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 Report dateSiteEvent description
05000483/LER-2017-00213 October 2017Callaway

On August 15, 2017, Callaway Plant was in Mode 1 at 100 percent power. During evaluation of protection for safety-related equipment from the damaging effects of tornados, Callaway Plant personnel determined that the minimum-flow recirculation lines for the turbine-driven auxiliary feedwater pump (TDAFP) and both motor-driven auxiliary feedwater pumps (MDAFPs) could be damaged if a postulated tornado-generated missile were to penetrate the condensate storage tank (CST) valve house and strike the lines. In response, Operations declared all three auxiliary feedwater pumps inoperable.

Compensatory measures were implemented consistent with Enforcement Guidance Memorandum (EGM) 15-002, "Enforcement Discretion for Tornado-Generated Missile Protection Noncompliance." Upon completion of the initial compensatory measures, the TDAFP and MDAFPs were declared Operable but nonconforming.

Subsequent to the condition identified on August 15, 2017, continued investigation of tornado missile vulnerabilities led to discovery that the exposed steam exhaust stacks for the main steam safety valves and atmospheric steam dump valves, as well as the exposed vents for the diesel generator fuel oil storage and day tanks, were also susceptible to tornado missile damage to the extent that compliance with General Design Criterion 2 is not ensured. Compensatory measures were then promptly implemented for these conditions, as well, in accordance with EGM 15-002 such that the affected systems have been evaluated to be nonconforming but Operable.

It has been determined that the identified noncomformances are an original plant design legacy issue. Long-term resolution for establishing compliance is under development and will be completed within the time frame described in the EGM.

05000483/LER-2017-00115 August 2017Callaway
Docket Number

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.

05000483/LER-2015-0012 December 2016Callaway

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. The root cause of the leak was determined to be that valve BBV0400 was not fully closed at normal closing force in RF20. The valve was replaced in April 2016 during Refueling Outage RF21. Additionally, a plant procedure was revised to require that selected valves (including BBV0400) are closed in MODE 3 using normal force or additional force if leakage is identified.

05000483/LER-2016-00117 October 2016Callaway

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.

05000483/LER-2015-0027 September 2016Callaway

During plant cooldown in response to conditions reported to the NRC on July 23, 2015 in Event Notification 51253, Callaway was in Mode 3 (Hot Standby) and on the way to Mode 5 (Cold Shutdown). In accordance with cooldown procedures, Callaway was operating with one Main Feedwater Pump (MFP) when the pump speed unexpectedly lowered to 0 RPM. The pump was manually tripped in response to the condition. This led to a decrease in water level in the steam generators. Operators manually activated the Auxiliary Feedwater System to maintain water level in the steam generators. This system actuation is reportable per 10CFR50.73(a)(2)(iv)(A).

Fault tree analysis and subsequent testing identified the most probable cause for the loss of the 'B' MFP is a software defect introduced during the software development process for the digital feedwater control system installed in 2013. Plant operating procedures have been revised to allow for a rapid start of the startup MFP during a plant shut down. Additionally, procedures were revised to allow for the startup MFP to be placed in a ready state when only one MFP is required based on power level.

These procedure revisions will provide defense in-depth against unnecessary Auxiliary Feedwater System actuations in the future.

05000483/LER-2015-00412 October 2015Callaway

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.

05000483/LER-2015-004, Auxiliary Feedwater Control Valve Inoperable Due To Faulty Electronic Positioner Card12 October 2015Callaway

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.

05000483/LER-2015-003, Reactor Trip Caused by Transmission Line Fault1 October 2015Callaway

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.

05000483/LER-2015-002, Manual Auxiliary Feedwater System Actuation17 September 2015Callaway

During plant cooldown in response to conditions reported to the NRC on July 23, 2015 in Event Notification 51253, Callaway was in Mode 3 (Hot Standby) and on the way to Mode 5 (Cold Shutdown). In accordance with cooldown procedures, Callaway was operating with one Main Feedwater Pump (MFP) when the pump speed unexpectedly lowered to 0 RPM. The pump was manually tripped in response to the condition. This led to a decrease in water level in the steam generators. Operators manually activated the Auxiliary Feedwater System to maintain water level in the steam generators. This system actuation is reportable per 10CFR50.73(a)(2)(iv)(A).

Fault tree analysis and subsequent testing identified the most probable cause for the loss of the 13' MFP is a software defect introduced during the software development process for the digital feedwater control system installed in 2013. However, further investigation and consultation with the software design firm for the control system is required to identify a definitive root cause.

Thus, a supplemental LER will need to be submitted to update the root cause and corrective actions.

05000483/LER-2015-001, Completion of a Shutdown Required by the Technical Specifications - TS 3.4.1317 September 2015Callaway

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.

05000483/LER-2013-0099 December 2013Callaway

On October 9, 2013, during a review of industry operating experience, Callaway Plant Engineering determined an unanalyzed condition exists related to Control Room fire analysis requirements (10 CFR 50 Appendix R). The original plant wiring design and associated analysis for the Class 1E Train B batteries and chargers (including the B swing charger) do not include overcurrent protection features to limit the fault current. It was identified that a postulated fire in the Control Room could cause a ground loop through unprotected (unfused) Direct Current (DC) ammeter wiring and potentially result in excessive current flow and heating to the point of causing a secondary fire outside of the Control Room in cable raceways. The postulated secondary fire could affect safe shutdown equipment and potentially cause the loss of ability to conduct a safe shutdown. This scenario has not been analyzed in accordance with 10 CFR 50 Appendix R, Section III.G. Compensatory fire watch measures have been implemented and remain in place for the affected fire areas in the plant.

