|Report date||Site||Event description|
|05000366/LER-2017-003||13 April 2017||Hatch|
APPROVED BY OMB: NO. 3150-0104 EXPIRES: 10/31/2018 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 Infocollects.Resource@nrc.gov, and to the Desk Officer, Office of Information and Regulatory 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.
|05000366/LER-2017-002||13 April 2017||Hatch|
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.
|05000321/LER-2017-002||7 April 2017||Hatch|
On February 8, 2017, at 1151 EST with Unit 1 at approximately 100 percent rated thermal power, the High Pressure Coolant Injection (HPCI) suction and discharge pressure indicators were noted to be downscale during a main control room panel walk down. Upon further investigation, it was discovered that the output voltage of the DC to AC inverter was degraded. The HPCI DC to AC inverter supplies power to the HPCI flow controller and power supply. HPCI was therefore declared inoperable due to the degraded voltage condition.
The inoperable as found condition of the HPCI pressure indicators was due to degraded output voltage from the DC to AC HPCI inverter. The degraded inverter was removed and replaced and HPCI was returned to operable status. As part of an extent of condition review, the internals of the degraded inverter were inspected to determine what caused premature failure of the inverter. Based on the findings of this inspection, the preventative maintenance frequency for inverter replacement and calibration will be adjusted as necessary.
|05000366/LER-2017-001||3 April 2017||Hatch|
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) 126.96.36.199. 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.
|05000366/LER-2016-004||4 January 2017||Hatch|
On November 7, 2016 at 2355 EST, while performing a main control board panel walkdown, it was d'scovered that the High Pressure Coolant Injection (HPCI) vacuum breaker motor operated isolation valve 2E41F111 had been left in the open position with its breaker turned off. Upon further review of the associated tagout, it was determined that this primary containment isolation valve (PCIV) had been in this inoperable configuration greater than allowed LCO time of 4 hours. The 2E41F111 was then declared inoperable and the 2E41F104 redundant Technical Specifications (TS) LCO 188.8.131.52, Condition A.1.
The inoperable as-found condition of the 2E41F111 PCIV was due to supervision failing to recognize that the tagout preparer did not possess the proper skill set to perform the task. Although the 2E41F111 was left in the open position with its breaker turned off, the manual HPCI turbine exhaust valve 2E41F021 was tagged in the closed position per the tagout instructions. Therefore, closure of the 2E41F021 ensured the affected piping was isolated such that primary containment boundary functions were maintained. Expectations were instituted to ensure individuals assigned with preparing tagouts associated with TS equipment are trained on the basics of TS.
|05000366/LER-2016-003||13 October 2016||Hatch|
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).
|05000366/LER-2016-001||8 June 2016||Hatch|
On 03/17/2016, with Unit 2 at 100 percent rated thermal power (RIP), a fuel oil leak was observed at the inlet to the fuel oil relief valve during the performance of the 2C Emergency Diesel Generator (EDG) semi-annual surveillance. The 2C EDG was declared inoperable until the relief valve was replaced. Investigation revealed that the leak was due to a through wall indication in the threaded area of the relief valve. Inspection indicated that the failure was consistent with flaws observed in cases of fatigue failures. Site analysis of the failure provided reasonable assurance of historic operability; however a vendor was engaged to perform an independent review with a detailed seismic model of the system.
On 4/13/2016, the vendor analysis indicated that a seismic event could cause the degraded fuel oil relief valve to adversely affect EDG operation. The analysis concluded that although the 2C EDG could have met its 7-day mission time with the existing leakage rate, a design basis earthquake could reduce the ability of the diesel to maintain the minimum fuel header pressure and sufficient amount of fuel for 7 days. Thus the seismic qualification of the 2C EDG was degraded, but the safety function of the emergency AC system would only be challenged under certain circumstances with a seismic event.
