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On June 16, 2017, with the plant in Mode 1 and 100% reactor power, the 'A' Ultimate Heat Sink (UHS) Cooling Tower Fan was operating in fast-speed to cool the UHS retention pond. The fan spuriously tripped after 44 minutes of operation. The most probable cause of the spurious trip was a defective fast-speed thermal overload relay that had been installed as a replacement during recent preventative maintenance activities.

In Mode 1, Technical Specifications require each of two redundant UHS cooling tower trains to be capable of dissipating the heat contained in the Essential Service Water (ESW) system. An inoperable UHS cooling tower fan renders its UHS cooling tower train inoperable. Review determined that the fan was inoperable from the start of the preventative maintenance task, and existed for a duration of 96 hours and 23 minutes while the plant was in Mode 1. Consequently, it was concluded that the 'A' UHS Cooling Tower Train had been inoperable for a period of time longer than allowed by the plant's Technical Specifications.

Failure analysis is being performed by a vendor which will provide insight into the nature of the defective fast speed thermal overload relay. Maintenance procedures will be revised to include additional pre-installation testing of similar thermal overload relays to ensure that defects similar to the one that caused the reported failure are detected prior to installation in the plant.

On 4/20/2016, Callaway received preliminary analysis results showing that during a Design Basis Accident (DBA) the 'B' Train Control Room Air Conditioning System (CRAGS) would experience a pressure transient in the associated cooling water system greater than what is experienced during Engineered Safety Feature Actuation Signal (ESFAS) testing. This condition could damage the NC unit's gaskets, as evidenced during ESFAS testing completed on 4/14/2016, resulting in the affected CRAGS and Control Room Emergency Ventilation System (CREVS) trains not being capable of performing their required safety function. This event is being reported as a condition prohibited by Technical Specifications, an unanalyzed condition, and a condition that could have prevented fulfillment of a safety function.

The root cause of the event is that the original Essential Service Water (ESW) system design did not appropriately account for water column separation and collapse pressure transients inherent during operation. Following the 'B' train ESFAS testing on 4/14/2016, more robust gaskets were installed in affected components. A complete evaluation of the pressures and dynamic forces experienced by all ESW system subcomponents will be performed. The results will be compared to current design limits, and appropriate modifications will be performed to ensure sufficient margin exists in the plant design.

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

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

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

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

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

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

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

On July 23, 2015, plant operators became aware of indications of an increase in the Reactor Coolant System (RCS) unidentified leak rate. The indications included containment radiation alarms as well as increasing containment humidity and sump levels. An RCS inventory balance indicated an unidentified leak rate of 1.2 gpm leak which is greater than the Technical Specification limit of 1 gpm for unidentified leakage. Actions were taken to determine the source of the leak. A containment entry was made, and a steam cloud was identified to be coming from the Pressurizer Spray Valve cubicle. The plant was shut down in order to comply with requirements of the Technical Specifications.

It was determined that the leak was due to seat leakage through the RCS Pressurizer CVCS Auxiliary Spray Supply Drain valve BBV0400 and then through the non-safety related pipe flange immediately downstream of the valve.

The valve was tightened which reduced the leakage to 60 drops per minute. The flange gasket was replaced.

Additional causes and corrective actions are still being determined.

On 05/28/2013, oil was observed leaking from a 345-kV bushing on the Startup Transformer (XMR01) while the plant was in Mode 1. The leakage was addressed by tightening the bushing oil fill cap, and the Startup Transformer was declared operable on 05/30/2013 at 1648.

The Startup Transformer is part of one qualified preferred source of offsite AC power to the Class 1 E buses, as required by the plant's Technical Specifications. Investigation determined that the oil leak on the Startup Transformer was determined to have existed from a certain point in time prior to the time of discovery and that the Startup Transformer would not have been capable of meeting its Operability mission time of 30 days while the oil leak existed. Consequently, it was concluded that the transformer had been inoperable for a period of time longer than allowed by the plant's Technical Specifications.

