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On August 28, 2017, at 0837, VCSNS Unit 1 automatically tripped due to a turbine trip. The turbine trip was caused by the Main Generator Differential Lockout due to a fault on the center phase, 230 kV lightning arrester, on the Main Transformer (XTF-1).

The plant trip response was normal. All control rods fully inserted. Balance of Plant (BOP) buses automatically transferred to their alternate power source, Emergency Auxiliary Transformers (XTF-31/32). Both Motor Driven (MD) Emergency Feedwater (EF) pumps and the Turbine Driven EF Pump started as designed.

The cause of this event was the failure of the center phase lightning arrester on XTF-1. The failed arrester, along with the other two lightning arresters that were in service on XTF-1 during the reactor trip, was replaced. The lightning arresters were sent to an independent lab, NEETRAC - Georgia Tech, for testing and evaluation.

The examination results indicate that the most probable cause of the arrester failure was an internal flashover of the metal oxide varistor blocks. The cause of the internal flashover is likely moisture ingress from the upper end seal.

On February 13, 2017, LaSalle County Station Unit 1 was in Mode 1 at 100 percent power and Unit 2 shut down for a planned refueling outage. At 2309 CST, a reactor scram signal was received on Unit 1 due to turbine control valves fast closure while the station was aligning back-feed operation to the Unit 2 main power transformer (MPT). The Unit 1 turbine trip was due to the main generator trip on differential current. The plant was placed in a stable condition with reactor pressure maintained by the turbine bypass valves and reactor water level controlled using feedwater. Unit 2 was unaffected by the event.

The root cause of the Unit 1 trip on differential current was a marginal generator differential relay design that was prone to responding to faults outside its zone of protection. Both units' 345 kV ring buses were connected together through the cross-tie bus, which allowed the Unit 1 generator to supply some of the electrical current that resulted in its differential circuit to create an unbalanced current that actuated the differential relay.

This event is reportable in accordance with 10 CFR 50.73(a)(2)(iv)(A) as an event or condition that resulted in manual or automatic actuation of the reactor protection system (RPS), including reactor scram. There were no safety consequences associated with the event since RPS and other emergency safety systems functioned as designed.

On May 9, 2015, an automatic reactor trip (RT) occurred due to a Turbine-Generator trip as a result of a failure of the 31 Main Transformer (MT). All control rods fully inserted and all required safety systems functioned properly. The plant was stabilized in hot standby with decay heat being removed by the condenser. There was no radiation release. The emergency diesel generators did not start as offsite power remained available. The auxiliary feedwater system actuated as-expected due to steam generator low level from shrink effects. Control room operators received alarms on the fire detection panel of the activation of the 31 MT and curtain wall deluge valves. Report to operators that there was an explosion and fire on the 31 MT. The plant fire brigade responded to the fire. The 31 MT had failed. Due to collateral influence from the 31 MT failure, the deluge system for the 32 MT and Unit Auxiliary transformer had also activated. In accordance with the emergency plan a Notice of Unusual Event (NUE) was declared at 1801 hours, which was terminated at 21:04 hours. The direct cause was an internal fault of the A Phase high voltage winding in the upper portion of the transformer.

The root cause was vendor design/manufacturing deficiency that caused an internal failure that resulted in a fault on the A phase HV side of the transformer and the A phase HV voltage bushing. Key corrective actions included replacement of the 31 MT with a spare transformer, associated acceptance testing, repair of the isophase bus ducting for the 31 MT, inspections, cleaning, testing of the 32 MT, the Unit Auxiliary Transformer, high voltage components, isophase buses and main generator. A 4-year PM was prepared to perform Partial Discharge testing on the Unit 2, and Unit 3 MTs, Unit 2 and Unit 3 Auxiliary Transformers and the Unit 3 GT Auto Transformer The event had no significant effect on public health and safety.