Corrective actions will establish periodic replacement of similar fuel oil relief valves on the EDGs.
|05000321/LER-2016-004||26 May 2016||Hatch|
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) 184.108.40.206. 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.
|05000321/LER-2016-003||14 April 2016||Hatch||During the 2016 Unit 1 R27 refueling outage, plans were put in place to upgrade the 1631-1RC-12BR-E-5 (1631-E5) design weld overlay (WOL) to a full structural weld overlay (FSWOL) in order to allow for code qualified examinations. On February 16, 2016 at 0631 EST, during surface preparation work, axial indications were found on the WOL. Evaluation of the indications found in the weld overlay suggests that the non-satisfactory PT examination was a result of the propagation of the original flaw that was found on the 1 E Recirculation Loop Piping. The original indication had propagated into the Incoiiel Alloy 82 WOL material installed in 1988. It was determined that the as-found condition of the flaw did not meet ASME Section XI acceptance criteria. The indications were removed from the WOL and 1B31-E5 was upgraded to a full structural weld overlay using intergranular stress corrosion cracking (IGCSS) resistant Alloy 52 weld material.|
|05000321/LER-2016-002||11 April 2016||Hatch|
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) 220.127.116.11. 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).
|05000321/LER-2016-001||8 April 2016||Hatch|
On 02/11/16, Unit 1 fuel movement activities were restarted after repairs to the main grapple camera. A refueling interlock of the main grapple was encountered while moving a double blade guide, caused by the disconnection of 20 Rod Position Information System (RPIS) Position Indicating Probes (PIPs). The operating crew began troubleshooting and determined that bypassing the RPIS probe "full-in" would clear the interlock. However the crew used a section of the site specific procedure for control rod withdrawal during refuel that wasn't applicable at the time.
The RPIS indications were bypassed and the movement of the double blade guide was recommenced at 12:00 followed by fuel movement. After a review of Technical Specifications 3.9.4, it was determined that fuel movement should not be performed with the RPIS probe disconnected and bypassed because the associated control rods were not disarmed with a tagout. Fuel movement activities were then halted.
|05000366/LER-2015-002||15 April 2015||Hatch|
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) 18.104.22.168. 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).
|05000321/LER-2014-003||7 July 2014||Hatch|
On May 7, 2014, at approximately 0837, Unit 1 was at 99.9 percent rated thermal power (RTP) when the "as-found" testing results of the 2-stage main steam safety relief valves (SRVs) were received which indicated that five of eleven SRVs had experienced setpoint drift during the previous operating cycle which resulted in their failing to meet the Technical Specification (TS) opening setpoints of 1150 psig +/- 3 percent as required by TS surveillance requirement 22.214.171.124.
The root cause of the SRV setpoint drift is attributed to corrosion-induced bonding between the pilot disc and seating surfaces. This conclusion is based on previous root cause analyses and the repetitive nature of this condition at Hatch and within the BWR industry. The 2-stage SRVs with platinum coated pilot seats were removed from Unit 1 during the 2014 refueling outage and replaced with 3-stage SRVs with a modified pilot. 3-stage SRVs typically do not exhibit set point drift, additionally the modified pilot reduces instances of vibration induced spurious openings and leak-by.
A 3-stage SRV with a similar modified pilot was installed on Unit 2 during the 2013 outage. Current plans are to replace the remaining ten valves at Unit 2 with the same modified pilot valves during the next outage in 2015.
NRC FORM 368 (02-2014)
|05000321/LER-2014-002||27 June 2014||Hatch|
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.
|05000321/LER-2014-001||5 June 2014||Hatch|
On March 14, 2014 at 11:50 AM, with Units 1 and 2 operating at 100 percent rated thermal power (RTP), a review of industry operating experience concerning postulated fire induced circuit failures of unfused DC ammeter circuits determined the described condition was applicable to Edwin I. Hatch Units 1 and 2 reactor protection system (RPS) battery/battery charger ammeter circuits. This review determined that a postulated fire could result in concurrent shorts of an unfused DC ammeter cable and a DC cable of opposite polarity. Due to a lack of overcurrent protection on the ammeter cables, the resultant excessive current flow and overheating of the ammeter cable could result in in a secondary fire in another fire area that could adversely affect fire safe shutdown capability and create an unanalyzed condition with respect to 10 CFR 50 Appendix R analysis requirements for this postulated condition.
The current configuration has apparently existed since construction. The original design standards did not account for this situation and did not call for overcurrent protection on these circuits.
