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 Report dateSiteEvent description
05000316/LER-2017-00119 May 2017Cook

On March 23, 2017, at 0941, Eastern Daylight Time (EDT), with Unit 2 in Mode 1 at 100% power, the Unit 2 Containment CEQ Fan #1 Backdraft Damper opening force exceeded the Technical Specification (TS) Surveillance Requirement (SR) limit.

Maintenance was performed on the damper and operability of the Unit 2 CEQ Fan #1 was restored at 1724 EDT. A past operability evaluation was performed and determined that the condition likely existed since maintenance was performed to lubricate the damper on February 24, 2017. As a result, the Unit 2 CEQ Fan #1 was inoperable longer than allowed by TS. During this time, the Unit 2 CEQ Fan #2 was declared inoperable to perform surveillance testing on March 2, 2017, from 0938 Eastern Standard Time (EST) until 1326 EST. This resulted in both trains being inoperable simultaneously for a short period of time.

The cause of the elevated force required to open the Unit 2 CEQ Fan #1 Backdraft Damper was determined to be that the lubrication Preventive Maintenance (PM) work order instructions were not adequate and did not provide adequate Post-Maintenance Testing (PMT) instruction. Corrective action is to revise model work order tasks to provide additional details and appropriate PMT. The risk significance of this condition has been determined to not constitute a significant increase in risk.

This event is reportable in accordance with 10 CFR 50.73(a)(2)(i)(B) and 10 CFR 50.73(a)(2)(v)(D).

05000316/LER-2016-0029 February 2017Cook

On December 13, 2016, the Unit 1 AB Emergency Diesel Generator (EDG) developed a fuel oil leak from a fuel injector pump Delivery Valve Holder (DVH) during a maintenance run of the diesel. On December 21, 2016, with Unit 1 in Mode 1 at 100 percent power and Unit 2 in Mode 4 during a refueling outage, it was determined that the failed DVH on the Unit 1 AB EDG was due to a design and manufacturing issue. Subsequently the Unit 1 CD EDG, Unit 2 AB EDG, and Unit 2 CD EDG were conservatively declared inoperable due to multiple affected diesel fuel pump DVHs being installed on each EDG.

The Root Cause was determined to be due to insufficient Corrective Action Program oversight by Engineering to ensure product quality and issue resolution in relation to a previous EDG DVH failure in 2013. Testing is being conducted to determine the resulting impact to associated EDGs. The affected DVHs have been replaced.

A Loss of Safety Function was reported via Event Notification 52456 for Unit 2 in accordance with 10 CFR 50.72(b)(3)(v)(D). The Loss of Safety Function is required to be reported in a Licensee Event Report in accordance with "50.73(a)(2)(v)(D) Event or Condition that Could Have Prevented Fulfillment of a Safety Function.

05000316/LER-2016-0014 October 2016Cook

On July 6, 2016, with the Donald C. Cook Nuclear Plant Unit 2 Reactor operating in Mode 1 at 100 percent power, the control room received a report of a steam leak on the Unit 2 B Right Moisture Separator Reheater (MSR)

  • crossover piping and damage to the turbine building structure. This information resulted in a decision by the crew to manually trip the Unit 2 Reactor at 0038. The cause of the steam leak was the sudden failure of the balance bellows on the Unit 2 B Right MSR crossover expansion joint, which also resulted in damage to the west wall of the turbine building.

The Root Cause was determined to be an organizational failure to recognize the risk significance of, and to adequately correct or mitigate, previously identified vibration issues with the Unit 2 B Right MSR crossover expansion joint tie rod and bellows in a timely fashion.

This event is being reported in accordance with 10CFR 50.73(a)(2)(iv)(A) as a manual actuation of the Reactor Protection System and an automatic actuation of the Auxiliary Feedwater system.

05000315/LER-2015-00231 March 2016Cook

On June 14, 2015, Donald C. Cook Nuclear Plant operations personnel identified an oil leak from the Unit 1 East Residual Heat Removal (RHR) pump (Train A) lower motor bearing oil reservoir. An engineering evaluation concluded that the leak rate would preclude the pump from meeting its 30-day mission time during accident conditions, thus rendering the Unit 1 East RHR pump inoperable. Review of oil addition logs concluded that this condition has existed, but was not recognized as such, since March 9, 2015. This exceeds the 72 hours allowed by Technical Specification (TS) Limiting Condition for Operation (LCO) 3.5.2, Condition A and is reportable in accordance with 10 CFR 50.73(a)(2)(i)(B).

Concurrent with the Unit 1 East RHR pump (train A) inoperability while in Mode 1, the Unit 1 AB Emergency Diesel Generator (EDG) (Train B) was inoperable for a scheduled maintenance window commencing May 18, 2015, and ending with a TS required shutdown due to EDG failure. The inoperable AB EDG required the Unit 1 West RHR pump to be declared inoperable in accordance with LCO 3.8.1, Condition B.3 - "Declare required feature(s) supported by the inoperable DG inoperable when its required redundant feature(s) is The Unit 1 West RHR Pump was not declared inoperable within four hours as required by TS LCO 3.8.1, Condition B.3. The Unit 1 West RHR pump should have been declared inoperable in accordance with TS LCO 3.8.1 Condition B.3 on three occasions while the Unit 1 AB EDG was inoperable for more than four hours during surveillance testing. Additionally, there were instances of inoperability in the Emergency Core Cooling System (ECCS) Train B constituting a "Loss of Safety Function" and is-reportable in accordance with 10 CFR 50.73(a)(2)(v).