FACILITY NAME (1) DOCKET (2) LER NUMBER (6) PAGE (3)

On March 29, 2016, at 1123 Central Daylight Time, Grand Gulf Nuclear Station was operating in Mode 1 and ascending in power at approximately 37% when an unplanned uncomplicated automatic reactor SCRAM occurred. A generator lockout was received due to a Main Transformer 'B' Differential Relay Trip which was followed by a turbine control valve fast closure, turbine trip, and reactor SCRAM. The Reactor Protection System and all other safety systems functioned as designed. The cause of the Main Transformer 'B' Differential Relay Trip was identified during forced outage investigation of the 'B' Main Transformer control cabinet. The high voltage current transformer wiring was incorrectly landed at the X1/X2 terminals instead of the X1/X3 terminals. This wiring configuration resulted in a turns ratio of 1000:5 instead of the designed 2200:5, causing relay actuation at a point lower than designed. The erroneous wiring configuration was corrected and all remaining wiring for the 'A', '6', and 'C' Main Transformer wiring was verified correct prior to startup from the forced outage. This event posed no threat to public health and safety.

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 internet 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 collection.

366A U.S. NUCLEAR REGULATORY COMMISSION

CONTINUATION SHEET

2. DOCKET 3. LER NUMBER 05000 416

PLANT CONDITIONS PRIOR TO THE EVENT

At the time of the event, Grand Gulf Nuclear Station (GGNS) Unit 1 was in Mode 1 and ascending in power at approximately 37% rated thermal power. All systems, structures and components that were necessary to mitigate, reduce the consequences of, or limit the safety implications of the event were available. No safety significant components were out of service.

DESCRIPTION

On March 29, 2016, Grand Gulf Nuclear Station (GGNS) was ascending in power for the unit startup following Refueling Outage 20 (RF 20). As reactor power reached approximately 37% rated thermal power, a generator lockout was received followed by a turbine control valve fast closure and turbine trip which resulted in an uncomplicated automatic reactor SCRAM. The generator lockout was the result of the Main Transformer 'B' Differential Relay Trip. The reactor protection system (RPS) (JC) and all safety systems functioned as designed and expected.

During the investigation, it was discovered inside the 'B' Main Transformer control cabinet that the high voltage current transformer (CT) (XCT) turns ratio wiring was incorrect. The CT wiring was connected in a manner that produced a turns ratio of 1000:5 versus the designed 2200:5. Due to this erroneous configuration the CT trip setpoint was lower than designed. Therefore, the CT and current differential relay actuation was not an equipment failure but an actual sensed actuation based on an incorrect wiring scheme. Work orders that involved working inside this panel during RF 20 were reviewed to determine when the wiring was altered. No work on CT wiring found incorrectly landed was intended to be performed during RF 20. Current Transformer ratio wiring work was not within the scope of the transformer rewiring project carried out during RF20. The most likely time the wiring was incorrectly removed and re-landed would have been during the post modification testing which was performed under a work order at the conclusion of the wiring project.

REPORTABILITY

This Licensee Event Report (LER) is being submitted pursuant to Title 10 Code of Federal Regulations (10 CFR) 50.73(a)(2)(iv)(A) for an automatic actuation of the RPS.

Telephonic notification was made to the U.S. Nuclear Regulatory Commission (NRC) Emergency Notification System on March 29, 2016, within 4 hours of the event pursuant to 10 CFR 50.72(b)(2)(iv)(B) and 10 CFR 50.72 (b)(3)(iv)(A) for a valid RPS actuation while the reactor was critical.

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 internet 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 collection.

NRC FORM

366A U.S. NUCLEAR REGULATORY COMMISSION

CONTINUATION SHEET

CAUSE

2. DOCKET 3. LER NUMBER 05000 416 Direct Cause: The 'B' Main Transformer X21 CT wiring was incorrectly landed at X1/X2 terminals instead of the X1/X3 terminals. This changed the ratio of the 'B' Main Transformer Current Differential Relay from the designed 2200:5 to 1000:5, which resulted in a lower trip setting than designed for the 'B' Main Transformer Differential Overcurrent trip.

