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On 10/09/17, during the bi-weekly Emergency Diesel Generator (EDG) #2 Load Test, a Generator Lockout signal (86G) was received which tripped the EDG output breaker. This failure resulted in EDG #2 being declared inoperable, and entry into an unplanned 7-day Limiting Condition for Operation (LCO) at 0312.

Troubleshooting identified a broken electrical ring lug connector on a current transformer that provides an input to the protective relay logic. The investigation determined the connector failure was due to fatigue cracking that was initiated by stresses caused by bending and twisting of the electrical lug beyond limits specified in industry guidelines. The ring lug was most likely distressed during initial installation in the 1990's. The condition that led to the EDG #2 trip existed for greater than the allowed outage time in the plant's Technical Specification (TS) and is reportable under 10 CFR 50.73(a)(2)(i)(B).

On July 3, 2017 at approximately 10:30 hours with the reactor subcritical after a manual scram, an automatic reactor scram occurred due to low Reactor Pressure Vessel (RPV) water level. Prior to this event, Main Control Room (MCR) Operators established reactor water letdown, reset the manual scram and were placing RPV water level control in automatic using a Low Flow Feedwater Regulator Valve (LFRV). Reactor pressure control was automatically being maintained with turbine bypass valves. A low reactor water level occurred when a bypass valve opened as expected to lower reactor pressure.

Operations personnel had reset the scram signal without fully evaluating other plant conditions. Upon resetting the scram with reactor water level not yet stabilized, an automatic scram was received on low reactor water level. The automatic scram initiation signal occurred with the plant in a shutdown mode.

On 11/20/2016 at approximately 0342 EST, an automatic reactor SCRAM occurred at 92% power due to Average Power Range Monitor (APRM) high flux. Oscillations of the turbine control valves and bypass valves were experienced during planned testing of the Turbine Master Trip Solenoid Valve at 95% power. Power was reduced from 95% to 92% by the Main Control Room Operators in an effort to stop the observed oscillations. The control valves did not respond properly during the power reduction, leading to an unexpected rise in reactor pressure and the subsequent scram on high flux.

There were no safety consequences impacting the plant or public safety as a result of this event. All control rods fully inserted and the plant response was as expected. This event is being reported pursuant to 10CFR50.73(a)(2)(iv)(A) due to an actuation of the Reactor Protection System (RPS).

Oyster Creek Nuclear Generating Station was in Cold Shutdown on 09/29/16 for Refueling Outage 1R26 when a condition was discovered during routine laboratory as-found testing that a Safety Valve (SV) (EIIC:RV) removed on 09/27/16 as part of refueling outage maintenance activities did not meet required setpoint tolerances. There were no structures, systems or components out of service that contributed to this event.

In accordance with American Society of Mechanical Engineers (ASME) Operation and Maintenance (O&M) Code requirements, two (2) of the nine (9) SVs installed in the plant were scheduled for removal during the refueling outage (1R26) and sent for as-found laboratory testing. Based on information received from the laboratory performing SV as-found testing, Site Engineering personnel determined that SV setpoint deficiencies existed with one (1) of the two (2) SVs removed and sent for testing. Per ASME O&M Code Mandatory Appendix I Section I- 1320, two additional SVs were removed from the plant and sent for as-found testing and both met the required setpoint acceptance criteria. One (1) of the four (4) SVs tested exceeded the setpoint tolerance of +/-3% (+1-36 psig) as specified in the Technical Specifications (TS), Paragraph 2.3.F. This resulted in a condition prohibited by TS and is considered reportable pursuant to 10 CFR 50.73(a)(2)(i)(B).

On 03/16/2016, it was identified that isolating or reducing cooling water to the Hydraulic Control Units (HCUs) for three control rods should have been considered a modification since it had the potential to impact the scram times of the control rods. Even though scram time penalties were applied for the three control rods where the cooling water flow was either isolated or reduced, failing to identify the isolation of cooling water to the control rods as a modification as described by the Technical Specifications resulted in the Plant not taking the action to scram time test the affected rods.