The RHR pump oil leak and the EDG have been repaired and are operable. The apparent cause has been determined that.Station leadership was not equipped with a consistent methodology to effectively manage risk associated with various station activities that possessed apparent low probability of occurrence. Corrective actions to preclude repetition include enhancements to equipment monitoring and oil level management. Additionally, risk process - management improvements were implemented, and a change management plan created to ensure that the correct questioning attitude is taking place during key station meetings.

05000316/LER-2015-00115 January 2016Donald C. Cook Nuclear. Plant Unit 2

On April 23, 2015, at 0210, Donald C. Cook Nuclear Plant Unit 2 Reactor was manually tripped from approximately 2 percent of rated thermal power during plant restart following a refueling outage. Unit 2 Reactor was manually tripped due to the inability to maintain Average Reactor Coolant System Temperature above the Technical Specification (TS) required minimum Temperature for Criticality when two newly installed Steam Dump Valves failed open while being manually valved into service. The valves were subjected to, but not designed for, two phase flow.

The Root Cause has been determined to be that the modification process failed to identify and document all system operational vulnerabilities. The corrective action to preclude repetition is an enhancement of the Engineering Modifications procedure to require development and inclusion of a narrative to describe system operation, including key interfacing system operation.

The manual Reactor Protection System (RPS) actuation was reported via Event Notification 51004 in accordance with 10 CFR 50.72(b)(2)(iv)(B) and 10 CFR 50.72(b)(3)(iv)(A), and 10 CFR 50.72(b)(2)(i). The valid RPS actuation and the completion of the plant shutdown required by TS are reportable as a Licensee Event Report in accordance with (- 10 CFR 50.73(a)(2)(iv)(A) and 10 CFR 50.73(a)(2)(i)(A) respectively.

05000315/LER-2015-00423 October 2015Cook

On August 26, 2015, during a self-assessment, it was identified that a Pressurizer Power Operated Relief Valve (PORV) would be rendered inoperable if its associated Control Air Compressor (CAC) is unavailable.

One of the three PORVs is not provided with a source of back up air. Therefore, when considering a dual unit LOOP concurrent with the unavailability of the CAC, it was recognized that the associated PORV should be considered inoperable. _ An evaluation concluded that the Unit 1 and Unit 2 CACs were not available when removed from service for LCO 3.4.11, conditions B and H were not entered and the associated action requirements were not met for each occasion. Therefore, this event is reportable in accordance with 10 CFR 50.73 (a)(2)(i)(B).

To correct this condition, procedures for removing CACs from service are being revised to add a precaution to declare the affected PORV inoperable while the CAC is unavailable.

05000315/LER-2015-00312 August 2015Cook

On June 18, 2015, a review based on U. S. Nuclear Regulatory Commission (NRC) Information Notice (IN) 2015-05, "Inoperability of Auxiliary and Emergency Feedwater Auto-Start Circuits on Loss of Main Feedwater," identified that Unit 1 is susceptible to the subject of the IN. Limiting Condition for Operation (LCO) 3.3.2, "Engineered Safety Feature Actuation System (ESFAS) Instrumentation," does not have a Condition with a provision for two required channels to be inoperable at the same time, which is the case for normal startup and shutdown of the Unit 1 Main Feedwater (MFW) pumps and some types of maintenance and testing.

An evaluation concluded that the Unit 1 MFW system has been operated in a manner such that the automatic initiation of Auxiliary Feedwater on loss of all MFW pumps was disabled on multiple occasions over the past three years. This is contrary to U1 LCO 3.3.2, requirements.

This condition is a legacy discrepancy between Unit 1 Technical Specifications (TS) and the Unit 1 MFW pump design existing since the initial operation of Unit 1.

.., To correct this condition, the NRC has approved an amendment to Unit 1 LCO 3.3.2 which aligns the plant design and TS requirements.

05000316/LER-2013-00124 September 2013Cook

On July 28, 2013, the Donald C. Cook Nuclear Plant Unit 2 reactor was operating at 100 percent power. At 1018, reactor operators manually tripped the reactor when reaching a low steam generator level threshold during a secondary plant transient event.

The secondary plant transient occurred when a steam supply valve closed to the Right Moisture Separator Reheater which resulted in feedwater heater level oscillations followed by Heater Drain Pumps tripping on heater low levels. This caused feedwater pump suction pressure to lower and automatically tripped the West Main Feedwater Pump. As a result, steam generator level lowered to 23 percent on the #4 Steam Generator. The reactor operators manually tripped the reactor based on a manual trip threshold for Steam Generator levels that was established by the Unit Supervisor.

The initiating cause of the steam supply valve closure and subsequent secondary plant transient was a loss of control air to the air operated valve resulting from fretting of the control air line.

The Reactor Protection System and the specified Auxiliary Feedwater System actuation was reported in accordance with 10 CFR 50.72(b)(2)(iv)(B) and 10 CFR 50.72(b)(3)(iv)(A). The valid actuation is reportable as a Licensee Event Report (LER) in accordance with 10 CFR 50.73(a)(2)(iv)(A).

05000315/LER-2013-00224 June 2013Cook

On April 24, 2013, the Donald C. Cook Nuclear Plant (CNP) Unit 1 reactor was in a refueling outage and defueled.

At 1411, a ground fault occurred on a power cable routed between 1-TR101CD, 4kV Buses 1C and 1D Reserve Feed Auxiliary Transformer (RAT) and 4kV circuit breaker 1-1C4, Reserve Incoming Feed from RAT 1-TR101CD. Fault protection circuitry caused breaker 12-12CD, Reserve Feed Auxiliary Transformers TR101CD and TR201CD Supply Breaker to open which de-energized both the Unit 1 and Unit 2 Reserve Feed Transformers, respectively. The unexpected loss of Train A Reserve Feed on Unit 1 caused a valid actuation of remained stable at 100% power after the loss of Train A Reserve Feed power to the 2-TR201CD RAT.

