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On February 16, 2017, at 1320 EST with Unit 2 at 0 percent rated thermal power due to being in a refueling outage, maintenance electricians were sent to the field to perform a protective relay trip test for the 2D start-up transformer (SAT). During the test setup, the 2E 4160 VAC Emergency Bus was inadvertently and momentarily de-energized, causing the 2A Emergency Diesel Generator (EDG) to autostart, secondary containment to isolate, and start of the standby gas treatment system. Subsequent investigations revealed that the cause of the event was due to a movement operated contact (MOC) switch adapter was not required to be installed on the 2D normal supply breaker in the 2E 4160 VAC bus. All systems responded appropriately.

A review of the event determined that the MOC switch adapter was not required to be installed by the procedure, but was instructed to be installed by supervision. Corrective actions were taken to cover supervisor roles and responsibilities and the need for all workers to follow plant standards for procedure use and adherence. All breaker procedures and protective relay test procedures were reviewed to determine if a MOC switch adapter needs to be installed. Continuing training will also be held to cover this event and its lessons learned.

On February 10 through February 13, 2017, planned operations with the potential to drain the reactor vessel (OPDRV) activities were performed while Unit 2 remained in Refueling Mode (Mode 5) without an operable secondary containment. These activities are prohibited by Technical Specifications (TS) 3.6.4.1. However, recent NRC guidance provided in Enforcement Guidance Memorandum (EGM) 11-003, Revision 3 and in Regulatory Issue Summary (RIS) 2012-11 allowed the implementation of interim actions as an alternative to full compliance. These actions are contained in the operating procedure for the OPDRV activities performed during the 2017 Hatch Unit 2 Refueling Outage in February.

The performance of OPDRV activities were planned activities that were completed under the guidance of plant procedures and confirmed to have low safety significance based on interim actions taken. Since these actions were deliberate, no cause determination was necessary. A license amendment request (LAR) will be submitted for the associated NRC-approved Technical Specifications Task Force (TSTF) Traveler 542, "Reactor Pressure Vessel Water Inventory Control.

On August 18, 2016 at 1006, while performing the monthly Emergency Diesel Generator (EDG) surveillance, the 2C Limiting Condition of Operation (LCO) 3.8.1.b. The other four EDGs were successfully started for surveillance testing in accordance with Tech Specs to preclude a common cause failure mode. Further inspections were performed and the cross drive shaft between the pump flexible drive gear and the engine driven lube oil pump was found sheared.

The cross drive shaft assembly was replaced and the 2C EDG was declared operable on August 24, 2016 after subsequent functional and post maintenance testing.

Investigations into the failure revealed that the initial cross drive shaft fracture existed prior to the monthly surveillance performed on August 18. The time frame for which the 2C EDG was able to perform its safety function for its 7-day mission time is indeterminable due to the failure mechanism of the cross drive shaft. A loss of safety function is being reported due to the 2C EDG being potentially inoperable during a time in which either the 1B swing EDG was inhibited from Unit 2 or the 1B/2A EDG was inoperable due to normal equipment maintenance and testing.

Additionally, this report constitutes a Part 21 notification per 10 CFR 21.21(d).

On March 30, 2016, Unit 1 was at 100 percent rated thermal power (RIP) when "as-found" testing results of the 3-stage main steam safety relief valves (SRVs) indicated two of the eleven Unit 1 SRVs had experienced a setpoint drift during the previous operating cycle which resulted in their failure to meet the Technical Specification (TS) opening setpoint pressure of 1150 +1- 34.5 psig as required by TS Surveillance Requirement (SR) 3.4.3.1. The test results showed that two SRVs were slightly out of spec low due to setpoint drift.

The SRV pilots were disassembled and inspected while investigating the reason for the drift. SNC has determined that the abutment gap closed pre-maturely. The pre-mature abutment gap closure is most likely due to loose manufacturing tolerances leading to SRV setpoint drift.

On February 13 through 15, 2016, February 15 through 16, 2016, and February 17 through 18, 2016 operations with the potential to drain the reactor vessel (OPDRV) activities were performed while Unit 1 remained in Refueling Mode (Mode 5) without an operable secondary containment. These activities are prohibited by Technical Specifications (TS) 3.6.4.1. However, recent NRC guidance provided in Enforcement Guidance Memorandum (EGM) 11-003, Revision 3 and in Regulatory Issue Summary (RIS) 2012-11 allowed the implementation of interim actions as an alternative to full compliance. These actions are compiled in the operating procedure for the OPDRV activities performed during the 2016 Hatch Unit 1 Refueling Outage in February.