The cause of this event was a human performance error which occurred during a maintenance activity on the Startup Transformer during Refueling Outage 19. Work instructions will be revised to provide photos and additional instruction on which components to loosen when power factor testing the Startup Transformer.

On 04/1 8/2013, a small fire occurred at the Unit Auxiliary Transformer which caused a loss of all non-vital power to the plant during core offload. At this point in the core offload, a fuel assembly was suspended in the spent fuel pool due to a torn grid strap. The assembly was considered to be in movement since the assembly was not in a "safe" or approved storage location. As a result of the loss of power, it was desired to restore temporary power to the 'B' train battery chargers to prevent loss (discharge) of the NK02 and/or NK04 batteries. Temporary power cables were routed through three doors in the Control Building, one of which was a Control Building Envelope (CBE) pressure boundary door. With cables running through the CBE door, mitigating actions were taken to seal the opening. Such mitigating actions are allowed in Modes 1-4 per Technical Specification (TS) 3.7.10, when Condition B applies for an inoperable CBE boundary. However, allowances for mitigating actions are not permitted for an inoperable boundary during the movement of irradiated fuel assemblies. For this situation, TS 3.7.10 Condition E applies, and its Required Actions are to immediately suspend CORE ALTERATIONS (E.l) and movement of irradiated fuel assemblies (E.2). The Control Room did not immediately recognize that Required Action E.2 was in effect; therefore, there was a delay in beginning this Action of approximately 2 hours and 24 minutes. Required Action E.2 was not met since the Action was not taken without delay.

NRC FORM 356 (10.20'0)

On 4/4/2013, during leak testing of a Service Water to Essential Service Water cross-connect valve, leakage in excess of 10 gpm was identified. Actions to further quantify the leakage rate and determine the cause of leakage found that the motor-operated valve (MOV) actuator coupling had become decoupled from the valve stem. Based on this finding, this valve was declared inoperable on 4/7/2013 at 20:46. Required actions B.1 and B.2 of Technical Specification 3.7.9 were entered. Repair of the valve was completed on 4/8/2013 at 0445.

After review of data from MOV testing on this valve, including a subsequent uncoupled test, it is estimated that the decoupled actuator condition could have existed for a significant period of time prior to discovery, possibly since 4/2/2012 when a leak check test performed on the valve identified zero leakage. Therefore, this condition is considered reportable.

The most probable cause is that bolts used to fasten the coupling block to the valve stem gradually loosened with the passage of time and from environmental effects, such as vibration and heating and cooling cycles.

Corrective actions include adding a periodic check of MOV valve shaft coupling block bolt torque to the periodic preventive maintenance performed on this and the other three cross-connect valves.

On March 2, 2010 with the plant in MODE 1 at 100% reactor power, a latent design issue was identified in regard to the essential service water (ESW) system and ultimate heat sink (UHS). Upon review of a calculation for UHS performance, it was determined that a limiting single failure had not been evaluated. During a Loss of Coolant Accident (LOCA), both ESW trains are assumed to operate for the first 8 hours of the accident. If a UHS bypass valve were to fail during a LOCA, flow from one train of ESW would be cooled by the UHS cooling tower while flow from the other train of ESW would flow directly to the UHS pond. This would lead to the UHS pond temperature increasing more quickly than previously analyzed, potentially exceeding the UHS pond temperature design basis accident limit in as little as an hour with no operator actions.

The cause for this unanalyzed condition is failure to re-evaluate the UHS/ESW single-failure analysis when UHS cooling tower capacity was questioned during construction of the plant. For corrective action, emergency operating procedures will be revised to include operator action if UHS bypass valves are lost during an accident scenario.

Design procedures are being updated to minimize the probability of generating non-conservative specifications, using non-conservative design inputs and assumptions in a calculation, and not evaluating single active failure in plant modifications as the corrective action to prevent recurrence.