The apparent cause of the power cable failure was a reduction of the insulation dielectric strength of the 4kV cabling running from the 1-TR101CD transformer to the plant buses. The insulation properties were affected from cable age combined with a stressor of a prolonged pressure point from the cable lay path in the cable tray.

The valid actuation and start of the U1 CD EDG was reported in accordance with 10 CFR 50.72(b)(3)(iv)(A), as an eight hour report. The valid actuation is reportable as a Licensee Event Report (LER) in accordance with 10CFR 50.73(a)(2)(iv)(A), System Actuation of an Emergency Diesel Generator.

05000315/LER-2013-00128 May 2013Cook

On March 30, 2013, at 0124 EDST, Donald C. Cook Nuclear Plant (CNP) Unit 1 reactor was in Mode 5, Cold Shutdown, after shutdown for a refueling outage. During planned maintenance activities, a small amount of dry boric acid was identified on the weld face of a 3/4 inch socket welded elbow-pipe connection upstream of a flow instrument isolation valve of the Reactor Coolant System (RCS). The weld is located in a non-isolable section of the RCS piping. Liquid dye penetrant testing was performed on March 31, 2013, at 0414 EDST and identified a 10mm long linear indication on the face of the weld. The indication is considered a through wall leak of the RCS that was active during the past operating cycle during modes of applicability. Technical Specification Limiting Condition for Operation (LCO) 3.4.13 limits the RCS to no pressure boundary leakage and is applicable in Modes 1, 2, 3, and 4.

Based on engineering judgment, the apparent cause is vibration fatigue of a cantilever tap connection which resulted in a through wall weld defect. Repairs completed include modification of the piping, revised fillet welds, and replacement of the elbow. Material failure analysis and a full causal evaluation of the socket weld and associated piping is pending at the time of this report.

The weld defect was reported in accordance with 10 CFR 50.72(b)(3)(ii)(A). The weld defect and the subsequent through wall leak of the RCS pressure boundary are reportable as a Licensee Event Report (LER) in accordance with 10 CFR 50.73(a)(2)(ii)(A) and 10 CFR 50.73(a)(2)(i)(B).

05000315/LER-2011-0017 November 2011Cook

On September 07, 2011, at 0854 hours, Donald C. Cook Nuclear Plant (CNP) Unit 1 Reactor tripped automatically due to a trip of the main turbine. All control rods fully inserted and the auxiliary feedwater system (AFW) started and performed as designed.

The reactor trip was uncomplicated and all major plant components functioned as designed; as such, there were no safety system functional failures. The reactor trip was reported in accordance with 10 CFR 50.72(b)(2)(iv)(B) and the AFW actuation was reported in accordance with 10 CFR 50.72(b)(3)(iv)(A). The reactor trip and AFW actuation are reportable as a Licensee Event Report (LER) in accordance with 10 CFR 50.73(a)(2)(iv)(A).

The main turbine tripped due to an automatic turbine trip signal generated by the main turbine thrust bearing wear detection system. The initial investigation has concluded that there was no actual thrust bearing wear condition. The cause of the inadvertent trip signal has been determined to be a result of inadequate installation of sensing equipment. This inadequate installation resulted in a spurious trip signal common to both channels.

Corrective actions have been taken to correct the installation.

05000316/LER-2003-0032 February 2005Cook

This supplemental LER is being issued to update the causal and corrective action statements. At 0400 hours on March 5, 2003, Technical Specification (TS) Limiting Condition for Operation (LCO), Action "a" was entered to perform routine maintenance on the Unit 2 West Motor Driven Auxiliary Feedwater (MDAFW) pump. During post-maintenance testing, a loud 'buzzing" noise was heard emanating from the vicinity of the pump motor. A supporting/refuting evaluation was performed, which eliminated the pump, breaker, or system alignment as the possible source of the noise. At this point, the decision was made to replace the suspect motor. Initially, Indiana Michigan Power (I&M) had expected to complete the replacement of the West MDAFW pump motor within the allowed outage times specified in TS However, unanticipated delays prevented the completion of this activity within the allowed outage time.

Therefore, I&M requested, and was granted, enforcement discretion on March 8, 2003. .

The apparent cause of the Unit 2 West MDAFW pump motor noise was loose air baffles due to mounting hole deformation as determined by the vendor's as found condition analysis. The cause for the failure to complete the motor replacement within the allowed outage time was inconsistent maintenance work practices and inadequate interface requirements that resulted In a lack of command and control process for short term LCO activities. Corrective actions to prevent recurrence included the establishment of administrative guidance to ensure the appropriate techniques and tools are used when performing work on critical components, and the development and satisfactory completion of coupling installation training. Also, going forward, KM established a team to respond to equipment issues that challenge short duration allowed outage time.

I&M determined that no net Increase in risk was associated with extending the TS 72-hour allowed outage time by an additional 36 hours to restore the West MDAFW pump to an operable status. Although the proposed action deviated from a requirement In TS, it did not affect any safety limits, setpoints in the TS, or other operational parameters, nor did it affect any margins assumed In the accident analyses. In addition, the redundant Unit 2 East MDAFW pump and TDAFW pump continued to be operable to perform their required design function. The Unit 2 West MDAFW pump motor was replaced with a spare motor and the pump was declared operable at 0246 hours on March 9, 2003.