Cause 1: Vague or inadequate work instructions provided in the testing and troubleshooting work package.

Cause 2: Insufficient testing following completion of all work.

CORRECTIVE ACTIONS

The immediate corrective action was to correct the 'B' Main Transformer CT wiring and verify all other wiring in the 'A', 'B', and 'C' Main Transformer control cabinets was correct. No other issues with wiring was identified during this verification.

Two corrective actions to prevent reoccurrence were identified:

1. Revise procedure(s) to require lifted lead sheet use (or similar table with performer and verifier signatures) in all work instructions where wiring determinations and/or re-terminations are performed at GGNS.

2. Revise the Post Maintenance Testing procedure to include clear guidance from SOER 10-01 (as delineated in the Post Modification Testing and Special Instructions procedure) for transformer work.

SAFETY SIGNIFICANCE

The event posed no threat to the health and safety of the general public or to nuclear safety as RPS performed as designed. All safety systems responded as expected and Operator actions were in accordance with GGNS procedures. No Technical Specification safety limits were challenged or violated. Industrial safety was not challenged, and there was no potential or actual radiological release during the event.

PREVIOUS SIMILAR EVENTS

The Main Transformers were installed in April 2012 to support Extended Power Uprate (EPU). Since the installation, there have been three RPS SCRAMs on main turbine trips associated with CTs prior to this event. These are documented in LER-2012-008-00, LER-2013-01-00, and LER-2015-001-00.

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 internet 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 collection.

NRC FORM

366A U.S. NUCLEAR REGULATORY COMMISSION

CONTINUATION SHEET

2. DOCKET 3. LER NUMBER 05000 416 The cause of LER-2015-001-00 was not similar to the event being reported, and the corrective actions would not have prevented the March 29, 2016 reactor SCRAM.

The cause of LER-2012-008-00 and LER-2013-001-00 was inadequate workmanship and work instructions that did not specify the minimum cold clearance of 0.5 inch between the CT and the micarta plate bolts during installation. The corrective actions addressed revising procedures, testing notes, work instructions, and drawings to ensure the minimum 0.5 inch cold clearance is maintained. Although these two events were attributed to inadequate work instruction, the corrective actions would not have prevented the March 29, 2016 reactor SCRAM.

Between 11/18/2014 and 12/3/2014, the 'B' MDAFW train was inoperable due to an improperly functioning positioner card installed on the control valve in the AFW flow path to the 'D' steam generator, i.e., valve ALHV0005. The 'A' MDAFW train and the TDAFW train were inoperable for short durations at different times between 11/18/2014 and 12/3/2014, although neither of those redundant trains was inoperable at the same time. During the short windows of TDAFW unavailability, only a single MDAFW train was operable, resulting in a loss of safety function.

On 08/11/2015, an unexpected turbine trip / reactor trip occurred due to a latent design error in the current transformer (CT) wiring for the main transformers. The reactor trip was reported to the NRC in Event Notification 51308. While responding to the reactor trip, the 'B' train motor-driven auxiliary feedwater (MDAFW) flow control valve in the auxiliary feedwater (AFW) flow path to the `A' steam generator, i.e., valve ALHV0007, could not be manipulated from the main control room. It was determined that ALHV0007 would have performed its specified safety function; however, during the extent of condition review, it was determined that ALHV0005 was inoperable from 11/18/2014 until 12/3/2014. The 72-hour Completion Time of Condition C of Technical Specification 3.7.5 was exceeded from 11/18/2014 until a new positioner card was installed on ALHV0005 on 12/3/2014.

The direct cause of the ALHV0005 failure was a failure of a bridge rectifier on the valve's electronic positioner circuit card. This type of positioner card was also installed on ALHV0007. The root cause of the card failures was determined to be a vendor design deficiency. The defective positioner cards have been replaced and measures have been taken to remove defective spares from future plant use.