By not completing scram time testing for the control rods, whose cooling water was isolated or reduced, the station was in violation of the requirements of Technical Specifications Section 3.2, since the issue was not identified previously and the affected control rods were not declared inoperable and isolated.

• This event resulted in an Operation or Condition that was Prohibited by the Plant's Technical Specifications (TS) and is therefore being reported under 10CFR50.73(a)(2)(i)(B).

On November 9, 2015, while attempting to commence a #1 Emergency Diesel Generator (EDG) test procedure, the #1 EDG failed to start and the "EDG 1 Disabled' Alarm annunciated in the Main Control Room. Locally, the operator heard relays chattering on the generator end of Diesel Generator #1 and notified the control room that the SEQ alarm was illuminated. Subsequently, a fast start of the #1 Emergency Diesel Generator was attempted but was unsuccessful. The cause of the failure was determined to be a failed zero speed relay (ZSR). The ZSR failure was caused by an internal component fallure'associated with age degradation of the Time Delay Module of the relay assembly.

The identification of this failure resulted in EDG #1 being declared inoperable and entry into an unplanned 7-day LCO at 0348. The repairs concluded on November 10, 2015 at 0400-and the #1 EDG was declared operable at 0634.

This issue is reportable under 10 CFR 50.73(a)(2)(i)(B) as an Operation or Condition which was Prohibited by the plant's Technical Specifications since the likely time of failure would have been during the previous EDG#1 run which was conducted on October 26, 2015.

NRC FORM 388 (014014) ' NRC FORM 35$A U.S. NUCLEAR REGULATORY COM ION X01-2014) P Al; VE Y OM NO. 31 IRE 01/31/2011 Wasiinton, uu 20503. If a means used to impose an information does not dankly a care* valid OMB control minim, the NM may not conduct or sponsor, and a person's not Reportd itasons foamed are incorporated Into the 6c , process and fed back to industry.

Sand comments regard ng burden estimate to the FOfA, Rimy and Intonation Collections Branch (T.5 F53), U.S. Nuclear Riguitary Coovniston, Washington, DC 20655-0001, or. by Internet ameil to Iricceiscis.RoourcsOnrc.gov, and to the Deek Mot, Office of informadon and?Watt/ Mao, NE08-10202, (31500104), Olgen of =Pent end Budget required to respond to, the information collection.

2: DOCKET 05000219, $. LER NUMBER 3. PAGE OF 4 2014 - 003 - 01 '

Description of Event

On November 9, 2016 at 0348, when Operations attempted a normal start of the Emergency Diesel Generator

• #1 per th&riormal bkveekly.load test, procedure 636.4.003, the:#1EDGrfalled

• tostart During this attempt; the "Unit Starr fight illuminated; however, the Unit Idling light faited to illuminate, followed by thel.lEDG1 Disabled" ;Mann annunciation and theUnit Start Light for EDG #1 extinguishing.. Locally, the operators heard relays chattering in the generator compartment; however; no starter motor actuation occurred (failed start sequence).

The Operators then notified the Main Control Room that the SEQ alarm Was illuminated. Due to this condition, EDG #1 was declared inoperable and an unplanned risk change to yellow.occurred. Notifications were performed for the unplanned risk change and a prompt investigation was initiated. The station entered a 7-day shutdown Limiting Condition for Operation (LCO) per Technical Specifications 3.7.C.2. As part of this LCO, EDG # 2 operability was verified. EDG #1 was quarantined for troubleshooting.

Complex Troubleshooting identified that the Zero Speed Relay (ZSR) was not de-energized or dropped out as expected from the last EDG #1 load test on 10/26/2015. There is no alarm or panel indication for the failure.

The energized state of the relay would have precluded any start of EDG #1 since that test. The repairs concluded on November 10, 2016 at 0400 and the #1 EDG was declared operable at 0634.