05000316/LER-2003-00517 February 2004CookOn December 30, 2003, at approximately 1328 Eastern Standard Time, the Unit 2 reactor automatically tripped on low steam generator water level coincident with feed flow less than steam flow for Steam Generator #22. Just prior to the trip, the Control Room Instrument Distribution (CRID) IV inverter transferred to the alternate power supply. A Feedwater Isolation Relay (K666X2), powered from CRID IV, opened. The opening of the relay initiated a seal-in closure signal to Steam Generator #22 and #23 Feedwater Isolation Valves (2-FMO-202 and 2-FMO-203), resulting in a loss of feedwater flow to Steam Generators #22 and #23 and produced a low steam generator water level trip coincident with feed flow less than steam flow. Following the reactor trip, the Unit Output Breakers failed to automatically open because a Main Turbine Stop Valve position indicator failed to provide a closed indication. The Unit Output Breakers were manually opened in accordance with the reactor trip response procedure. All safety components started and performed as expected. The initiator of the reactor trip was determined to be a momentary ground on the GRID IV bus, which occurred during the conduct of instrument calibration. The ground caused the automatic transfer of CRID IV to the alternate power source. The voltage drop on the CRID IV bus caused the Feedwater Isolation Relay to open. The root cause of the event has been determined to be inattention on the part of the Instrument and Control Technician who was performing the calibration. Corrective actions include the establishment of enhanced controls for the disconnecting and connecting of electrical leads.
05000316/LER-2002-00512 January 2004Cook

At 2301 firs on May 12, 2002, Unit 2 tripped due to an instrument rack power supply failure. Specifically, the second of two redundant 24-volt direct current (VOC) power supplies to reactor control instrumentation control group cabinet 2-PS-CGC-16 failed. The failure of both power supplies caused steam generator (SG) feedwater regulating valve 2-FRV-210 to close. Unit 2 subsequently tripped on low water level in SG-21 coincident with low feedwater flow. In accordance with 10 CFR 50.72 (b)(2)(iv)(B), a four-hour ENS notification (Event #38915) was made to the NRC on May 13, 2002, at 0255 hours for an event or condition that resulted in an actuation of the reactor protection system (RPS) when the reactor is critical. As such, this LER is being submitted in accordance with the requirements of 10 CFR 50.73 (a)(2)(1v)(A) for a condition or event that resulted in an automatic actuation of the RPS system.

The preliminary cause of this event was age-related failure of components within the power supplies. A contributing factor was that no provisions existed for periodic monitoring of the power supplies.

This event had minimal safety significance since plant procedures and operator training provided sufficient direction for control room personnel to shutdown the plant and maintain it in a safe shutdown condition. The failed 24-VDC power supplies were replaced. The remaining 24-VDC control group power supplies in Unit 2 were inspected and one power supply was replaced. Routine tasks have been established to verify the availability of the 24-VDC power supplies for both Unit 1 and Unit 2.

05000315/LER-2002-0081 August 2003Cook

On June 4, 2003, with Unit 1 in MODE 1, during an extent of condition review for LER 50-316/2003-004-00, "Weight of Ice Basket Below Minimum Allowed in Technical Specification (TS)," Donald C. Cook Nuclear Plant (CNP) discovered that on April 27, 2002, Unit 1 was not placed into shutdown action as required by TS

On April 25, 2002, Unit 1 was operating in MODE 1, with ice basket weighing in progress. Ice Basket 24-1-7 was weighed and discovered to be weighing 1099 pounds (lbs.), which is below the minimum acceptable weight of 1144 lbs. as specified in TS CNP failed to recognize that this condition constituted a failure to meet the Limiting Condition for Operation (LCO) for TS and did not enter the associated 48 hour LCO action for an inoperable ice bed. Accordingly, on April 27, 2002, Unit .1 was not shut down in accordance with TS The cause for the failure to comply with the TS was human error. Procedure 12-EHP-4030-010- 262, "Ice Condenser Surveillance and Operability Evaluation," will be revised to include instructions that a low ice basket weight results in an entry into the action statement of TS Training specific to TS will be provided to the Operators. This condition is being reported in accordance with the reporting criteria specified in 10 CFR 50.73(a) (2) (1) (B) as a failure to meet the requirements of TS

05000316/LER-2003-00425 June 2003Cook

On April 26, 2003, Donald C. Cook Nuclear Plant (CNP), during the performance of a routine inspection of the ice bed within the Unit 2 ice condenser, identified that ice basket 11-7-1 weighed 1125 pounds (lbs.). Technical Specification (TS) requires that the ice bed shall be OPERABLE with each ice basket containing at least 1144 lbs. of ice (end-of-cycle). Therefore, the weight of ice basket 11-7-1 did not meet the minimum required weight specified in TS 3:6.5.1d.

This condition is reportable pursuant 10 CFR 50.73(a) (2) (i) (B). During the extent of condition evaluation for this event, CNP discovered that during the Unit 1 2002 refueling outage ice basket 2 4 - 1 - 7 fell below the minimum TS weight limit. Ice basket 24-1-7 was emptied and refilled with 1445 lbs. of ice. This condition was not recognized as being reportable at that time. The failure to initiate an LER for ice basket 24-1-7 has been entered into the CNP corrective action program and will be reported in LER 50-315/2002-008-00.

Ice basket 11-7-1 was emptied, inspected for damage, and refilled with 1484 lbs. of borated ice. Additionally, in accordance with TS, upon discovery of the low weight in ice basket 11- 7-1, an additional 20 ice baskets within the same bay were weighed. The average weight of the 20 additional ice baskets and the discrepant basket (ice basket 11-7- 1) was greater than 1144 lbs. Additional administrative requirements will be added to the ice basket inspection procedure to ensure discrepant conditions are evaluated prior to the basket being emptied.