Compensatory actions taken were to establish required fire watches with subsequent actions taken to de- energize the affected circuits which removed the described vulnerability until design changes are implemented to correct the deficiency.
|05000366/LER-2013-004||1 April 2014||Hatch|
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.
|05000366/LER-2013-005||8 January 2014||Hatch|
On September 13, 2013 at 1438 EDT, with the unit in Mode 1 at 100 percent power, the Unit 2 'D' outboard main steam isolation valve (MSIV) failed to move during surveillance testing that involved partial closure testing of the valve. Based on previous operating experience this test result typically indicated a problem with a solenoid used for partial valve closure testing and was not indicative of a problem with the MSIV. A plan was made to cycle the MSIV to the "closed" position and return it to the "open" position during a planned power reduction on September 14, 2013. If the failure was indeed due to the test solenoid, the affected MSIV would function as expected after the power reduction.
At 1105 EDT on September 14, 2013, following power reduction to approximately 65 percent power, the 'D' outboard MSIV failed to close using its control switch. Actions were taken to isolate the MSIV penetration as required by Technical Specifications. Maintenance activities were completed and the MSIV underwent rigorous testing with successful results to confirm the operability of the 'D' outboard MSIV.
|05000366/LER-2013-003||14 June 2013||Hatch|
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.
|05000366/LER-2013-002||19 April 2013||Hatch|
On February 19, 2013, February 20, 2013 and February 25, 2013, OPDRV activities were performed while 1-1NP-2 remained in Mode 5 without an operable secondary containment. These activities are prohibited by Technical Specifications (TS) 126.96.36.199, however recent NRC guidance provided in Regulatory Issue Summary (RIS) 2012-11 and in Enforcement Guidance Memorandum (EGM) 1.1-003, Revision I allowed the implementation of interim actions as an alternative to full compliance. These actions were compiled in an operating procedure for the OPDRV activities performed at HNP-2 during the 2R22 Refueling Outage in February.
The 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 will be submitted following NRC approval of the Technical Specifications Task Force (TSTF) traveler associated with generic resolution of this issue.
NFIC FORM 366 (9.2007) PRINTED ON RECYCLED PAPER
|05000366/LER-2013-001||12 April 2013||Hatch|
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.
|05000321/LER-2012-003, Leak in Reactor Pressure Boundary at Small Bore Piping Fillet Weld||10 May 2012||Hatch||On 3/13/2012, during the Reactor Pressure Vessel (RPV) Pressure Test walk-down with the unit in Mode 4 for leakage testing, a through-wall leak was identified in a small bore line located upstream of a High Pressure Coolant Injection (HPCI) valve inboard of the piping's connection to the Main Steam piping. The leak identified during this event was in the thicker portion of the fillet weld adjacent to the socket elbow. D Initial evaluation of the crack in the subject HPCI piping and elbow by an experienced site Quality Control inspector and a senior Southern Nuclear metallurgist concluded that the most apparent cause of the weld defect that led to the leak was inadequate root penetration in the weld. The actual cause has not yet been fully determined. The section of piping in which the leak was located will be sent to a vendor for inspection and expert determination of the most probable cause of the through-wall leak. Following removal and repair of the subject piping, a leak test was performed at 920 psig with no leaks identified. The Technical Specification (TS) definition of pressure boundary leakage is leakage through a non-isolable fault in the reactor coolant system: D By its location, the leak met this definition. Inspection of the weld and adjacent areas determined the leak had existed when the Unit was in Mode 1, and no such leakage is allowed by TS.|
|05000321/LER-2012-003||10 May 2012||Hatch|
On 3/13/2012, during the Reactor Pressure Vessel (RPV) Pressure Test walk-down with the unit in Mode 4 for leakage testing, a through-wall leak was identified in a small bore line located upstream of a High Pressure Coolant Injection (HPCI) valve inboard of the piping's connection to the Main Steam piping. The leak identified during this event was in the thicker portion of the fillet weld adjacent to the socket elbow. D Initial evaluation of the crack in the subject HPCI piping and elbow by an experienced site Quality Control inspector and a senior Southern Nuclear metallurgist concluded that the most apparent cause of the weld defect that led to the leak was inadequate root penetration in the weld. The actual cause has not yet been fully determined. The section of piping in which the leak was located will be sent to a vendor for inspection and expert determination of the most probable cause of the through-wall leak. Following removal and repair of the subject piping, a leak test was performed at 920 psig with no leaks identified. The Technical Specification (TS) definition of pressure boundary leakage is leakage through a non-isolable fault in the reactor coolant system: D By its location, the leak met this definition. Inspection of the weld and adjacent areas determined the leak had existed when the Unit was in Mode 1, and no such leakage is allowed by TS.