The performance of OPDRV activities were planned activities that were completed under the guidance of plant procedures and confirmed to have low safety significance based on interim actions taken. Since these actions were deliberate, no cause determination was necessary. A licensee amendment request (LAR) will be submitted following NRC approval of the Technical Specification Task Force (TSTF) Traveler associated with generic resolution of this issue (TSTF-542).

On February 16, 2015, February 18 through 19, 2015, and February 23 through 24, 2015 operations with the potential to drain the reactor vessel (OPDRV) activities were performed while Unit 2 remained in Refueling Mode (Mode 5) without an operable secondary containment. These activities are prohibited by Technical Specifications (TS) 3.6.4.1. However, recent NRC guidance provided in Enforcement Guidance Memorandum (EGM) 11-003, Revision 2 and in Regulatory Issue Summary (RIS) 2012-11 allowed the implementation of interim actions as an alternative to full compliance. These actions are compiled in the operating procedure for the OPDRV activities performed during the 2015 Hatch Unit 2 Refueling Outage in February.

!he performance of OPDRV activities were planned activities that were completed under the guidance of plant procedures and confirmed to have low safety significance based on interim actions taken. Since these actions were deliberate, no cause determination was necessary. A licensee amendment request (LAR) will be submitted following NRC approval of the Technical Specification Task Force (TSTF) Traveler associated with generic resolution of this issue (TSTF-542).

On 5/1/2014 at 3:40 PM, with Unit 1 operating at 100 percent rated thermal power (RTP), condensation was found leaking out of the governor end gland seal and the coupling end of the High Pressure Coolant Injection (HPCI) turbine. By taking a temperature reading of the turbine casing, the elevated temperature of the turbine casing at the location monitored indicated that the steam supply isolation valve was leaking by to the HPCI Turbine Exhaust.

Due to a blown fuse, the exhaust drain pot drain valve no longer opened automatically on a high exhaust drain pot level signal. As a result the steam condensate from a leaking steam supply valve eventually filled the exhaust drain pot, the turbine exhaust line, and the turbine itself. With the presence of the blown fuse there was no HPCI Turbine Exhaust Drain Pot Level High annunciation received by the main control room (MCR).

Investigation showed that the blown fuse controlled power to the exhaust drain pot level control switches and alarms. Actions were taken to drain the system and restore power and annunciation by replacement of the affected fuse, and HPCI was returned to an operable status. Additional monitoring of the fused circuit and operation of the drain from the drain pot was established until the plant is in a condition to repair the leaking steam supply valve.

On 8/13/2013, at 1545 EDT, Unit 2 was operating at 100 percent RTP when it was determined that inter-cable analyses for the safe shutdown analysis had not been done using the guidance of Reg Guide 1.189 and NEI 00-01.

An initial analysis for some of the components in the high/low pressure interface systems was performed considering inter-cable shorts as a plausible vector in the Safe Shutdown Analysis. Vulnerabilities were subsequently identified during this circuit analysis, in that postulated fire scenarios can cause two valves required for safe shutdown to open during power operation. At risk are Residual Heat Removal (RHR) valves with controls in Fire Area 2203 (Fire Zone 2203F) and Fire Area 0024. Specifically, during a postulated fire scenario on the affected unit, an inter-cable hot short could occur on the control cables for inboard RHR shutdown cooling isolation valves causing the valves to open while at rated power. In addition, a spurious opening of outboard RHR shutdown cooling isolation valves could occur due to an intra-cable hot short on the control cables in the same postulated event. An intersystem LOCA could then occur when the low pressure system piping is subjected to higher reactor pressures as a result of the postulated conditions.

The cause of the event is attributed to ineffective monitoring and follow-up of regulatory activities involving inter-cable hot shorts in identifying the vulnerabilities associated with these RHR isolation valves. Upon notification, plant operators took actions to de-energize affected valves in the "closed" position to remove the vulnerability.

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On March 18, 2013 at 0910 EDT, the Unit 2 High Pressure Coolant Injection (HPCI) system was declared inoperable after the Turbine Control Valve (TCV) did not open as expected during the HPCI Pump Operability 165 psig Test. Unit 2 was in Mode 2 (Startup) and was not in power production at the time of the event. The TCV failed to open because the hydraulic lines between the hydraulic actuator and the remote servo had been interchanged during performance of the 10-year preventive maintenance (PM) procedure in the 2013 refueling outage for Unit 2.