At 1042 on 12/12/2008, while in Mode 3, an invalid reactor trip signal was generated during maintenance activities on intermediate range (IR) nuclear instrument SEN0036. In addition to the reactor trip, a feedwater isolation actuation occurred. Reactor Operators manually started motor driven auxiliary feedwater pumps to maintain steam generator levels, prior to an anticipated Auxiliary Feedwater actuation.

The IR high flux reactor trip was a result of removal of the control power fuses for IR nuclear instrumentation N-36 while performing work to replace a bistable card for SEN0036. It was desired to de-energize equipment prior to circuit card replacement to protect electronic circuits. When a step was included in the work document to remove the control power fuses it was not understood that a relay would be de-energized which allowed the IR High Flux Reactor trip signal to be generated.

Corrective action (CA) will include installing labels and training instrumentation and controls personnel about the effects of pulling control power fuses for nuclear instrumentation.

During calibration of Reactor Coolant System (RCS) Temperature Loop 3 on June 30, 2007, problems were identified which called into question the validity of a previous calibration on Loop 2. On June 30/July 1, 2007, Reactor Coolant System (RCS) Temperature Loop 2 calibration surveillance was performed to verify the results from the last loop calibration performed on June 9, 2007. It was determined that the Lower Flux input to the Over Temperature Delta Temperature (OTDT) setpoint circuit was Out of Tolerance (OOT). This condition was determined to have been sufficient to cause the OTDT setpoint to exceed its Technical Specification Allowable Value. The Loop 2 OTDT setpoint was inoperable for 21 days. The Temperature Loop 2 setpoint was returned to the correct value on July 1, 2007.

When RCS Temperature Loop 2 was calibrated on June 9, 2007 a wrong test configuration was used when making connections to simulate the Lower Flux input to the flux imbalance penalty circuitry in the Westinghouse 7300 system. The negative power supply lead must be grounded to properly simulate the input from the Nuclear Instrumentation System (NIS) cabinets; during the June 9, 2007 calibration this was not established. The calibration was performed on July 1, 2007 using the proper configuration. The loop calibration procedures have been revised to ensure the basis for this ground connection is clear.

On 5/12/2006 reactor power was being reduced to 45% for a planned maintenance activity. Reactor power had been lowered to approximately 48% when vibration on main turbine bearings started rising eventually reaching the turbine trip criteria. The turbine was manually tripped at 0047 on 5/12/2006.

Control rods subsequently stepped in under automatic rod control, as designed. The control rods I continually stepped in reducing power below 10% in approximately four minutes. Feedwater flow was controlled through the Main Feedwater Regulating Valves which are not normally in service below 20% power. At 0052, the Steam Generator High-High Level setpoint was exceeded on the 'A' Steam Generator resulting in a Feedwater Isolation Signal and Motor Driven Auxiliary Feedwater Actuation Signal. All safety systems responded as designed. A manual reactor trip was initiated at 0053 in accordance with procedural guidance for the loss of both main feedwater pumps. The cause of this event is an inadequate mitigation strategy in procedure OTO-AC-00001, "Turbine Trip below P-9" (50% power permissive setpoint). The procedural deficiency was the result of an inadequate procedure change review� I process used in 1991. Corrective Actions to Prevent Recurrence include revision of the procedure change review process and revision of OTO-AC-00001 to incorporate an appropriate mitigation strategy.

On 2/15/04, during plant startup and synchronizing to the grid, Callaway experienced oscillations in Steam Generator (S/G) levels which resulted in a main turbine generator trip and subsequent reactor trip. After the reactor trip occurred, to reduce the plant cooldown rate, operators attempted to secure the Turbine Driven Auxiliary Feedwater Pump (TDAFP). However, due to an automatic actuation signal being present, the TDAFP experienced an electrical and mechanical overspeed trip.