NRC FORM 5E8 (9-2007) PRINTED ON RECYCLED PAPER Edwin I. Hatch Nuclear Plant Unit 1 05000321
|05000366/LER-2011-003||12 February 2012||Hatch|
On October 24, 2011, at approximately 0% power during startup from a scheduled maintenance outage, the 'A' IRM signal showed increasing levels of electrical noise while on Range 1. A spike in the signal resulted in a half-scram signal that prompted Operations personnel to bypass the 'A' IRM and declare it inoperable. The 'C' IRM subsequently began exhibiting erratic behavior and slowly drifted downscale while on Range 7. Operations personnel "ranged" down the 'C' IRM. Its signal continued to display the same behavior. Operations personnel declared the 'C' IRM inoperable, resulting in no operable IRM channel in one quadrant of the reactor core. Further control rod withdrawal to maintain the core critical was prohibited. Operations personnel were then directed to insert a manual scram signal.
Testing revealed the direct cause to be degraded signal cable shielding at under-vessel connectors in six of eight IRM channels allowing electrical noise to couple to the signal conductor. The noise was caused by a consistent low frequency signal on the preamplifier signal input and output cables and by degraded connectors. PM intervals were previously based on time rather than on duty cycle resulting in unidentified connector degradation.
Connectors were replaced and post maintenance testing confirmed noise had been reduced to acceptable levels. PM frequency changed based on duty cycle.
|05000366/LER-2011-001||9 December 2011||Hatch|
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.
|05000366/LER-2011-002||30 August 2011||Hatch|
On July 5, 2011, at approximately 1000 EDT, Unit 2 was at 100 percent rated thermal power (RTP) when the "as-found" testing results of the 2-stage main steam safety relief valves (SRVs) were received which indicated that eight of eleven SRVs had experienced setpoint drift which resulted in their allowable Tech Spec limits being exceeded.
The root cause of the SRV setpoint drift is attributed to corrosion-induced bonding between the pilot disc and seating surfaces. This conclusion is based on previous root cause analyses and the repetitive nature of this condition at Hatch and within the BWR industry.
The 2-stage SRVs were removed from Unit 2 in April 2011, and preemptively replaced with 3-stage SRVs as the long term corrective action for the historically observed setpoint drift. The use of 3-stage SRVs is regarded as an industry-wide solution for the corrosion-induced bonding phenomenon which has been a historic industry issue since the early 1980s.
|05000321/LER-2010-004||30 July 2010||Hatch|
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.
|05000366/LER-2007-005||14 May 2007||Hatch|
On March 15, 2007 at approximately 1532 EDT, Unit 2 was in the start-up mode at a reactor pressure of approximately 155 psi and estimated power level of one percent. The low pressure start-up testing of the High Pressure Coolant Injection (HPCI) system was in progress when the system failed to perform as required. Operations personnel entered the applicable Technical Specification for HPCI inoperable. Troubleshooting was performed to determine the cause of the failure and the system was repaired. Specifically the Electronic Governor Remote (EGR), Reduction Gear Unit, and the Duplex Filters were all replaced. The oil in the HPCI turbine was also replaced. The low pressure start-up testing of the HPCI system was re-performed successfully and the HPCI system was returned to service at 1435 EDT on March 16, 2007.
This event was caused by corrosion of the EGR Actuator internals. The corrosion of the EGR internals is attributed to an event that occurred earlier in the refueling outage. During that event, water was introduced into the HPCI bearing oil system through a path created by a tagout. The root cause associated with the tagout event is that the drafter and reviewer of the tagout did not adequately address the system or functional impact associated with the components that were tagged or removed from service.
NRC FORM 388 (6-2004)