05000315/LER-2003-00228 March 2003Cook

This special report is provided in accordance with the special reporting requirements specified in Donald C. Cook Nuclear Plant (CNP), Technical Specifications (TS), Action 22B. Radiation Monitor 1-MRA-1701, "Steam Generator #2 Power Operated Relief Valve (PORV) 1-MRV-223 outlet radiation detector," has been inoperable since March 16, 2003, therefore exceeding the allowed 7 days specified in TS, Action 22B.

On Sunday, March 16, 2003, at 1119 hours, 1-MRA-1701, Unit 1 Steam Generator #2 PORV, 1-MRV-223 radiation monitor, went into a high alarm during source check operation. The high alarm cleared after 15 minutes with no action taken. Based on this condition of unreliable indication, the control room shift declared 1-MRA-1701 inoperable.

Subsequently, on Saturday, March 22, 2003, at 0243, 1-MRA-1702, Unit 1 Steam Generator #3 PORV was declared inoperable, in accordance with TS, to allow de-energization of 1-MRA-1700, "Steam Generator safety relief PORV Loops 2 and 3 monitor," for Data Acquisition Module (DAM) card replacement in support of 1-MRA-1701 troubleshooting.

Corrective actions have been performed, 1-MRA-1701 and 1-MRA-1702 were both returned to operable status at 1300, Friday, March 28, 2003.

05000315/LER-2003-00117 March 2003Cook

On January 15, 2003, at approximately 2010 hours, a fault occurred in the Unit 1 main transformer.

A The fault caused the current differential relays to actuate resulting in an automatic trip of the main transformer.

A A sudden internal fault within the main transformer ruptured the transformer oil tank resulting in a.loss of oil and a fire. A The loss of the main transformer precipitated an automatic trip of the main generator and an immediate turbine and reactor trip. A The main transformer fire was extinguished within 35 minutes of the event with one minor ref lash, which was promptly controlled and extinguished by onsite fire brigade members.

A One minor personnel injury occurred requiring offsite medical attention. A An Unusual Event was declared based on a fire of more than 15 minutes in duration within the protected area. A All safety-related components functioned properly and no significant discrepancies'in equipment - time responses were noted. A In accordance with 10 CFR 50.72(b)(2)(iv)(B), 10 CFR 50.72(b)(2)(xi), and 10 CFR 50.72(b)(3)(iv)(A), all, applicable event (EN #39513) and emergency plan required notifications were completed in a timely manner. A As such, this LER is being submitted in accordance with the requirements of 10 CFR 50.73(a)(2)(iv)(A) for a condition resulting in an automatic actuation of the reactor protection system. A A one-hour report was completed at 2105 hours and the remaining three reports were completed by a single notification at 2339 hours.

A The apparent cause of the event was a sudden internal fault within the main transformer.

A Corrective actions included replacement of the main transformer. A Other non- safety related components damaged by the resultant fire were either repaired or replaced.

C FORM 366 (7-2001)

05000316/LER-2002-00413 December 2002Cook

At 00:01 hours on 01/19/02, in preparation for a Unit 2 refueling outage, Operations shift personnel initiated a planned manual reactor trip of Unit 2 from 22t power per Procedure 02-OHP-4021-001-003, Revision 15, T "Power Reduction." T Shortly thereafter, an automatic start of the turbine driven auxiliary feedwater pump (TDAFP) occurred as a result of a valid low-low level indication in the steam generators. T The automatic start of the TDAFP was determined to be an "unanticipated" engineered safety feature (ESF) actuation.

Steam generator levels rapidly recovered. T Operators secured the"TDAFP and throttled the flows from the motor driven auxiliary-feedwater pumps in accordance with plant procedures for reactor trip response and recovery. T Reactor coolant system cooldown and depressurization proceeded normally. T During the trip, pressurizer level shrank lower than procedurally anticipated, resulting in a reactor coolant system 'letdown isolation.

At 07:56 on 01/19/02, the Shift Manager made an eight hour, non-emergency notification to the NRC (EN# 38640) per 10 CFR 50.72(b)(3)(iv)(A) for an unanticipated ESF actuation. T The cause of this event was inadequate procedural guidance. T Corrective actions included revision of the applicable procedures to include a reduction in the planned power level trip point to reduce the potential for automatic start of the TDAFP.

05000316/LER-2002-00713 December 2002Cook

On November 2, 2002, at 0827 hours, the Unit 2 CD Emergency Diesel Generator (EDG) , was declared inoperable and Technical Specification (TS), Action "b", was entered in preparation for routine surveillance testing in accordance with TS . a . 5 . T Within approximately 10 minutes after reaching full load of 3500 kilowatts (kW) during the surveillance test, the CD EDG load began oscillating approximately 150 kW. T The amount of time required to correct this condition exceeded the 72-hour allowed outage time requirements of TS, Action "b". T Donald C.

Cook Nuclear Plant (CNP) requested and received enforcement discretion from the Nuclear Regulatory Commission (NRC), to extend the 72-hour allowed outage time by an additional 72 hours. T The purpose of this extension was to allow sufficient time to restore the Unit 2 CD EDG to operable status and exit TS, Action "b". T CNP evaluated the described condition and determined that the risk of operating an additional 72 hours with the Unit 2 CD EDG unavailable was less than the risk associated with a plant shutdown. T The apparent cause of the load oscillations was a failure of the electronic governing module in the EDG speed governing system.

Corrective actions include replacement of the governor. T A formal root cause analysis is in progress to ensure adequate corrective actions to prevent recurrence are identified and implemented.

05000315/LER-2002-00513 August 2002Cook

At 1443 hrs on June 14, 2002, Unit 1 was manually tripped following the trip of the East main feedwater (FW) pump (MFP). The East MFP tripped due to a loss of main feed pump turbine condenser vacuum caused by an influx of debris following the start of the #13 circulating water (CW) pump. On June 14, 2002, at 1751 hours, in accordance with 10 CFR 50.72 (b)(2)(iv)(B), a four-hour ENS notification (Event No. 38993) was made to the NRC for a condition that resulted in an actuation of the reactor protection system when the reactor is critical.

