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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 3.7.1.1. 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.

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.

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.

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) 3.8.3.2, 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.

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.

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.

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.

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.

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.