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On September 17, 2017, at 0938 Eastern Daylight Time (EDT), a momentary power interruption to Emergency Bus E4 occurred during planned surveillance activities involving Emergency Diesel Generator (EDG) 4. This occurred when EDG 4 was disconnected from Emergency Bus E4 and offsite power was not supplying the bus. EDG 4 automatically transferred from manual mode to automatic control and reconnected to Emergency Bus E4. Normal frequency and voltage were restored with EDG 4 in automatic control. The momentary power interruption to Emergency Bus E4 resulted in various Unit 2 Primary Containment Isolation System (PCIS) actuations. The affected equipment responded as designed.

The direct cause of this event was that Operators were not aware that, at the time of the event, Emergency Bus E4 was being supplied solely by EDG 4. As a result of a failed under-frequency relay, the incoming line and feeder breakers from Balance of Plant (BOP) Bus 2C to Emergency Bus E4 had opened during the performance of the EDG 4 surveillance, leaving only EDG 4 to power Emergency Bus E4 in the manual mode of operation.

On May 17, 2017, during Refueling Outage (RFO)-21 while performing an extent of condition review it was discovered that the contact indicating tabs of relays 16A-K30 and 16A-K54 of the Pilgrim Nuclear Power Station (PNPS) Primary Containment System, were visually hanging in the mid-position (partial travel).

The relays were replaced during RFO-21 along with 16A-K29 and 16A-K53, and all four relays were sent to an offsite vendor for further testing and analysis. Other relays were reviewed but were determined to be outside the scope of this extent of condition review.

PNPS stated at the time that this event was reportable under 10 CFR 50.73(a)(2)(i)(B) - Operation or condition prohibited by Technical Specifications; and potentially reportable in accordance with 10 CFR 50.73(a)(2)(v)(B), (C) and (D) - Any condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to remove residual heat, control the release of radioactive material and mitigate the consequences of an accident. However, additional information provided by our offsite vendor and an engineering evaluation, support the conclusion that there was never a loss of safety function regarding any of the four relays (16A-K29, 16A- K30, 16A-K53 and 16A-K54). Therefore, this event was not reportable under 10 CFR 50.73(a)(2)(i)(B) nor under 10 CFR 50.73(a)(2)(v)(B), (C) or (D).

This event posed no threat to public health and safety.

On November 9, 2016, at 0420 with the Hope Creek reactor in Operational. Condition 2, Startup, the B channel reactor level instrumentation was found to be inoperable. The inoperable Instrumentation was discovered as reactor level was being lowered into the normal band in preparation for plant startup. Hope Creek had made a mode change from Operational Condition 4, Cold Shutdown, to Operation Condition 2, Startup, on November 9, 2016, at 0317, approximately 1 hour prior to discovering the inoperable instrumentation.

The B Channel reactor level instrumentation is required to be operable in order to enter Operational Condition 2 to support the B division of the Reactor Protection System (RPS), the Emergency Core Cooling Systems (ECCS), and the Primary Containment Isolation System (PCIS). The cause was determined to be an improperly filled reference leg for the B channel reactor level instrumentation. This report Is being made under 10 CFR 50.73(a)(2Xi)(B), as a condition which was prohibited by the plant's Technical Specifications.

On April 22, 2016, at 1358 Central Daylight Time (CDT), during transfer of the 4160 V (4kV) Shutdown Bus from Alternate to Normal, the Normal Feeder Breaker (BKR 1722) failed to close when the Alternate Feeder Breaker was manually tripped. 4kV SD Bus 2 de-energized, resulting in the loss of 1B and 2B Reactor Protection System (RPS) as well as Steam Jet Air Ejector 1B. Emergency Diesel Generators (EDG) C and D started, but did not tie to the 4kV Shutdown Boards due to Operations personnel immediately re-closing the Alternate breaker and re-energizing 4kV Shutdown Bus 2. Invalid actuations of several Containment Isolation Valves also occurred during this event due to the loss of RPS. At 1530 CDT, EDG C and D were shut down. BFN, Unit 1, was returned to normal operating conditions.

The cause of this event was loose wires in the closing control circuit for BKR 1722 due to work in the vicinity of the control circuit termination points. Corrective actions were to terminate loose wires, using a ring type lug instead of a forked spade type lug, in the closing control circuit for BKR 1722; and to verify Shutdown Bus 2 transferred successfully to BKR 1722. A briefing was provided to Electrical personnel who perform modifications to discuss the potential consequences of installing tie wraps and performing other activities that could adversely affect existing wiring.