Equipment Dericriptima The Emergency Diesel Generators are designed to start automatically and supply AC power to Class 1 E buses during degraded voltage or loss of voltage conditions on 1E, Loss of Offsite Power (LOOP), or a LOOP with a Loss of Coolant Accident (LOCA), for safe shutdown and coot down.

The ZSR is manufactured by Vapor Corporation under model number 39430622. The relay is mounted in .a control panel enclosure located in the. MG compartment. This location experiences mild temperatures during EDG operations and standby conditions. The most recent replacement of the ZSR relay for both EDG #1 and EDG #2 occurred in 1996. The ZSR is a normally de-energized, time delay relay with a fixed time delay of 2 seconds. Upon an EDG start signal, the relay is energized by ESSB (Engine Speed Sensing relay) when the engine speed increases to 40rpm. The MR prevents the starter motor engagement for next start attempt if the engine has not stopped. The relay contact returns to normal state after 2 seconds timeout following 0 rpm.

This interlock is not bypassed by a fast start signal.

Analysis cif Event The failed relay was sent to Exeton's PowerLabs for functional testing and analysis. PowerLabs' Failure Analysis report (OYS-25105) concluded that the ZSR's time delay unit failed to de-energize, which left voltage on the ZSR coil that was sufficient to prevent ZSR dropout. The cause of the excessive output voltage from the Time Delay Unit is likely attributed to degraded internal components. Attempts were made to identify the specific component(s) that was faulty within the Time Delay Unit. However, when the outer cover of the Time Delay Module was removed the Internal components were found to be encapsulated in a hardened potting compound that prohibited evaluating its components. The environment during the testing was approximately 71-73 degrees F. Powertabs' report indicated that the Time Delay Module would fail to de-energize the relay at ambient temperature.

NR - FO 34 (01.2014) In addition to the ZSR failure, potential leakage through surge suppressing rectifier CR-2A was considered.

This device was replaced with the ZSR replacement. The CR-2A rectifier was also sent to PowerLabs for testing. PowerLabs analysis concluded that the rectifier was free of any deficiencies and did not contribute to the failure mechanism.

Assessment of Safety Consequences

Two diesel generator units serve as the Standby Power Supply for the station by providing an emergency source of power to the 4.16 kV buses 1C and ID In the event of a loss of normal power. The diesel generator units are designed to start and load automatically, if required. Nonessential loads are automatically shed by undervoltage sensing devices on loss of offsite power to ensure that the units are not overloaded. The capacity of the units is sufficient to sequentially energize for starting all safety related pumps and auxiliaries required for a safe shutdown of the reactor in the event of a Design Basis Accident. The diesel generator units are independent of each other, with the exception of a common bulk fuel storage supply, and are provided with auxiliary systems to ensure reliable starting and continuous operation with no operator attention. Power to start the units is self-contained and is not dependent on the availability of any other source of normal plant power at the moment of initiation.

There are two types of automatic start signals to the diesel generator units. The first signal will cause the Units to start and idle. The second signal is called the Fast Start Signal. The Emergency Diesel Generator allowable time response to a Loss of Offsite Power (LOOP) event is 20 seconds as a basis for Core Spray System response to accident conditions. The time response period Includes UV sensor pickup time, emergency bus logic to isolate and actuate the Emergency Diesel Generators and the period to bring the Emergency Buses to normal voltage level.

The failure of the Zero Speed Relay would have precluded the #1 EDG from being able to start and load in the event of a degraded or toss of voltage condition. The #2 EDG would have continued to operate and would have supplied thelD 4160V bus as required to ensure power to the components required to achieve cold shutdown. The #2 EDG was evaluated to not be susceptible to a common cause failure and was maintained in an operable condition in accordance with station procedures.

Cause of Event

The ZSR failed to drop-out and remained energized from the last EDG #1 bi-weekly load test and prevented the fast start of EDG #1 during the current load testing. There Is no alarm or panel indication for a ZSR failure.