On August 11, 2015, at 01:39 Callaway plant tripped from 100% power due to an incorrect, automatic response to a transmission line fault on the Montgomery-Callaway 8 line by transformer bus differential relaying. This resulted in Reactor Protection System (RPS) and Auxiliary Feedwater System actuations. The plant response to the trip was as expected except for a problem encountered with Auxiliary Feedwater flow control valve ALHV0007 subsequent to the plant trip.

This event was caused by the inadvertent inclusion of jumpers in the current transformer (CT) circuits of the main transformers that were installed as part of Main Transformer Replacement Modification 09-0044 implemented in Refuel 19. Following the event, the inadvertently placed CT jumpers were removed and the plant was successfully restarted.

The preliminary root cause of the incorrect main transformer CT wiring was failure to revise drawing E-23MA02, "Generation System - Three Line Metering & Relaying Diagram," which was missing information on connections to switchyard protective relays and included jumpers that were not supposed to be installed. Post-modification testing performed by System Relay Services did not detect the improper jumpers.

Corrective actions include additional design, testing and job reviews, as well as reviews of similar drawings to identify and correct missing information.

On Tuesday January 27, 2015, at 0402 hours, while in the process of lowering reactor power, with the reactor in the RUN mode at 52 percent core thermal power, Pilgrim Nuclear Power Station (PNPS) experienced a loss of 345KV power resulting in a load reject and an automatic reactor scram. The loss of 345KV power was due to faults from flashovers in the PNPS switchyard. All control rods fully inserted.

The Emergency Diesel Generators had been previously started and were powering safety-related buses A5 and A6. The plant stabilized in Hot Shutdown. At the time of the event a significant winter storm (Juno) was buffeting Southern New England.

The root cause of the event is that the design of the PNPS switchyard does not prevent flashover when impacted by certain weather conditions experienced during severe winter storms. A modification of the switchyard is planned to address the susceptibility of the PNPS switchyard to flashovers during severe winter storms.

This event posed no threat to public health and safety.

On November 5, 2013 at 1747 hours, Beaver Valley Power Station (BVPS) Unit 1 was operating at 47 percent power after the 1R22 Refueling Outage. The Unit 1 Control Room received multiple unexpected alarms. The Turbine/Generator tripped due to Unit Station Service Transformer (USST) "BV-TR-1C" differential protection relay actuation. This transformer was energized but not in service at the time. The reactor operator manually tripped the reactor due to multiple unexpected alarms. An automatic reactor trip signal was not generated due.to the fact that the reactor was operating at a power level less than the turbine trip - reactor trip setpoint of 49 percent power. The Steam Driven Auxiliary Feedwater (AFW) pump automatically started due to low level in the "C" Steam Generator. The "B" Motor Driven AFW pump was manually started to assist in maintaining steam generator levels. An Unusual Event was turbine building mezzanine. The cause of this event was determined to be a fault in the "B" 4KV bus supply cables from BV-TR-1C that resulted in an arc flash and subsequent fire. Corrective actions include planned replacement of the faulted supply cables and inspections of the remaining Unit 1 and Unit 2 4KV bus supply cables for signs of degradation and aging.

This event is being reported under 10 CFR 50.73(a)(2)(iv)(A) as a condition that resulted in the valid manual and automatic actuation of systems listed in (a)(2)(iv)(B) - (1) manual Reactor trip, (6) manual and automatic Auxiliary Feedwater pump start. A 10 CFR 50.72 notification was made at 1927 hours on November 5, 2013 to report entry into an Unusual Event, RPS Actuation and a Specified System, Auxiliary Feedwater actuation (EN 49505).

On October 11, 2013, at 1319 hours with Unit 1 operating at 48 percent power (Mode 1), an automatic turbine trip and subsequent reactor trip occurred due to a lockout relay actuation for the 1C Station Service Transformer (1-EP-SST-1C). The lockout occurred simultaneously with the start of the 1C Condensate Pump (1-CN-P-1C). The direct cause of the 1-EP-SST-1C lockout is that current transformer terminal block shorting screws were left installed inside the 1- EP-BKR-15C2 breaker cubicle. The root cause of the event was less than adequate written instructions for documenting the installation and removal of the terminal block shorting screws.