Post trip investigations determined that the S/G oscillations were due to not having aligned extraction steam to provide feedwater preheating. The overspeed trip of the TDAFP was per system design. A TDAFP actuation signal was present when the operators closed the steam supply valves, causing the valves to reopen automatically and in such a sequence as to cause an overspeed condition.

A Root Cause Analysis team was assembled and identified four Root Causes, plus several Corrective Actions to Prevent Occurrence.

This revision of LER 2003-006-00 is being submitted to change the reporting criteria to specify that this is only a voluntary LER and no violation occurred. On 7/3/03, with Callaway Plant operating in Mode 1 at 100 percent power, and during development of Licensed Operator Continuing Training (LOCT), it was discovered that an error existed in emergency procedure E-3, STEAM GENERATOR TUBE RUPTURE. The postulated accident involved a reactor trip due to a loss of off-site power compounded by a steam generator tube rupture (SGTR) on "D" loop of the reactor coolant system, and a stuck open auxiliary feedwater flow control valve. Early in the procedure, the Pressurizer Power Operated Relief Valves (PORV) were being armed in order to provide cold overpressure protection during the cool down phase. By arming the PORVs early, this made it difficult to meet the conditions required to secure Safety Injection later in the SGTR recovery, which potentially could prolong recovery from the SGTR. Prolonged recovery would result in additional liquid being released to the atmosphere via the ruptured steam generator's atmospheric dump valve and additional dose to the public.

Once the procedure error was identified, a procedure revision was issued which corrected the problem.

On 4/11/03, while at 100 percent power, it was discovered that a note contained in Technical Specification (T/S) 3.3.9 for the Boron Dilution Mitigation System (BDMS), had been inappropriately applied during past reactor startups. This had been interpreted to allow blocking BDMS while withdrawing Shutdown (S/D) Bank rods in Mode 3. This action is not allowed in Mode 3 per Final Safety Analysis Report (FSAR) accident analysis Section 15.4.6.2 where BDMS is credited for automatically terminating a dilution event while in Mode 3.

Wording of T/S 3.3.9 and T/S 3.3.9 Bases did not provide clear guidance as to what constitutes "reactor startup". The Bases indicate BDMS could be blocked prior to withdrawing "rods" for startup. These words do not delineate between control banks and shutdown banks. Based on this unclear guidance, procedure OTG-ZZ-0001A was incorrectly revised allowing the blocking of BDMS prior to withdrawing shutdown banks. The discovery of the unclear T/S wording was the result of requested procedure enhancements to clarify when it was allowable to block BDMS.

A review of reactor startups within the last 3 years indicated that BDMS was inappropriately blocked on three separate startups.

The first occurred on 11/24/02, the second on 12/17/02, and the third on 4/2/03. Plant procedures governing reactor startup were revised to remove statements allowing blocking BDMS while withdrawing S/D Bank rods in Mode 3.

On 2/13/02, Callaway Plant was in Mode 4 with Reactor Coolant System (RCS) temperature at 300 degrees F and RCS pressure at approximately 395 psig. The Reactor Trip Breakers were closed, Main Turbine Shell warming was in progress, and Auxiliary Feedwater system testing was being conducted. At 0434, a Reactor Protection System (RPS) signal was generated that tripped open the Reactor Trip Breakers. Subsequent investigation revealed the trip was due to pressure in the Main Turbine increasing above an interlock setpoint of 56 psig (P-13), which is equivalent to 10 percent power. When this interlock was satisfied, it in turn enabled a Low Pressurizer Pressure Reactor Trip permissive (P-7) with a setpoint of RCS pressure less than 1885 psig. Since RCS pressure was approximately 395 psig, an RPS signal was generated to open the Reactor Trip Breakers.

The cause of the event was operating procedures not clearly identifying plant conditions required to perform Main Turbine Shell Warming. Corrective actions taken were to revise plant procedures to reflect appropriate cautions and restrictions for performing Main Turbine Shell warming.