Complex troubleshooting identified the energized state of the ZSR; however, there were no visible degraded conditions kientified that would have caused the relay to remain energized. The relay was subsequently replaced and EDG # I was restored to an operable status.

The failed relay was sent to Exelon's Powertabs for functional testing and analysis. PowerLabs' Failure Analysis report (0VS-25105) concluded that the ZSR's time delay unit failed to de-energize, which left voltage on the ZSR coil that was sufficient to prevent ZSR dropout. The cause of the excessive output voltage from the Time Delay Unit is likely attributed to degraded internal components. Attempts were made to identify the specific component(s) that was faulty within the Time Delay Unit. However, when the outer cover of the Time Delay Module was removed the internal components were found to be encapsulated in a hardened potting compound that prohibited evaluating its components. The environment during the testing was approximately 71-73 degrees F. PowerLabs' report indicated that the Time Delay Module would fail to de-energize the relay at ambient temperature.

The apparent cause of the ZSR failure was determined to be en internal component failure associated with age degradation of the Time Delay Module of the relay assembly. Due to the internal components encapsulated in a dense potting material, it was not possible to determine what specific component of the Time Delay Module was failed.

The following immediate actions were taken:

• Complex Troubleshooting was commenced.

• The #2 Emergency Diesel Generator was placed in service to eliminate the potential for a common cause failure.

Corrective Actions

In order to address the Apparent Cause the following actions were (or are being) taken:

• Replaced the zero speed relay and the associated surge suppressor for the #1 EDO.

• Scheduled the replacement of the #2 EDG ZSR during the next maintenance outage

• Instituted a requirement to verify the state of the #2 EDG ZSR following each diesel run effective until the replacement of the ZSR is completed.

Previous Occurrences

There have been no previous events resulting from a failure of a normally de-energised Vapor Corporation relay.

Component Data Component IEEE 605 System ID IEEE 8034 Function Emergency Diesel Generator EK DO NRC FORM 2A (01-2014)

On.October 12, 2014, an automatic SCRAM occurred during the reactor startup evolution following the 1R25 refueling, outage. The SCRAM occurred when a station electrician, in conjunction with a General Electric technician and a site engineer; secured power to the, Main Generator Automatic Voltage. Regulator (AVR). controllers while the Main Turbine warming evolutionmas in progress. The individuals were not authorized to perform ihis action nor did they have procedUres in'the fieid- tO operate the equipment, Their actions resulted in an automatic. reactor SCRAM on law water ,.

level, . . . , ..

. ,.

ENS 50524 was submitted on October 12, 2014, and updated on October 17, 2014: This issue is reportable under 10 CFR 50.73(a)(2)(iv)(A), because it involved an event or condition that resulted in manual or automatic actuation of any - of the systems listed in paragraph.(a)(2)(iv)(13). .

. . ,.

The Root Cause Analysis was completed on January 30, 2015. The cause of this event was determined to be that Station Leadership has inconsistently reinforced Human Performance Error Reduction Tool Use and Procedure Use , and Adherence. This resulted in the breakdown of multiple fundamental practices and standards that led to the event.

..........

• ., NRC FORM 386 (01-2014) / NRC FORM 306A U.S. NUCLEAR REGULATORY COMMISSION'APAOYE6 EP10118 : NO. 385020104 EXPIRES: 01/31/2017

CONTINUATION SHEET

Estnated burden per response to comply WO) this mandatory collodion request 80 hours.

Reported lessons darned are incorporated into the licensing 'eosins and fad back to Industry.

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• 10202, (31640104), Office of aunt and Budget, Washington, DC 20600. It a means used to Impose an information oes not display a veld OW coital number, the WIC may not conduct or sponsor, end a person is not to respond to, the information collecton.

Description of Event

On October 12, 2014, during a planned reactor power ascension with reactor power at approximately 1% of rated thermal power, reactor water level began lowering. An automatic SCRAM occurred at 0251 EDT, moments before operators inserted a manual SCRAM in accordance with station procedures. The SCRAM occurred when an electrical technician reset all three Main Generator Automatic Voltage Regulator (AVR) controllers. This resulted in a Main Turbine trip while warming was in progress.