On September 29, 2015, at 0900 hours, the 'B' train of the Standby Gas Treatment System (SGTS) was declared inoperable as part of surveillance test SE-030-002B (24-Month Control Structure Ventilation System Operability Test Div II 'B' SGTS).

During the test, personnel also commenced testing of the Unit 1 Reactor Pressure Vessel water level instrumentation per SI- 180-306 (24-Month Calibration of RWCU PCIS Secondary Containment Isolation and CREOASS Initiation of Reactor Vessel Water Level 2 and MSIV Isolation on Reactor Vessel Water Level 1 for channels LITS-B21-1N026A and B21-1N026C). At 1030 hours, level instrument LITS-B21-1N026A failed its test acceptance criteria, resulting in entry into the Action Statement for TS 3.3.6.2, Condition A. This failed instrument channel is part of the initiation logic for the 'A' train of SGTS. In accordance with TS 3.0.6, since the SGTS is a support system, a loss of safety function determination was performed and concluded the 'A' train of SGTS was inoperable. With both the 'A' and 'B' trains of SGTS inoperable, the Action Statement for TS 3.6.4.3, Condition D, was entered at 1050 hours. At 1456 hours on September 29, 2015, an 8-hour Event Notification (#51432) was made to the NRC per 10 CFR 50.72(b)(3)(v)(c) for a condition that could have prevented the fullfilment of the safety function of the SGTS. On September 30, 2015, during panel walkdowns, it was identified that the 'B' CREOAS system flow controller was still in manual and had not been restored to auto after completion of SE-030-002B on September 29, 2015. As a result, the TS 3.7.3 Action Statement for CREOAS system was entered for the 'B' train being inoperable. In accordance with 10 CFR 50.73(a)(2)(v)(C),this LER is being submitted for any event or condition that at the time of discovery, could have prevented the fulfillment of the safety function of SGTS and the CREOAS system.

Apparent cause: Loss of safety function was not recognized and mitigated when scheduling a surveillance test concurrent with the planned inoperability of the opposite division. Key corrective action: Revise surveillance procedures for instrumentation involving RPS, ECCS initiation, Primary Containment Isolation System (PCIS) and the Secondary Containment Isolation System, to include information on equipment impacts for instruments removed from service, and that redundant equipment is to be operable. There were no actual consequences to the health and safety of the public.

On 11/12/2015 at 1132 hours, the Unit 1 'B' Inboard Main Steam Isolation Valve, HV141F022B, closed during the performance of SI-183-207, Quarterly Functional Test of Main Steam Line 'C' Flow Channels FIS-B21-1 N008A&B and Main Steam Line 'D' Flow Channels FIS-B21-1N009A&B. This resulted in an automatic SCRAM of Unit 1 on high reactor pressure.

This event was reported under 10 CFR 50.72(b)(2)(iv)(B) and 10CFR 50.72(b)(3)(iv)(A) per the guidance of NUREG 1022, Revision 3, Section 3.2.6. This event is also being reported as a Licensee Event Report (LER) in accordance with 10 CFR 50.73(a)(2)(iv)(A).

The root cause is that the station did not evaluate recommendations made in 2011 by the Boiling Water Reactor Owners Group Instrument and Controls (BWROG l&C) Maintenance Committee to mitigate Primary Containment Isolation System (PCIS) Group 1 Surveillance Testing Risk. It was also determined as a causal factor that there was not specific guidance contained in SI-183-306 (24 Month Calibration Main Steam C/D) which led to an inaccurate field decision when determining the cause of the extinguished light.

Planned corrective actions include evaluating the BWROG l&C Maintenance Committee Recommendation to mitigate PCIS Group 1 Surveillance Testing Risk and then design and implement the proposed modification. Additionally, l&C personnel will perform a review of the population of BWROG recommendations that were issued between January 2011 and December 2013 to ensure they were evaluated.

There were no actual consequences to the health and safety of the public as a result of this event.

APPROVED BY OMB: NO. 3150-0104 EXPIRES: 01/31/2017 hours. Reported lessons learned are incorporated into the licensing process and fed back tc 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 not conduct or sponsor, and a person is not required to respond to, the information collection.