All safety system responded as expected. The Auxiliary Feedwater Pumps actuated as designed following the reactor trip and provided makeup flow to the Steam Generators. 1-EP- SST-1C was inspected and no signs of damage or abnormal conditions were observed. At 1507 hours, a 4 hour report was made to the NRC in accordance with 10CFR50.72(b)(2)(iv)(B) for a Reactor Protection System (RPS) actuation and a 8 hour report in accordance with 10CFR50.72(b)(3)(iv)(A) for a Auxiliary Feedwater system actuation. The event is reportable pursuant to 10CFR50.73(a)(2)(iv)(A) for a condition that resulted in the automatic actuation of the RPS and AFW Systems. The health and safety of the public were not affected by the event.

On Friday February 8, 2013, at 2117 hours with the reactor initially at 85% core thermal power, Pilgrim Nuclear Power Station (PNPS) experienced a loss of off-site power (LOOP) resulting in a load reject and a reactor scram. All rods fully inserted and the Emergency Diesel Generators automatically started and powered safety-related buses A5 and A6. All other safety systems functioned as required.

The plant stabilized in Hot Shutdown. At the time of the event a significant winter storm (Nemo) was buffeting Southern New England. At 2200 hours PNPS in conjunction with the local grid operator determined off-site power sources were not reliable and efforts to restore off-site power were temporarily suspended. At 2200 hours, PNPS declared a Notification of Unusual Event. On February 10, at 1055 hours, one of two off-site power supplies was restored, all safety buses were powered from the startup transformer and the Unusual Event was exited. Later on February 10, at 1402 hours with the plant in Cold Shutdown, ice bridging on a startup transformer insulator caused its 345 KV supply breaker to open resulting in a second LOOP. Again the EDG's started and powered safety-related buses. All other safety systems functioned as required. Shutdown cooling was restored at 1426 hours.

On February 10, at 2020 hours, this occurrence was reported to the USNRC as documented in EN# 48739.

The severe winter storm which caused extensive generalized geographical damage to the electrical distribution network was root cause of the LOOP events.

These events posed no threat to public health and safety.

With Essential Cooling Water (ECW) Pump 2B unknowingly inoperable, the plant staff was unaware that the associated Limiting Conditions of Operation (LCO) were not met when Unit 2 reached greater than 5% rated thermal power and entered Mode 1 on 01/07/2013 at 0053, in violation of LCO 3.0.4. This event is considered reportable under 10 CFR 50.73(a)(2)(i)(B).

On 01/06/2013 at 2100, just prior to the mode change, a temperature excursion began on the ECW Pump 2B lower motor bearing, which peaked below the alarm setpoint before returning to normal by 01/07/2013 at 0125.

This excursion was identified on 01/14/2013. Analysis of subsequent vibration data indicated a bearing defect with a step increase in vibration data. Without reasonable assurance that the pump would meet its mission time, ECW Pump 2B was declared inoperable on 01/15/2013 at 1200. Due to lack of any other abnormal temperature or vibration data available for the degraded condition, the pump is considered to have been inoperable since the start of the temperature excursion.

The bearing degradation was due to insufficient tolerance in the motor shaft endplay, as set during refurbishment.

Corrective actions are planned to specify this design parameter for subsequent refurbishments, and to increase endplay adjustment shim thickness in the affected ECW pump motors to reduce bearing wear.

On October 18, 2011, at 0351 hours, the plant entered MODE 2 during plant startup. One of the two offsite power circuits required by Technical Specification (TS) 3.8.1, "AC Sources-Operating," was the delayed access circuit through the unit one auxiliary transformer. At 1619 hours, the manual disconnects for yard breakers S610 and S611 (isolation between offsite and onsite AC power distribution), were found to be open with danger tags installed. In this configuration, a TS Required Action was not performed within its designated Completion Time and a MODE change was made without satisfying the associated Limiting Condition for Operation (LCO). By 1730 hours, the danger tags were removed and the delayed access circuit was returned to OPERABLE status.