In this condition, the Turbine Bypass Valves (TBV) are held open by the Bypass Valve Opening Jack (BVOJ) with the internal bypass of the #2 TBV open, admitting steam to the Low Pressure (1.P) turbine. in this state, when the turbine is tripped, Turbine Emergency Trip Oil pressure is dumped, which closes the TSVs and Turbine Control Valves (TCVs). However, because the BVOJ was open, and the pressure wave caused by the TSV closure, the TBVs go to 90% open, which corresponds to a steam flow of approximately 35% Core Thermal Power. Reactor steam flow immediately increased and reactor pressure rapidly lowered. The initial reactor level swell reached 179" Top of Active Fuel (TAF) (Turbine Trip is 175" TAF as a reference) due to the voiding swell while reactor pressure decreases. The Balance of Plant (BOP) Reactor Operator (RO) commenced driving the BVOJ closed in accordance with station procedures in an attempt to reduce the rate of pressure reduction and maintain reactor inventory. This drives a reduction in voiding swell and a level decrease that is compounded by a significant inventory reduction due to the single element control on the 'A' Low Flow Feed Regulating Valve not being capable of providing adequate flow to compensate for this transient. As a result, indicated reactor level rapidly lowers, and the Unit RO performs the manual SCRAM actions in accordance with station procedures. However, the automatic SCRAM was processed moments before by the Reactor Protection System (RPS) reactor low-level signal. The Unit RO was less than one second behind the automatic SCRAM. The reactor water level reached a low point of approximately 107" TAF.

Following the reactor SCRAM, all systems operated as expected.

Analysis of the Event

• Following the actuation, all systems responded as expected; therefore, this event is of low safety significance.

Cause of Event

On October 12, 2014, an automatic SCRAM occurred during the reactor startup evolution following the 1R25 refueling outage. The SCRAM occurred when a station electrician secured power to the Main Generator AVR controllers while the Main Turbine warming evolution was in progress. The electrician, engineer, and technician were not authorized to perform this action nor did they have procedures in the field to operate the equipment.

Additional barriers had failed in the process sequence that could have prevented this event, including failure to follow the task management process and procedures, failure to conduct proper briefs in accordance with human performance procedures, and gaps in the planning process that resulted in an inadequate work package. These and other failed barriers in this sequence exhibited a commonality of a failure to comply with the applicable process and procedure.

he Root Cause of this event is that Station Leadership has inconsistently reinforced Human Performance Error Reduction Tool Use and Procedure Use and Adherence. A Contributing Cause is that individuals made decisions to deviate from processes, procedures, and human performance tool use because they incorrectly assumed there was no risk involved and they wanted to complete the assigned task to meet schedules.

Corrective Actions

To address the Root Cause, Exelon took (or will take) the following actions:

1. Senior Leadership Team will review at least once per week the station performance observations (i.e., Day in the Field, Daily Observation challenges, meeting observations, etc.) for strengths and gaps in human performance error reduction tool usage and procedure use and adherence to ensure supervision is critically observing performance. Trends and specific observations/direction will be communicated to First-Line Supervisors and above on a weekly basis.

2. Generate and communicate a human performance vision statement to the site.

3. Establish a daily, First-Line Supervisor time in the field expectation of at least two hours and daily observations focused on human performance tool use and procedure use and adherence.

4. Create a template and implement a process for the First-Line Supervisor/Manager Daily Observations and the Senior Leadership Team presentation and challenge. First-Line Supervisors or Managers will present their Daily Observation of human performance error reduction tool use and procedure use and adherence to multiple Senior Leadership Team members. The Senior Leadership Team members will engage the First-Line Supervisors and. Managers to ensure leadership team alignment and supervisor engagement in human performance and procedure use and adherence. The outcome of this interaction will be documented in a performance observation database for that First-Une Supervisor.