The cause of this event was the transport of debris (primarily zebra mussel shells and sand) into the East MFP turbine condenser upon the start of the #13 CW pump. A contributing factor was the closure of 12-WMO-30 (the center lake water intake valve) a few days prior to the start of the #13 CW pump.

The safety significance of this event was minimal since plant procedures and operator training provided sufficient direction for control room personnel to shutdown the plant and maintain it in a safe shutdown condition. In addition, this event had no impact on the ability of the main FW system to perform its feedwater isolation accident mitigation function.

The Unit 1 East and West MFP turbine condenser tubes and waterboxes were cleaned on June 14, 2002.

CNP will take actions to mitigate the effects of debris on CW pump startups with the unit on line. Specifically, precautions will be added to the CW system operating procedure to identify the potential vulnerability for debris intrusion associated with starting CW pumps with the unit on-line. The procedures will also include guidance for use of MFP turbine condenser waterbox lancing when starting a CW pump with a unit on-line.

05000315/LER-2002-0062 August 2002Cook

On June 12, 2002, at 1345 hours, the "BC" 34.5 kilovolt (kV) circuit breaker opened and a trouble alarm for the TR101CD reserve auxiliary transformer was received in the control room. This was caused by an explosion in the 345 kV switchyard and oil fire in the "L" switchyard output feeder breaker. This resulted in the loss of the preferred offsite power source to the Unit 1 East Essential Service Water (ESW) pump. Since the Unit 2 East ESW pump was out of service for planned maintenance to replace the pump, Unit 1 entered the 2-hour action requirement of Technical Specification (TS) 3.0.5 at 1345 hours. Subsequent protective switching by the system load dispatcher resulted in the loss of the preferred offsite power source to the Unit 2 West ESW pump and Unit 2 also entered the 2- hour action requirement of TS 3.0.5 at 1359 hours. Donald C. Cook Nuclear Plant (CNP) requested and received enforcement discretion from the NRC to extend the 2-hour allowed action time by 10 hours to allow sufficient time to restore the Unit 2 East ESW pump to an operable status and exit TS 3.0.5. This Licensee Event Report (LER) is being submitted in accordance with the requirements of 10 CFR 50.73 (a)(2)(i)(B) for operation or condition prohibited by the TS.

CNP determined that compliance with TS 3.0.5 to place both Unit 1 and Unit 2 in Mode 3 within the time required by the action statement could initiate an undesirable transient. In addition, due to the degraded material condition of the switchyard at the time of the event, the risk associated with maintaining both units on line for an additional 10 hours was less than the risk associated with taking both Unit 1 and Unit 2 off line. Therefore, there was no net increase in risk associated with operating the plant for approximately 10 additional hours. CNP completed replacement and testing of the Unit 2 East ESW pump and exited TS 3.0.5.

05000315/LER-2002-00328 June 2002Cook

On May 2-3, 2002, with the unit at approximately 52% power, seven of twenty Main Steam Safety Valves (MSSVs) (EIIS:SB,RV) failed to meet Technical Specifications (TS) required lift settings specified in TS, Table 4.7-1.

TS allows a +/- 3% tolerance on the as-found lift setting and requires all tested valves to be set to a +/- 1% as-left tolerance. Operations personnel entered the applicable TS Action Statement until each valve was adjusted and tested satisfactorily. In accordance with 10 CFR 50.73(a)(2)(i)(B), this condition is being reported as a condition prohibited by TS.

The cause of the test failures was attributed to metallic bonding between the valve disc and the nozzle.

Adjustments were made and all of the "as-left" lift settings were within the +/- 1% acceptable range. No component was left outside of its acceptable range.

The MSSVs ensure that the secondary system pressure will be limited to within 110% of 1085 psig during the most severe anticipated system operational transient. The as-found test results of the seven valves discussed in this LER were still well below the 110% design pressure value. Thus, there is reasonable assurance that the valves were capable of performing their primary safety function as well as maintaining an adequate heat sink for the primary side. Therefore, this event is not considered safety significant since the valves in question would have performed their function.

05000316/LER-2002-00329 May 2002Cook

During the weekly battery surveillance on April 3, 2002, a maintenance electrician identified cracks in the top cover between the post seals and the sample tubes of battery cells 27 and 102 of the 2AB 250-volt D.C. battery bank. The cracks were above the electrolyte with no indications of electrolyte leakage observed. The time of identification was 1200 on April 3, 2002. An action request was generated at 1530 on April 3, 2002, to document the deficiency. Shift manager notification was not made by the initiator or supervisor performing the approval as required by procedure. Operations became aware of the equipment deficiency at 1700 on April 4, 2002, when a deficiency tag was processed for the 2AB battery. The Shift Manager visually confirmed the cracking on cells 27 and 102, and identified, during an extent of condition inspection, that cell 35 exhibited the same cracking phenomenon. The 2AB battery was declared INOPERABLE at 1812 and Unit 2 entered technical specification (TS) action statement A TS required shutdown commenced at 2114 on April 4, 2002, when the battery was not returned to an operable status.

A four-hour ENS notification, event number 38832, was made at 2330 on April 4, 2002, in accordance with 10 CFR 50.72(b)(2)(i) for an initiation of a reactor shutdown required by the plant's TS.