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 June 2, 2014, during performance of the Reactor High Pressure Calibration surveillance, the Residual Heat Removal (RHR) Shutdown Cooling (SDC) Inboard Suction Valve Isolation relay failed to energize preventing automatic closure of the RHR SDC Inboard Suction Valve. On three occasions, the inability of this valve to close automatically upon receipt of the Primary Containment Isolation System signal resulted in a violation of the Browns Ferry Nuclear Plant, Unit 3, Technical Specifications. The Shutdown Cooling Mode of the Residual Heat Removal System was unaffected by this condition.

The cause of the event was relay wires had been lifted and incorrectly landed due to a human performance error at an indeterminate time between a successful post maintenance test (PMT) on March 07, 2014, and the time the condition was corrected by re-landing the wires according to plant drawings on June 6, 2014.

The corrective action to reduce likelihood of recurrence is to develop and deliver a case study to the Maintenance, Modifications, and Operations departments based on the details of this event.

On March 18, 2014, the Browns Ferry Nuclear Plant (BFN) Unit 3 reactor automatically scrammed due to a turbine trip from a high main turbine moisture separator level. Initial indications show the level controller for 3B2 Moisture Separator failed to maintain level in automatic. Additionally, local manual control attempts failed to restore moisture separator level. Following the turbine trip Main Steam Isolation Valves remained open with main turbine bypass valves controlling reactor pressure.

At approximately 2232, Central Daylight Time (CDT) the 3B2 Moisture Separator Level High Alarm was received and an operator was dispatched to investigate. In accordance with the alarm response procedure the 3B2 Moisture Separator Water Level Controller was placed in manual. Attempts to control the Moisture Separator Reservoir 3B2 High Level Dump Valve manually were ineffective. At approximately 2252 CDT, the Unit 3 reactor automatically scrammed due to a turbine trip from a high moisture separator level.

The root cause was a failure to prevent the introduction of foreign material during the manufacturing process of the Moisture Separator Level Controller. The manufacturing defect was a legacy issue dating back to 1971 when the controller body was originally machined. The corrective actions to prevent recurrence requires the removal, cleaning of air passages, replacement of control relays, for similar controllers and upgrading the calibration procedure to include cleaning guidance.

On April 17, 2013, LaSalle Units 1 and 2 were operating in Mode 1 at 100% power, with a severe thunderstorm in progress. At 1457 hours CDT, lightning struck 138KV Line 0112, resulting in a phase-to-ground fault which subsequently cleared. At 1459 hours, a second phase-to-ground fault on Line 0112 occurred and all 345 KV oil circuit breakers (OCBs) in the main switchyard opened, resulting in a loss of offsite power and reactor scrams on both Units. All emergency diesel generators automatically started and loaded onto their respective busses. All control rods fully inserted, and all systems responded as expected.

An Unusual Event was declared due to a loss of offsite power for greater than 15 minutes. Offsite power was restored to all ESF busses by 2301 hours on April 17, 2013, and the Unusual Event was terminated at 0814 hours on April 18, 2013.

The root cause of the event was determined to be degradation of the 138kV switchyard grounding system that allowed a lightning induced fault to flash over onto the DC protective system. The ground system in the 138kV switchyard was repaired, and corrective actions include improving lightning shielding in the 138kV switchyard.

On February 25, 2013, at approximately 1313 hours Central Standard Time, the Browns Ferry Nuclear Plant (BFN), Unit 3, reactor automatically scrammed due to an actuation of the Reactor Protection System from a turbine trip. The turbine tripped on low condenser vacuum due to a reactor feedwater piping separation. The Main Steam Isolation Valves were manually closed. There was one Safety Relief Valve that was manually operated to maintain reactor pressure due to the unavailability of the Main Turbine Bypass Valves upon loss of condenser vacuum. All systems responded as expected to the turbine trip. No Emergency Core Cooling System or Reactor Core Isolation Cooling (RCIC) system reactor water level initiation set points were reached. Reactor water level was controlled with the RCIC system and reactor pressure was controlled with the High Pressure Coolant Injection system.

The root cause for this event is that the system design for BFN, Unit 3, Feedwater Long Cycle line does not account for flashing of water to steam due to isolation valve leakage.

The corrective action to prevent recurrence is to redesign Feed Water Long Cycle lines downstream of each Feed Water Long Cycle isolation valve and upstream of the Miscellaneous Drain Header with a valve and piping configuration appropriately designed for the specified application.

