Main Control Board were observed to be flickering. Those lights subsequently went out.
On August 23, 2011, when a fire water booster pump auto-started, the lights indicating that the "B" MSIV was open turned on. After the booster pump was secured, the lights turned off. Following subsequent troubleshooting, a fuse clip in the control circuit was determined to be not making contact with the fuse. It is suspected that relay actuation from the booster pump vibrated the fuse clip causing it to make contact.
Troubleshooting on August 23, 2011, established that the fuse clip for the "B" train actuation circuit was damaged. This condition may have existed since June 11, 2011, thereby exceeding the required action time of the applicable Limiting Conditions for Operations (LCO). Maintenance was performed and the circuit was restored to service.
The apparent cause is the use of fuse blanks for hanging clearance tags that caused excessive bending of the fuse clips. The corrective actions are described in Section IV.
|05000244/LER-2011-001||4 October 2011||Ginna|
On August 11, 2011 the R.E. Ginna NFPA-805 project identified a fire scenario in the Turbine Building that could fail power to safeguards busses resulting in a station blackout, coincident with loss of the Turbine Driven Auxiliary Feedwater pump. While no damage to the emergency diesel generators or the output breakers occurs as a result of the fire, electrical interlocks prevent automatic closure of the diesel generator breakers due to closed normal supply breakers. Manual closure of a diesel generator breaker without first tripping the normal supply breaker may result in overload.
Compensatory measures have been established to provide operators with guidance to monitor control power indication prior to attempting to manually close the emergency diesel generator breakers. In the event control power is unavailable to the normal supply breaker, operators will locally open the normal supply breaker prior to closing the emergency diesel generator breaker. Procedure changes have been made to incorporate this guidance.
The cause is an inaccurate analysis of interlock effects in the Appendix R Safe Shutdown analysis.
Additional corrective actions will be evaluated upon completion of the NFPA-805 Fire PRA and Fire Risk Evaluation.
|05000244/LER-2006-004||3 November 2006||Ginna|
On September 6, 2006, a reportable condition was identified during the review of a previous issue discovered on April 18, 2005. The current review was being performed in response to NRC inspection questions regarding the previous issue.
On April 18, 2005, while at 100% power, both trains of standby auxiliary feed water (SAFW) flow transmitters were found isolated. The plant had entered Mode 3 on April 9, 2005 for a routine startup after a refueling outage. The transmitters were restored to their normal operational alignment promptly when the condition was identified. It has since been determined that this condition resulted in the inoperability of both trains of SAFW.
Corrective action to address the condition is outlined in Section V.
|05000244/LER-2006-001||13 July 2006||Ginna|
On May 17, 2006, during the performance of an electrical engineering circuit evaluation of certain Appendix R fire scenarios, it was discovered that a previously unevaluated failure mode potentially existed for the Charging Pumps. Certain fire scenarios occurring in the Control Complex, Cable Tunnel, or Auxiliary Building, could result in the failure of specific under- voltage protection circuitry. The failed circuitry could trip the "A" Charging Pump breaker and hold it in a tripped condition. A similar condition existed for the "B" Charging Pump breaker, during certain fire scenarios in the "A" Battery Room. The safety significance of this event was reviewed and determined to be of low risk significance.
This report is being made under 10CFR50.73(a)(2)(ii)(B).
Corrective action to address the failure mode is outlined in Section V.
|05000244/LER-2003-004||11 December 2003||Ginna|
On October 14, 2003, at approximately 2300 EDST, the plant was in Mode 2 at approximately 2% steady state reactor power. Surveillance testing was in progress as part of a return to power following a refueling outage.
It was discovered that one of two turbine driven auxiliary feedwater (TDAFW) flowpath was isolated, and had been inoperable during the transition from Mode 4 to Mode 3 on October 12, 2003 at 1320 and from Mode 3 to Mode 2 on October 14, 2003 at 0446. This condition is contrary to Ginna Station Improved Technical Specifications Limiting Condition for Operation 3.0.4.
The conditions initiating this event were traced to the performance of procedures utilized for the filling of the steam generators during shutdown, which invalidated the auxiliary feedwater system lineup previously performed.