The TS required shutdown was terminated at 0145 on April 5, 2002, when a Notice of Enforcement Discretion (NOED) was granted by the Nuclear Regulatory Commission (NRC). In granting the NOED, the NRC would not enforce the allowed outage time in TS action for 13 hours, thereby providing an additional 11 hours for restoration of the 2AB battery to an OPERABLE status. The three cracked battery cells were replaced and 2AB battery was declared OPERABLE at 0755 on April 5, 2002. Unit 2 subsequently returned to full power.

05000315/LER-2002-00219 April 2002Cook

On February 19, 2002, stroke testing of the Unit 1 pressurizer power operated relief valve (PORV) block valves 1-NMO-152 and 153 was being performed in accordance with surveillance test procedure 01-IHP-4030-STP-053, "Pressurizer Power Operated Relief Valve Functional Test." During the test, a reactor operator noticed that the control switches for pressurizer PORVs 1-NRV-152 and 153 were positioned slightly to the left of the AUTO position. Subsequent investigation identified that the control switches had been out of position from February 6, 2002, to February 19, 2002. As such, the pressurizer PORVs were declared inoperable due to the loss of automatic function to control reactor coolant system pressure below the setting of the pressurizer code safety valves. This condition is reportable in accordance with 10 CFR 50.72(a)(2)(i)(B), for a condition prohibited by plant technical specifications.

The cause of this event was the lack of awareness by the reactor operators to the potential for mis-positioning the pressurizer PORVs when placing the control switch in the AUTO position.

This event has minimal safety significance since the Donald C. Cook Plant Nuclear Plant accident analyses do not take credit for the automatic actuation of the pressurizer PORVs for overpressure protection of the reactor coolant system. In addition, the valves would still be capable of operating in manual to mitigate a steam generator tube rupture accident.

The Unit 1 pressurizer PORV control switches were restored to the AUTO position and the PORVs were declared operable.

A lessons learned memo was issued to all plant operators regarding proper pressurizer PORV control switch manipulation.

The appropriate procedures will be revised to re-order the restoration steps such that the pressurizer PORVs are placed in the AUTO position before the associated block valves are opened.

05000316/LER-2002-00212 April 2002Cook

On February 12, 2002, Technical Specification (TS) 3.9.4.c was violated when the 100 PSI Control Air to Containment Control Air Header #2 Train 'B' Containment Isolation Valve, 2-XCR-101(EllS:LKSHV), was stroked open during core alterations with open test connections on both sides of the valve, one inside containment and one outside. This configuration provided direct access from the containment atmosphere to the outside atmosphere. The apparent cause was determined to be ineffective procedural control (02-OHP-4030.STP.041). The preferred method for establishing refueling integrity for 2-CPN-74 in the procedure does not consider the possibility that the control air ring headers may be cross-tied. A contributing cause was that the installation of containment control air header cross-tie jumpers was not documented in the Proceduralized Temporary Modification Log on January 20, 2002.

Upon discovery that the preferred method used to maintain refueling integrity for 2-CPN-74 was ineffective, an alternate method was established and valve 2-XCR-101 was visually confirmed to be intact and closed. The Temporary Modification Log Index was reviewed to verify that other Temporary Modifications were logged. The containment control air cross-tie jumpers were documented in the log at that time.

The refueling integrity procedures will be revised to ensure that the methods used to establish refueling integrity for Penetrations CPN-74 and CPN-29 recognize that the Containment Control Air headers may be cross-tied. Unit 1 and Unit 2 Type B and C Leak Rate Testing procedures will be revised to ensure that steps are added for documenting the placement of the containment control air header cross tie jumpers in the Proceduralized Temporary Modification Log.

05000316/LER-2002-00128 March 2002Cook

On January 26, 2002, during refueling outage 13, 10 CFR 50 Appendix J, Type B and C leak rate testing was being performed in accordance with procedure 02-EHP-4030-234-203, "Unit 2 B & C Leak Rate." This procedure requires root shutoff valve 2-GPX-301-V1 (ElISIK:SHV) from the nitrogen supply manifold to be in the closed position for testing.

When core alterations commenced, valve 2-GPX-301-V1 was thought to be tagged "Do Not Operate" in the closed position as required by procedure 02-OHP-4030-STP-041, "Refueling Integrity". Upon successful completion of the leak rate testing, an auxiliary equipment operator (AEO) found the root shutoff valve 2-GPX-301-V1 in the open position during the valve lineup restoration. This resulted in refueling integrity being lost while fuel movement was in progress. The control room was notified and core alterations were suspended. Based on investigation of this incident, the valve was mispositioned for approximately 10 hours. This breach of refueling integrity is prohibited by Technical Specification (TS) and is therefore reportable in accordance with 50.73(a)(2)(i)(B).

The cause of this event was failure to follow procedures. The AEO performing the initial valve lineup for testing opened valve 2-GPX-301-V1 and inappropriately pulled the "Do Not Operate" tag from the valve contrary to the requirements of plant procedures 02-EHP-4030-234-203 and 02-0HP-4030.STP.041.

Operations restored valve 2-GPX-301-V1 to the closed position, thereby re-establishing refueling integrity. A review of the completed B & C test lineups impacting refueling integrity was conducted and verified that no other loss of containment integrity had occurred during core alteration. A lessons learned memo was published and distributed to the auxiliary equipment operators. The human performance and personal accountability aspects of this issue have been appropriately addressed.