On March 19, 2013, at approximately 0402 hours Central Daylight Time, the Browns Ferry Nuclear Plant (BFN), Unit 1, reactor was manually scrammed due to decreasing condenser vacuum caused by a significant leak from the 1C feedwater heater level control line. Condenser vacuum was deteriorating and was approaching the turbine trip setpoint, at which time the reactor was manually scrammed. The main steam isolation valves remained open, reactor pressure was controlled with the main turbine bypass valves, and the reactor feedwater pumps were used to control reactor water level. All systems responded as expected to the scram. All control rods inserted into the core during the scram.

The root causes for this event were a combination of vibration from the dump valve opening with the vibration in the 4 inch drain line from leaking drain valves, and station personnel did not consistently consider risk when making decisions to replace the BFN, Unit 1, feedwater heater vent and drain valves.

The corrective actions to prevent recurrence are to design and implement a design change for the feedwater heater vent and drain header piping to provide increased support, and establish initial and continuing training requirements for leaders and craft that support their roles and responsibilities.

Also, BFN has implemented a Strategic Performance Management process to reinforce and institutionalize conservative decision making principles.

NRC FORM 388 (10-2010) FACILITY NAME (1) PAGE (3) DOCKET (2) LER NUMBER (6)

During planned surveillance testing three of four isolation instrumentation channel response times exceeded the Technical Specification T (TS) maximum limit of less than or equal to 0.5 seconds for main steam line T (MSL) T high flow.

T The response time test failures were caused by a failure to proceduralize the method of replacement relay selection to ensure the fastest contact release times. T This caused the overall as-left logic response time to lose margin to the TS limit. T The affected relays in the 1A, T 10 and 1D MSL flow channels were replaced. T The relay testing and/or replacement procedure will be revised to include a step-by-step method of selecting relays with the shortest contact release times upon de-energization of the relay.

A new stock code will be created for new relays that have been response time tested and found to be acceptable for this application.

On May 24, 2012, at approximately 0638 Central Daylight Time, Operations personnel inadvertently ranged 3H intermediate range monitor (IRM) down instead of up resulting in a half scram from the 3B reactor protection system (RPS) trip channel. Subsequently, the IRM was properly ranged and Operations personnel responded in accordance with procedures to reset the half scram. Coincident with Operations personnel placing the scram reset switch in the Group 2/3 position, an electrical spike was received on 3A IRM of the 3A RPS trip channel resulting in control rod insertion for the Groups 1 and 4 control rods. Operations personnel identified the unexpected control rod motion and initiated a manual reactor scram in accordance with Browns Ferry Nuclear Plant (BFN) Abnormal Operating Instructions.

The root cause was determined to be high impedance of the BFN, Unit 3, Main Control Room (MCR) common ground to station ground that exposed the 3A IRM to noise feedback.

The corrective action to prevent recurrence is to verify that BFN, Unit 3, MCR common ground connections to station ground are as shown in the applicable system drawings. If any ground connections are identified that require repair, work orders will be initiated and repairs performed.

Following repairs, the high impedance connection of BFN, Unit 3, MCR common ground to station ground will be confirmed to have been resolved by documenting the results of validation testing.

On April 28, 2011, at 2338 hours Central Daylight Time, with all three units in cold shutdown and power supplied to the 4-kV shutdown buses by onsite emergency diesel generators (EDGs), Browns Ferry Nuclear Plant personnel performed a shutdown of the Unit 1/2 C EDG. The Unit 1/2 C EDG was shutdown due to a hydraulic oil leak in piping for the EDG governor that was causing voltage and frequency fluctuations. Following shutdown of the Unit 1/2 C EDG, the 4-kV shutdown board C, which was being powered by the Unit 1/2 C EDG, de-energized. This resulted in a loss of power to the 1B Reactor Protection System causing a Primary Containment Isolation System (PCIS) actuation. The PCIS isolation (Group 2) caused the loss of Shutdown Cooling on Unit 1 for 47 minutes. In addition, the loss of power to the 4-kV shutdown board C also caused the loss of the 2B Residual Heat Removal (RHR) pump leading to a momentary suspension of Shutdown Cooling for Unit 2. Shutdown Cooling for Unit 2 was immediately restored using the 2D RHR pump. The root cause of the oil leak was determined to be a less than adequate design of the Unit 1/2 C EDG governor oil piping to compensate for vibration I loading.

This report also constitutes a 10 CFR 21 notification.