Switchyard equipment configuration, necessary to maintain reliable sources of offsite power, was not held to the same operational configuration standards required for plant controlled equipment, due to less than adequate policies governing the plant's switchyard configuration cognizance.

Corrective actions include completed and planned procedure revisions to ensure control room personnel are aware of switchyard configuration and training will be provided to appropriate plant personnel. The safety significance of this condition is considered to be small.

This event is being reported 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.

On August 27, 2011, at 2248 eastern daylight time, Unit 1 experienced an automatic reactor trip from 100 percent power. The Reactor Protective System actuated on loss of load. The loss of load occurred due to a phase-to-phase short circuit on the main transformer when main transformer lines were struck by dislodged Turbine Building siding caused by winds associated with Hurricane Irene. Immediately following the short circuit, 14 Containment Air Cooler stopped operating. Shortly after the plant trip occurred, 1A Emergency Diesel Generator was declared inoperable due to a shorted speed switch. The root cause analysis performed to address this event concluded that the Turbine Building Northwest corner siding was not installed per design during original construction. This resulted in a weaker siding connection to the Turbine Building structure, allowing the siding to come off in wind speeds less than design.

At Calvert Cliffs, there have been no recent similar events involving a reactor trip associated with severe weather. This event is being reported pursuant to 10 CFR 50.73(a)(2)(iv)(A) due to Reactor ProteCtive System actuation. Corrective actions include testing and inspection of the main transformer, replacement of B and C phase high line drops to the main transformer and inspection and repair of electrical connectors on the 1A Emergency Diesel Generator.

On November 7, 2010, an automatic reactor trip (RT) was initiated as a result of a turbine-generator trip due to actuation of the main generator primary and back-up lockout relays. All control rods fully inserted and all primary systems functioned per design except for the 138 kV Station Auxiliary Transformer tap changer. The plant was stabilized in hot standby with decay heat being removed by the main condenser (SG). Based on reports of two explosions an Alert was declared in accordance with the emergency plan which was terminated at 22:18 hours. There was no radiation release. The Emergency Diesel Generators did not start as offsite power remained available. The Auxiliary Feedwater System automatically started as expected due to SG low level from shrink effect. The direct cause of the RT was due to actuation of the 86P and 86BU relays that sensed a fault from the failure of 21 main transformer (MT) as a result of a low impedance fault of the 345 kV Phase B bushing. The root cause was an internal failure of the phase B bushing due to a vendor design/manufacturing deficiency.

Corrective actions include replacement and acceptance testing of the 21 MT, external visual inspections of the 22 MT HV bushings, Unit Auxiliary Transformer (UAT), Iso-phase bus and 345 kV feeder W95, testing of the 22 MT, UAT, Iso-phase bus and HV components. Damaged HV components were replaced. The bushings for the 21 and 22 MT were replaced with another manufacturers bushing. The event had no effect on public health and safety.

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On January 20, 2010, Comanche Peak Nuclear Power Plant (CPNPP) Unit 1 was in Mode 3 during a planned outage and Unit 2 was in Mode 1 operating at 100% power. At 1827 hours, during review of an Oconee INPO OE report, parallels were discovered between the Oconee design and the CPNPP design. Further investigation determined that the required completion times for TS 3.3.2, Condition J, may not have been completed in the past when Units 1 and 2 were operating at low power with only one MFWP providing MFW flow.

The cause analysis of this event determined that the plant design and original operating philosophy was not compatible with the NRC's clarification of the intent of TS 3.3.2, Function 6.g. Corrective actions include the completion of procedure changes on Unit 1 to ensure compliance with TS. Since Unit 2 has been operating at 100% power with both MFW pumps in service since discovery of this condition, corresponding changes to the Unit 2 procedures will be completed prior to removing one MFW pump from service during the next shutdown of Unit 2 or prior to startup of Unit 2 from any event which results in an unplanned trip of Unit 2.