05000316/LER-2001-00312 March 2002CookThis supplemental LER was issued to identify the correct the reporting requirement for submittal of the LER. No other changes were made. On August 29, 2001, Donald C. Cook Nuclear Plant (CNP) Unit 1 was in MODE 5 for a planned maintenance outage and Unit 2 was in MODE 1. Unit 2 Operations personnel were performing a routine surveillance test of the Essential Service Water (ESW) system in accordance with approved plant procedures. At approximately 2255 hours, Unit 2 Operations personnel noted low ESW flow to both of the Unit 2 Emergency Diesel Generator (EDG) heat exchangers. The Unit 1 ESW flows were also checked and it was determined that ESW flow to both Unit 1 EDG heat exchangers was low. All four EDGs were declared inoperable. Unit 2 entered Technical Specification (TS) 3.0.3, and Unit 1 entered TS After flushing the ESW side of the associated heat exchangers both Unit 2 EDGs were declared OPERABLE at 2350 hours. Based on conservative decision making, Unit 2 was shut down on August 30, 2001, to facilitate the identification and correction of the causes for the low ESW flow conditions. The U.S. Nuclear Regulatory Commission was notified of the decision to commence a Unit 2 shutdown. A common mode failure of the EDGs was reported in accordance with 10 CFR 50.72(b)(3)(v), "Non-Emergency Events - 8-Hour Reports." The cause of the low flow conditions was pre-existing material failure of the Unit 1 East ESW strainer basket, which created a bypass flow path around the strainer. The bypass flow path allowed large debris to enter the ESW system. The cause of the EDG common mode failure was the station design and operational practices that allowed aligning the ESW supplies to each EDG from both ESW headers on the associated unit. C Corrective actions included inspection and replacement of all baskets, revision of the applicable maintenance procedures which detail installation requirements, and modification to the design and operating procedures to maintain the alternate ESW valves to the EDGs normally shut during normal and accident conditions.
05000316/LER-2001-0045 December 2001Cook

On October 7, 2001, a reactor trip occurred at 8 percent reactor power. The trip was the result of a loss of rod control system voltage. The cause of the loss of rod control system voltage was an open resistor at the input to the north control rod drive motor generator (CRD-MG) voltage regulator. The open resistor caused a low voltage transient when the north CRD-MG field collapsed. A protective auxiliary relay removed power from the south CRD-MG voltage regulator resulting in a loss of rod control system voltage. The loss of voltage caused all control rods to rapidly insert, thereby, initiating a Power Range, Neutron Flux, High Negative Rate trip from the reactor protection system (RPS). The RPS actuation was initiated by actual plant conditions that satisfied the requirements for the initiation of the trip, and was, therefore, a valid RPS actuation.

The failed resistor was determined to be the result of a random component failure. The resistor was original equipment and inspection revealed no evidence of overheating or manufacturing defect. The defective resistor was replaced and, as a precaution, the remaining series resistor in the north CRD-MG along with the identical resistors in the south CRD-MG were replaced.

This event was reported in accordance with 10 CFR 50.72(b)(1)(iv)(B).

05000315/LER-2001-00421 November 2001Cook

On September 27, 2001, during Unit 1 startup activities, the unit was taken from Mode 4 to Mode 3 with the remote shutdown pressurizer level instrument inoperable. The inoperable instrument was identified in Mode 4, during performance of normal control room panel walkdowns. Despite this discovery, the unit was taken to Mode 3 in violation of Technical Specification (TS) 3.0.4. . During the extent of condition review for this event, it was identified that during Unit 1 startup activities on December 12, 2000, the required monthly channel check had not been performed for the pressurizer pressure instrumentation prior to transition to Mode 3. This condition was also determined to be a violation of TS 3.0.4. Both events were determined to be reportable per 10CFR50.73(a)(2)(i)(B) as conditions that are prohibited by TS.

The cause of the September 2001 violation was human error. Corrective actions included counseling of the responsible personnel and distribution of lessons learned. The cause for the December 2000 event was incorrect procedure guidance.

Corrective actions included the establishment of a Unit 1 Mode 3 constraint as a barrier to prevent additional violations while a change to the TS is processed that will permit the remote shutdown instrumentation (TS to be excepted from TS 3.0.4. The significance of the TS violations is considered minimal since the probability of an event requiring the Remote Shutdown System is low, and because the equipment can generally be repaired during operation without significant risk of spurious trip.

05000316/LER-2001-00226 October 2001Cook

This LER supplement is being submitted to include revised information related to the completed root cause evaluation.

This LER revision replaces the previous LER in its entirety. On January 23, 2001, during the removal of plant equipment from the Unit 2 lower containment personnel airlock, the airlock doors' interlock failed. This allowed the inadvertent opening of both the inner and outer lower containment airlock doors at the same time for approximately 5 seconds.

Technical Specification requires both containment airlock doors to be closed; except during normal transit entry and exit through containment, then at least one airlock door shall be closed. Because both lower containment airlock doors were open at the same time, an 8-hour ENS notification was made to the NRC in accordance with 10 CFR 50.72 (b)(3)(v)(C), for a condition or event that could have prevented the fulfillment of the safety function of a system needed to control the release of radioactive material.

The root cause for the containment airlock door interlock failure was the interlock mechanism slipping out of adjustment.

The specific failure involved a gradual loosening of the setscrews that hold the interlock gears in place.

Both the inner and outer lower containment airlock doors were immediately closed to restore containment integrity. The airlock door interlock was repaired and satisfactorily tested. Preventive maintenance (PM) activities for the airlock doors were evaluated and the root cause recommendations and vendor recommendations have been incorporated into the appropriate procedures. A detailed design analysis is presently being performed and is being tracked in accordance with the site Corrective Action Program. The appropriate procedure has been revised to include directions on the operation of the containment airlock doors and the consequences of improper airlock door configuration, including radiological and industrial safety concerns. This condition is not considered to be safety significant due to the extremely low probability of a Loss of Coolant Accident or Main Steam Line Break occurring during the 5-second time interval in which both airlock doors were open. A review of plant events during the past three years did not identify any conditions in which the containment doors were opened simultaneously. Therefore, this is considered an isolated event.

FORM 366 (7-2001) �