On Sunday, February 20, 2011 at 1034 EST, with the reactor shutdown and all control rods fully inserted a valid Reactor Protection System (RPS) low reactor water level initiation signal (+12 inches) was received. The RPS actuation signal resulted in a reactor scram and actuation of Primary Containment Isolation System (PCIS) Group II (Drywell) isolation, Group VI (RWCU) isolation and a Reactor Building Isolation System (RBIS) actuation. At the time of the event, a controlled reactor shutdown and cooldown was in progress. The Reactor Mode Selector Switch was in "Startup" and the low reactor water level actuation signal was the result of reactor water level control difficulties during the cool-down using the Mechanical Pressure Regulator (MPR). Reactor water level was immediately restored, the isolations (Group II and VI) were reset; and the RPS signal was reset at 1135 EST. All systems operated as expected, in accordance with design.

Corrective actions taken included the revision of the reactor heat-up / cool-down procedure to incorporate lessons learned and to identify the Bypass Valve Opening Jack (BVOJ) as the preferred method for executing a reactor pressure vessel cool-down. Corrective actions planned include the performing of an analysis of MPR/RPV and level response during plant cool-down at the plant simulator and evaluate results for disposition. This event had no impact on the health and/ or safety of the public.

On May 5, 2010, at approximately 11:44 hours Eastern Daylight Time (EDT), an automatic reactor scram occurred on Unit 1 following a trip of the 1B Reactor Feed Pump (RFP). The Reactor Recirculation pumps did not run back as expected following the 1B RFP trip. The resulting water level shrink caused level in the Reactor Pressure Vessel (RPV) to drop to Low Level 1, causing the activation of the Reactor Protection System (RPS) and the Primary Containment Isolation System (PCIS). All control rods properly inserted.

PCIS Group 2, Group 6, and Group 8 isolation signals were received on Low Level 1. Actuations of the Primary Containment Isolation Valves (PCIVs) were completed and the affected equipment responded as designed. Water level in the RPV momentarily reached Low Level 2, which initiated the High Pressure Coolant Injection (HPCI) System, the Reactor Core Isolation Cooling (RCIC) System, and a partial Group 3 (i.e., Reactor Water Cleanup (RWCU)) PCIS isolation. The HPCI and RCIC systems did not inject to the RPV. The RWCU inboard isolation valve isolated and, in accordance with plant design, 1-G31-F004 (i.e., RWCU outboard isolation) did not automatically isolate. Unit 2 was not affected by this event.

The safety consequences of this event were minimal. All Emergency Core Cooling Systems (ECCS) were -Operable and-available-to provide- adequatecore cooling if needed. The investigation concluded that the --adverse-coridition--was,a historical problem_ and_no.root.catiSe- Could reasonably. be. determined._ _ .

On July 8, 2009, at 1013 hours Eastern Daylight Time (EDT), during planned preventive maintenance activities, electrical power was lost to the 4160V emergency bus E2. Emergency Diesel Generator 2 automatically started and re-energized the E2 bus. The loss of power to E2 resulted in Unit 1 Primary Containment Isolation System Groups 2, 3, 6, and 10 isolations. Per design, no Unit 2 safety system group isolations or actuations occurred. Other Unit 1 actuations included the Reactor Building Ventilation System isolation (i.e., Secondary Containment isolation), automatic start of both trains of the Standby Gas Treatment System and automatic start of both trains of the Control Room Emergency Ventilation System. The affected equipment responded as designed.

This event occurred during activities associated with instrument calibration of an emergency bus E2 voltage transducer. Technicians performing the activity opened the wrong test switch. As a result, arcing occurred when test equipment was connected to an energized circuit. This caused the blown fuse in the C phase of emergency bus E2, which in turn caused a loss of power to the emergency bus and the E2 master/slave breaker to trip. The root cause of this event is inadequacies associated with procedure OPIC-CNV023 and the associated work order used to perform the preventive maintenance task. Corrective actions to prevent recurrence will correct identified problems with these documents.

February 18, 2009, at 0351 hours Central Standard Time (CST), following a scheduled preventative maintenance activity, Unit 1 reactor automatically scrammed from a turbine trip due to a power load unbalance signal on the main generator. Specifically, at 0349 hours CST, Operations swapped the Unit 1 Main Generator Isophase Bus Duct System cooling fan from the running to the alternate fan. When the alternate fan started, water entrapped in the fan housing was expelled into the bus provided a path to ground inside the bus duct.