5. The Station Leadership Alignment Meeting and the Leader-to-Leader meeting will have agenda items specifically to address observed site behavior for human performance and procedure use and adherence to align on observations and actions.

To address the Contributing Cause, Exelon has taken (or will take) the following actions:

1. Create and implement a Behavior Based Performance Policy to ensure a clear and consistent management approach to procedure use and adherence issues.

2. Site management will discuss with their direct reporting personnel that the expectation is strict compliance with processes and procedures; each instance of non-compliance will be addressed consistently. These discussions are to be documented in the performance observation database or an affirmation letter.

Previous Occurrences

This was the first occurrence of the Automatic Voltage Regulator causing a Main Turbine trip, and the subsequent SCRAM at Oyster Creek. There arre historical Issue Reports (IRs) that documented deficiencies related to procedure use and adherence and the improper use of human performance tools.

On September 18, 2014, during refueling outage 01R25 with the unit in cold shutdown, plant personnel performed local leak rate testing (LLRT) of the Main Steam Isolation Valves (MSIVs). During the testing, it was identified that the "B" main steam line inboard isolation valve NSO3B (V-1-8) exceeded the leakage rate limits allowed by the plant's Technical Specifications.

The MSIV (V-1-8) that exhibited excessive leakage was repaired and the as-left leakage rate was verified to be within Technical Specifications leakage limits.

This issue is reportable under 10 CFR 50.73(a)(2)(i)(B) as a condition which was prohibited by the plant's Technical Specifications.

On December 17, 2013 at 1958 EST, while shut down, the plant experienced a reactor SCRAM when taking the Mode Switch from REFUEL to SHUTDOWN. The jumpers required to prevent a full SCRAM for this Mode Switch change were not installed as required by procedure. The actuation was a result of the reactor mode switch being placed from the refuel position to the shutdown position without the scram bypass jumpers installed.

The root cause determined that an unvalidated assumption by the supervisors resulted in a reactor scram while shut down.

Corrective actions include evaluation on requirements, through an Out-of-box Evaluation, to ensure operators understand and can demonstrate the proper use of the human performance fundamental tools that broke down in this instance. In addition, procedures will be enhanced to clarify verification requirements.

There were no safety consequences impacting the plant or public safety as a result of this event. The reactor was subcritical with all rods inserted at the time of the actuation. All systems functioned as designed. This event is being reported pursuant to 10CFR50.73(a)(2)(iv)(B) due to a valid actuation of the Reactor Protection System (RPS).

On 11/17/13 at 1725 EST station personnel simultaneously opened the inner and outer air lock doors from the Reactor Building to the reactor control enclosure (Reactor Building 23 foot elevation North West airlock). Reactor Building secondary containment integrity was momentarily declared inoperable per Technical Specification (TS) 3.5.B.2 due to both containment airlock doors being simultaneously open at the same time. Reactor Building D/P (differential pressure) remained less than negative 0.25 inches water column. The doors were immediately closed within 10 seconds and the Technical Specification condition was exited. The cause was a degraded airlock door interlock.

The secondary containment interlock doors were open for less than ten seconds. Based upon the short duration of the secondary containment doors being opened simultaneously, individuals present in the airlock to close the doors and that the Reactor Building D/P remained less than negative 0.25 inches water column during the course of this event, the safety function was met and this event is of low safety significance.

This event is being reported in accordance with 10 CFR 50.73(a)(2)(v)(C), any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to control the release of radioactive material.

On May 3, 2011, General Electric Hitachi (GEH) informed Oyster Creek Nuclear Generating Station (OCNGS) of a change in the calculation of Peak Cladding Temperature (PCT) and the Maximum Local Oxidation (MLO) that was based on corrections to errors in the previous calculation of record that were identified by the fuel vendor. On May 4, 2011, OCNGS determined that the multiple 10 CFR 50.46 Notifications resulted in a cumulative increase in analyzed PCT that exceeded the 10 CFR 50.46 PCT acceptance criterion of 2200°F. Also, the identified effect of the model change resulted in an increase in the calculated MLO above the 10 CFR 50.46 acceptance criteria. Further review of 10 CFR 50.46(a)(3)(ii) determined that an 8-hour notification report to the NRC was required under 10 CFR 50.72(b)(3)(ii)(B). The notification was completed as required.