The lines were properly reconnected, and the HPCI system returned to Operations at approximately 1033 EDT on 3/19/2013. The HPCI operability surveillance was successfully performed at approximately 1056 EDT on 3/19/2013. Additionally, the PM Procedure was revised to include more detailed instructions on the labeling of the hydraulic actuator and remote servo piping prior to removal and to include additional post-maintenance testing criteria for the hydraulic actuator and remote servo.

On 2/16/2013, at approximately 0310 eastern standard time (EST), Unit 2 was in the refueling mode, when a valid unplanned reactor protection system (RPS) actuation occurred as a result of scram discharge volume (SDV) high level. Following shutdown for refueling the scram vent and drain valves would not open as expected which resulted in water remaining in the SDV. The refueling interlocks surveillance testing was being performed in accordance with the Operations surveillance procedure with the SDV water level above the setpoints for the "rod withdrawal block" and the "scram trip" in conjunction with closed SDV vent and drain valves. Jumpers had been installed to bypass the rod block signal, and the scram signal had been bypassed using the "Disch Vol Hi Level Byp" switch.

When the Reactor Mode Switch was placed in the "Start & Hot Standby" position, a full reactor protection system (RPS) actuation occurred. Subsequent investigation revealed that the SDV high level bypass is only active with the mode switch in the "Shutdown" or "Refuel" positions.

The RPS actuation was caused by the presence of a water level in the SDV above the trip setpoint and by a less than adequate procedure. The absence of procedure prerequisites to confirm the SDV Hi Level Rod Block and RPS trip signals were not present prior to performing the refueling interlocks surveillance procedure resulted in positioning the reactor mode switch to the "STARTUP" position with the SDV trip signal present. This caused the SDV high level trip signal to no longer be bypassed resulting in the RPS actuation. The SDV high level condition was cleared and beginning of shift training (BOST) was issued to inform licensed operators of the event. Actions to prevent recurrence involved revision of Units 1 and 2 refueling interlocks surveillance procedures.

On April 16, 2011, during the Hatch Nuclear Plant outage, a local leak rate test (LLRT) was performed on torus purge supply primary containment isolation valve (PCIV) 2T48-F324 which is associated with primary containment penetration 2T23-X205. At that time, plant engineers and technicians were performing an LLRT for penetration 2T23-X205 when it was discovered that both PCIVs had failed their LLRTs for this penetration. This resulted in the penetration leakage exceeding the overall allowable leakage (La) required by the Technical Specifications (TS) for primary containment. This is considered a safety system functional failure of the primary containment function for this penetration.

The primary cause for the excessive leakage for valve 2T48-F324 was attributed to "over-travel" of the valve disc which reduced the seat contact with the disc. This was caused by inadequate procedural guidance for adjusting the valve travel. The excessive leakage for 2T48-F309 was attributed to the valve disc failing to "center" on the seat and wear on the actuator and its linkage. The necessary repairs and adjustments were made and the valves subsequently passed their respective LLRTs, which restored penetration 2T23-X205 to within its TS leakage limits. Additional procedural guidance is being provided to better control "travel" adjustments and in performance of valve inspections.

During operation of Emergency Diesel Generator (EDG) IA for monthly surveillance, at 1443 EDT on June 03, 2010 with the Unit operating at full power, a section of one-quarter-inch tubing in the fuel oil system became disconnected from its fitting rendering EDG1A inoperable due to the potential for fire. Applicable requirements of the Technical Specifications were accomplished and plant operations continued. The tubing's function is to route waste fuel oil from the injectors to the fuel oil collection tank. The tubing separation occurred at the fitting to a discharge check valve which prevents backflow of waste oil to the injectors. This tubing failure occurred subsequent to an observed small amount of leakage at the same location on April 01, 2010. An attempt at that time to stop that leakage by tightening the fitting was unsuccessful. Subsequent to the attempt to stop the leakage, the potential impact on EDG operation was evaluated and judged to be acceptable for EDG operation pending future repair. The apparent cause of both the leakage and subsequent tubing separation was degradation of the tubing connection due to wear and stresses resulting from the repetitive disassembly and re-assembly during scheduled maintenance activities.

Subsequent to both the noted leakage and the tubing separation, the corresponding tubing for the other four EDGs was examined for signs of leakage or cracking. None was found and those EDGs were determined to be operable.