This resulted in actuation of the generator protective relays and a turbine trip and automatic reactor scram, which resulted in the automatic actuation of the reactor protection system. Water that had settled in the idle bus duct cooling fan housing was expelled into the main generator isophase bus duct upon fan startup providing a conductive path to ground. The root cause of this event was less than adequate design process guidance for consideration of seasonal variations in the operating conditions for heating ventilation and air conditioning (HVAC) system design. The design process does not consider full range of operation of HVAC systems using raw cooling water as a cooling medium during the winter months. BFN inspected the Unit 1 isophase bus for damage. No damage was identified. BFN installed a drain with a site glass on each Unit 1 bus duct cooling fan housing. General Operating Instruction, Operations Round Logs, was revised requiring verification that there is no water in the idle fan and to drain any water that may have accumulated prior to placing it into service. BFN will modify the design change technical considerations checklist to provide design process guidance for consideration of seasonal variations in operating conditions for HVAC design.

On November 9, 2008, at 1108 hours Eastern Standard Time (EST), Safety Relief Valve (SRV) 2-B21-F013H (i.e., SRV H) spuriously opened with no Operator action or testing in progress. The SRV's control switch was cycled as required by Abnormal Operating Procedure with no success. At 1113 hours, the fuses were pulled for SRV H in an attempt to close the valve. At 1117 hours, a manual reactor scram was inserted based on the Suppression Pool temperature reaching 109.8 degrees Fahrenheit (F). Technical Specifications requires a manual reactor scram to be inserted when Suppression Pool average temperature exceeds 110 degrees F. All control rods fully inserted from the manual reactor scram signal. Reactor water level lowered to Low Level 2 resulting in Primary Containment Isolation System (PCIS) isolations of Groups 2, 3, 6, and 8. In addition, the Reactor Core Isolation Cooling (RCIC) system actuated and injected into the reactor. The High Pressure Coolant Injection (HPCI) system actuated but did not inject since reactor water level had recovered. An Alternate Rod Insertion signal was received, the Standby Gas Treatment (SBGT) system initiated, and the Reactor Recirculation pumps tripped as designed. All systems responded as designed.

The root cause of this event was the failure to verify proper seating of the set pressure spring in the upper spring follower plate. The corrective action to prevent recurrence is to revise the corrective maintenance procedure to perform Verification of proper set pressure spring seating prior to the reassembly of the pilot valve.

On August 30, 2008, at 1503 hours Eastern Daylight Time (EDT), a Power/Load Unbalance (PLU) actuation caused the Turbine Control Valves (TCVs) and the Main Turbine Bypass Valves (BPVs) to cycle. The initial cycle resulted in BPV No. 1 partially opening while a second cycle resulted in four BPVs going full open. At that time, the order was given to insert a manual scram. An automatic scram signal occurred just as the operator was beginning to insert the manual scram. Reactor water level momentarily dropped below Low Level 1 (LL1) during the response, resulting in Primary Containment Isolation System (PCIS) Group 2 and Group 6 isolations. LL1 actuations occurred as designed. All control rods fully inserted and all systems responded as designed.

This event is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A), as an event or condition that resulted in manual or automatic actuation of any of the systems listed in 10 CFR 50.73(a)(2)(iv)(B).

The select cause of this event was the lack of adequate work controls for transmission maintenance activities due to an inaccurate perception of risk. The corrective actions to prevent recurrence include the revision of site procedures to provide additional work controls and improve risk assessment.

On March 5, 2008,.at 2:43 p.m. CST, an automatic reactor scram occurred while the plant was operating at 60 percent power. The scram signal was initiated by high steam pressure in the reactor, and all control rods inserted as designed. The initial pressure transient caused the automatic actuation of nine main steam safety-relief valves. Reactor water level momentarily decreased to Level 3 immediately following the scram, resulting in the automatic closure of the containment isolation valves in the suppression pool cleanup system. Reactor pressure and water level were promptly stabilized following the initial transient. A malfunction in the main turbine control system resulting from a loose, oil-contaminated electrical connector apparently produced an errant turbine speed error signal. This signal caused a closure of the turbine control valves, resulting in high reactor steam pressure. The connector was cleaned and reassembled. -A preventative maintenance task will be developed to inspect this and similar connectors periodically. This event is being reported in accordance with 10CFR50.73(a)(2)(iv)(A) as an unplanned actuation of the reactor protection system and the primary containment isolation system.

- -) NRC FORM 366 (9-2007) PRINTED ON RECYCLED PAPER