The combined impact on PCT of the errors/changes described above is 115°F for the GE11 fuel and 145°F for the GNF2 fuel. These increases in PCT result in the licensing basis PCT exceeding the 10 CFR 50.46 acceptance criterion of 2200°F. Therefore, the PCT and MLO impact of these notifications has been offset by the calculation and implementation of revised Maximum Average Planar Linear Heat Generation Rate (MAPLHGR) values such that the maximum PCT and MLO values for both the GE11 and GNF2 fuel designs are returned to their original values of 2150°F and 16.5% respectively as documented in the vendor 10 CFR 50.46 notifications. Accordingly, this reanalysis meets the requirements of 10 CFR 50.46.

As a result of the MAPLHGR limit adjustment the current LOCA analysis of record remains applicable and therefore, the offsite dose is still bounded by our current safety analysis. Therefore this event is not significant with respect to the health and safety of the public.

On October 7, 2010, the No. 2 Emergency Diesel Generator (EDG) automatically started and loaded onto the 'D' 4160V Safety-Related Bus (`D' Bus) due to a valid undervoltage start signal resulting from deenergization of the 'D' Bus. The "D" Bus main breaker opened during test equipment installation while performing a grid undervoltage channel functional test.

The cause of the trip of the 'D' Bus main breaker was test equipment failure from chemical attack on the plastic test jacks.

Further investigation found that the timer connection jack showed signs of electrical pitting and arcing and was internally shorted to ground. After the test equipment was installed and prior to opening the test switch, the voltage on two of the undervoltage relays decreased below the set points for degraded voltage conditions, opening the normal feed breaker resulting in a valid undervoltage start signal for the No. 2 EDG.

Due to the event, the procedure for test equipment installation will be revised to include pre-use testing of the timer to ensure that the battery of the digital timer is acceptable for use and that the terminals are not shorted or grounded. Additionally, a placard will be installed on the timers stating, "Caution - Do not use cleaners or solvents to clean terminals on this unit.

Avoid contact with oil on terminals.

This event is being reported pursuant to 10CFR50.73(a)(2)(iv)(A) as an automatic ESF system actuation.

During the 1R22 Refueling Outage (Fall 2008), a Temporary Modification was made to the secondary containment so that the trunnion room door could be left open to support maintenance activities. The Temporary Modification moved the barrier for secondary containment from the outer walls and door of the trunnion room to the inner walls, ceiling, floor, and associated penetrations in the trunnion room. A 10 CFR 50.59 Evaluation supported the Temporary Modification based on the determination that secondary containment integrity could be maintained separate from the trunnion room door and concluded that a Technical Specification change was not needed.

During the NRC Plant:Modification Inspection (May 4 through 15, 2009), the determination was made that the Temporary Modification. to open the trunnion room door for extended periods of time during 1 R22 was in noncompliance with Oyster Creek's Technical Specifications. The supporting 10 CFR 50.59 Evaluation inappropriately determined that prior approval from the NRC was not needed in that the secondary containment integrity required by Technical Specification Limiting Condition of Operation (TS LCO) 3.5.B was maintained.

On July 17, 2007 at 05:21 while operating at 100% power, an automatic reactor scram occurred due to low reactor water level following a trip of the "C" Reactor Feed Pump (RFP). The cause of the "C" RFP trip is attributed to an electrical fault internal to the motor. This transient led to an automatic scram on

• low reactor water level and subsequent reactor isolation on a low-low reactor level.

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

This event is being reported pursuant to 10 CFR 50.73(a)(2)(iv)(A) due to the automatic reactor protection system and subsequent ECCS actuations.