All times in this report are approximate and Central Standard Time unless noted otherwise.

On April 25, 2009, with the unit at 100% power, loss of cooling to the Main Power Transformer M1A resulted in a manual plant scram. The loss of cooling was caused by a faulted cooling bank motor starter, resulting in the failure of the MIA auxiliary control power transformer and subsequent loss of control power for the remaining cooling bank motor starters. A reactor load reduction was commenced in accordance with the alarm response procedure to maintain MIA temperatures below the alarm set points. While reactor power was being reduced, transformer operation was limited to 30 minutes without forced cooling. Operations secured the power reduction and manually scrammed the reactor from 74% power in accordance with plant procedures. The post scram response was normal and the required notifications were made.

All safety systems operated as expected following the reactor scram.

There were no safety consequences impacting plant or public safety as a result of this event.

This event is being reported pursuant to 10CFR50.73(a)(2)(iv)(A) due to manual actuation of the reactor protection system.

On February 1, 2009 the Oyster Creek Generating Station was operating at 100% reactor power, 661 Megawatts Electric (MWE). Oyster Creek had been online for 56 days following the 1F17 Forced Outage due to the M1A transformer failure on November 28, 2008.

At 2156 hours, Oyster Creek's main generator tripped due to the actuation of the 230kV bus section differential relay due to the failure of the MIA main power transformer. This caused a load reject SCRAM that automatically shut down the reactor. The transformer failure led to the declaration of an Unusual Event at 2211 hours, based on a fire lasting greater than 15 minutes affecting the M1A transformer. The fire was extinguished at 2227 hours and the Unusual Event was terminated at 2337 hours on February 1, 2009.

There were no nuclear safety consequences impacting plant or public safety as a result of this event.

This event is being reported pursuant to 10CFR50.73(a)(2)(iv)(A) due to the automatic reactor protection system actuation.

On August 16, 2008, at 23:57 PDT, with Unit 2 in Mode 1 (Power Operation) at approximately 100 percent power, a main generator Unit Trip signal initiated a Reactor Trip due to the failure of the main electrical transformer "C" phase. On August 17, 2008, at 00:12 PDT, plant operators declared an Unusual Event (UE) due to an observed fire. at the "C" phase transformer. Plant operators made an Emergency Event Notification (EN 44419) in accordance with 10 CFR 50.72(a)(1)(i) at 00:37 PDT. Plant operators stabilized Unit 2 in Mode 3 (Hot Standby) and updated the UE that the fire was out at 02:02 PDT. At 07:38 PDT, EN 44419 was updated to specify 10 CFR 50.72(b)(3)(iv)(A) and 10 CFR 50.72(b)(3)(iv)(B).

This event was due to a catastrophic failure of the main electrical transformer "C" phase high voltage bushing. The event investigation will continue, however, this event is considered a random component failure based upon onsite inspections and vendor reviews performed.

Corrective actions include the "C" phase transformer replacement, electrical tests of transformers and bushings, oil analysis of transformers and bushings, installation of a bushing monitoring system, evaluation and replacement of equipment damaged as a result of the electrical failure, and review of industry and station operating experience regarding main transformer issues.

On January 12, 2008, at 1626 hours a manual reactor scram was initiated from 99 percent power due to loss of cooling to the Main Transformers. After the scram reactor water level decreased to Level 2 (-41.6 inches) and Reactor Core Isolation Cooling initiated. There were no inoperable structures, systems, or components at the start of the event that contributed to the event. The normal heat sink (main condenser) remained available and no Main Steam Safety Relief Valves actuations occurred during the event. All control rods fully inserted and all safety systems functioned as designed and responded properly.

