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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.

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.

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.

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).

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).

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) 3.7.1.2, 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 3.7.1.2. 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 3.7.1.2, 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.

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.

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) 3.6.5.1d 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 4.6.5.1.b.2, 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.

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)

On November 2, 2002, at 0827 hours, the Unit 2 CD Emergency Diesel Generator (EDG) , was declared inoperable and Technical Specification (TS) 3.8.1.1, Action "b", was entered in preparation for routine surveillance testing in accordance with TS 4.8.1.1.2 . 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 3.8.1.1, 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 3.8.1.1, 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.

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.

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 3.8.2.3.b. 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 3.8.2.3.b 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.

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.

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 3.3.5.5) 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.