Corrective action was immediately taken to restore the TDAFW flowpath to operable status, and further procedural and process controls will be implemented to prevent recurrence.
|05000244/LER-2003-005||11 December 2003||Ginna|
During start-up from the 2003 Refueling Outage (RFO) on October 15, 2003, high wind conditions resulted in the loss of off-site Circuit 751. With the electrical system in the normal start-up alignment, the loss of Circuit 751 resulted in the loss of the bus powering the B Reactor Coolant Pump (RCP). Following the loss of the B RCP, the operators manually tripped the reactor as required by Abnormal Operating Procedure AP-RCS.2, Loss of Reactor Coolant Flow. Safeguards busses 16 and 17 were also lost due to the loss of Circuit 751, but were subsequently re-energized by the B Emergency Diesel Generator (EDG) as designed. The A and B Motor Driven Auxiliary Feedwater Pumps started as designed. The plant was stabilized in Mode 3 using the appropriate procedures.
Corrective action to prevent recurrence is outlined in Section V.B.
|05000244/LER-2003-001||23 May 2003||Ginna|
On April 2, 2003, the plant was in Mode 1 at approximately 100% steady state reactor power. At approximately 0930 EST, it was discovered that over the last three years, on two separate occasions (June 8, 2000 and January 16, 2002), maintenance activities associated with non-safety-related bus tie breakers 52/BTA-A and 52/BTB-B had rendered the Main Feedwater Pump Discharge Valves (MFPDVs) inoperable with respect to the Ginna Station Technical Specifications. This inoperability was not recognized by plant staff at the time of the maintenance. As a result, LCO 3.7.3 Condition A was not entered and the Required Action Completion Time of 24 hours was not met. Since these were previous occurrences, no immediate actions were required.
The cause of operating in a condition prohibited by Technical Specifications was plant staff not recognizing the impact of removing the bus-tie breakers from service and their impact on the MFPDVs due to inadequate consideration of system interactions.
Corrective action to prevent recurrence is listed in Section V.B.
|05000244/LER-2002-002||20 December 2002||Ginna|
On November 8, 2002, the plant was in Mode 1 at approximately 100% steady state reactor power. At approximately 0905 EST, it was discovered that there was a small breach in a flexible connection at the inlet of the Control Room HVAC system (system VI) Return Air Fan (AKF08). The plant entered Technical Specification Limiting Condition for Operation 3.0.3 for approximately 40 minutes while temporary repairs were made.
It was determined that the small breach in the flexible connection could have caused an in-leakage into the Control Room greater than that assumed in the accident analysis. This was reported to the NRC within eight hours of the determination per 10 CFR 50.72(b)(3)(v)(D).
The cause of the small breach was a partial failure of a flexible connection.
Corrective action to prevent recurrence is listed in Section V.B.
|05000244/LER-2003-003||11 November 1111 JL||Ginna||This information is reported voluntarily appropriate to the guidance provided in NUREG 1022, "Event Reporting Guidelines 10 CFR 50.72 and 50.73," revision 2, section 2.7 "Voluntary Reporting." On September 18, 2003, with the reactor in Mode 5 for a refueling outage, investigations determined that potential flow paths existed larger than allowed by design basis (greater than 1/4-inch openings) into the containment Sump B that bypass the sump inner screen. Upon initial evaluation, it was postulated that debris generated by a design basis loss of coolant accident inside containment could have potentially bypassed the emergency sump inner screen and affected both independent Emergency Core Cooling System (ECCS) trains, due to both trains requiring suction from the emergency sump during the recirculation phase of operation. This had the potential to prevent both trains of ECCS from removing residual heat from the reactor. Also, further investigations determined an existing limited amount of debris inside containment Sump B and a question regarding the size of the openings in the inner screen. However, since that time, RG&E has performed an extensive evaluation and determined that equipment required to mitigate the event, though found to be in a degraded condition, would perform their required functions. Corrective actions included modifications to the containment Sump B to restore it to design conditions and enhancements to the containment inspection procedure, including training of involved personnel.|