The cause of this event was the loss of cooling to the Main Transformers caused by loss of Auxiliary Power to the Main Transformer cooling system. Inspection of the complete circuit for Main Transformer Auxiliary Power showed that the "B" phase power cables were found to be burned in two at the transfer switch panel. The cause of the "B" phase power cable failure is attributed to failure of an electrical compression connection on a lug connection. This particular cable and connection has been inservice since plant start-up. Potential root causes were determined to be use of a compression connection for high current applications versus the preferred crimp type connection and an inadequate preventive maintenance strategy to provide early detection. Corrective actions included an inspection of the power panel and replacement of all damaged cabling.

At 1256 CDT on May 4, 2007, an unplanned manual reactor scram was initiated following the loss of cooling on the No. 2 main transformer. Reactor power at the time of the scram was approximately 67 percent. Following the scram, reactor water level briefly decreased below Level 3 as expected, resulting in the automatic closure of two containment isolation valves in the suppression pool cleanup system. This isolation was confirmed to have occurred as designed. Control of reactor pressure and water level was promptly established. No emergency coolant injection ,system actuation was required.

This event is being reported in accordance with 10CFR50.73(a)(2)(iv)(A) as a condition that resulted in the unplanned manual actuation of the reactor protection system. The loss of cooling to the transformer resulted from an electrical fault in the cooling system control cabinet caused by rainwater intrusion. The cabinet was repaired and sealed, and preventative maintenance procedures are to be enhanced to prevent recurrence. The plant responded to the manual scram as expected, thus this event was of minimal safety significance. .

NRC FORM 366 (6-2004) PRINTED ON RECYCLED PAPER

On June 15, 2006, at 1053 hours EDT, a reactor scram occurred from 100% power as a result of a main turbine / generator trip due to an internal fault on main unit transformer 2B. A reactor scram occurred as designed from the turbine control valve fast closure signal. The reactor protection system performed as expected, and all rods were fully inserted into the core. Reactor water level reached a low of approximately 134 inches above top of active fuel and recovered to normal automatically without operator intervention. Subsequent to the event, the main steam isolation valves remained open and reactor water level was maintained in the normal band of 173 to 214 inches. Reactor water was supplied by the condensate and reactor feedwater systems, and the resultant reactor steam was sent to the condenser via the main turbine bypass lines. Pressure control was maintained by the turbine bypass valves. Reactor dome pressure peaked at about 1077 psig, and none of the safety relief valves lifted.

Reactor water Level 3 isolations occurred as expected. An internal fault to ground of the Z-phase of the high voltage transformer winding caused the transformer failure. The most probable cause of the internal fault is that two adjacent transformer oil coolers were taken out of service together and washed with cold water which caused the internal fault. Transformer 2B was isolated from the generator and the electrical system, and the plant was restarted at reduced power on June 18, 2006. The plant was subsequently shut down on July 8, 2006 for replacement of failed main unit transformer 2B and returned to 100% power on July 22, 2006.

On July 13, 2005, at 0917 hours, Unit 1 received a Main Turbine trip followed by an automatic Reactor Protection System (RPS) actuation. The cause of the Main Turbine trip was the failure of the B phase of the Main Generator No Load Disconnect Switch (NLDS). Plant systems responded per design. All control rods fully inserted. An expected Reactor Pressure Vessel coolant level shrink resulted in the coolant level decreasing below the Reactor Vessel Water Level - Low Level 1 setpoint, which resulted in appropriate Primary Containment Isolation System (PCIS) isolations. Additionally, coolant level momentarily satisfied the Low Level 2 actuation logic requirements, at which point an additional PCIS isolation occurred and the High Pressure Coolant Injection (HPCI) system initiated but did not inject. Safety/Relief valves B, C, D, and E operated to control pressure. This condition is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) as an event that resulted in valid actuation of systems listed in 10 CFR 50.73(a)(2)(iv)(B).

The root cause of this event is inadequate design and testing of the NLDS by the vendor; resulting in the and Unit 2 which replaced the NLDSs with removable bus bars.