The cause is that the original design of the DC ammeter circuits did not include fuses to protect ammeter cables. This design has been in place since construction and has only recently been identified as an issue based on testing sponsored by the NRC in 2011 and reported in NUREG/CR-7100. The NRC has been developing new guidance for addressing hot short issues within the same cable tray. Once this document is available for review, Callaway will determine if the use of Fire PRA is permitted to evaluate the issue and either leave the circuits as built or modify the affected circuits (to provide circuit protection) as necessary.

05000483/LER-2013-00723 July 2013Callaway

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.

05000483/LER-2013-0063 July 2013Callaway

On May 8, 2013, during Refueling Outage 19, water was observed dripping from the insulation on piping connected to Reactor Coolant System (RCS) loop 4. Further investigation determined it was near a 3/4-inch ASME Code Class 2 line upstream of Safety Injection (EP) system valve EPV0109. The 3/4-inch vent line is located on the combined Safety Injection / Residual Heat Removal outlet piping which connects to the cold leg injection piping from Accumulator Tank D.

The RCS leakage identified at the noted location was indicative of degradation of a principal safety barrier and is considered reportable per the requirements of 10 CFR 50.73(a)(2)(ii)(A). Conditions that represent welding or material defects in the primary coolant system which cannot be found acceptable under ASME Section XI standards are reportable to this criterion.

The cracked vent line was removed and repaired on May 10, 2013. The completed weld repair was inspected and found acceptable.

An evaluation concluded that the leak was caused by induced cyclic fatigue crack at the socket weld upstream of valve EPV0109.

The safety significance of this event is low. The RCS leakage that resulted from the cracked vent line was well within the capability of the normal charging pump.

05000483/LER-2013-00417 June 2013Callaway

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)

05000483/LER-2013-00217 June 2013Callaway

On 2/13/2013, during surveillance testing of the 'B' Train of the ESW system, an Operations Technician noticed that the oil in the sight glass of the lower motor radial bearing appeared darker than normal. Based on analysis of the oil, the 'IV ESW pump was declared inoperable on 2/14/2013 at 0721. Required Action A.1 of TS 3.7.8 was entered. Following replacement of the pump motor due to evidence of a degraded bearing, the 'W ESW train was restored to operable status at 1345 on 2/16/2013 such that Required Action A.1 was exited after a period of 54 hours and 24 minutes. Based on a conservative evaluation of past operability, it is estimated that the 'B' ESW pump motor would not have been capable of meeting its Operability mission time of 30 days after the August to October 2012 timeframe; therefore, this condition is currently considered reportable. This determination is based on the presence of metallic contaminants found in the oil and on recently increased motor vibration, which are indicative of bearing degradation.

The direct cause is insufficient motor shaft endplay, resulting in lower bearing failure due to excessive axial loading.

Corrective actions include establishing new preventive maintenance overhaul requirements and establishing new motor shaft endplay settings.

NRC FORM 356 (10-2010)

05000483/LER-2013-0053 June 2013Callaway

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.

05000483/LER-2013-00115 February 2013Callaway

On 14:35 on 12/17/2012, the A Class lE electrical equipment air conditioning unit (SGKO5A) was declared inoperable due to identification of Freon leakage from the unit's low oil pressure and compressor discharge sensing lines. Following repair to address the leakage, the unit was declared operable at 11:08 on 12/18/2012.

The SGKO5A unit provides a support function for the A train of Class lE electrical equipment. The Class lE electrical equipment is addressed in the plant's Technical Specifications. Since the leakage for SGKO5A had apparently existed prior to the time of discovery, it was concluded that SGKO5A and the supported Class 1E electrical equipment had been inoperable for a period of time longer than the allowed by the plant Technical Specifications.

The leakage was the result of two sensing lines rubbing together. The Root Cause was determined to be an inadequate scope of previously conducted equipment reliability evaluations on the HVAC system. The leaks were repaired. In addition, preventive maintenance and monitoring of vibration-susceptible Class lE electrical equipment air-conditioners will be increased.

05000483/LER-2010-00430 April 2010Callaway

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.

05000483/LER-2010-00220 April 2010Callaway

On 2/19/10, upon review of industry operating experience, Callaway Plant identified a condition in which the actuation logic for anticipatory start of the Motor-Driven Auxiliary Feedwater (AFW) pumps upon trip of both Main Feedwater (MFW) pumps would not be satisfied as required by Table 3.3.2-1 Function 6.g of the Technical Specifications (TS).

This condition exists when one MFW pump (MFP) is operating and the second MFP in secured in a 'Reset' configuration.

Low pressure on the MFP Turbine Trip Oil Header is used to indicate a MFP trip. However, the Trip Oil Header is also used to keep the 'Reset' MFP turbine stop valves open such that the Trip Oil Header pressure of a 'Reset' MFP is the same as an operating MFP that is providing flow to the steam generators. As a result, all MFW flow would be lost upon the trip of the operating MFP, but the actuation logic for anticipatory start of AFW upon trip of both MFPs would not be satisfied.

The cause of this event has been identified as a lack of detailed design basis information regarding this function.

Corrective actions include TS to allow both channels associated with a 'Reset' MFP turbine to be placed in a tripped condition (enabling the AFW actuation logic to be satisfied as required upon trip of the operating MFP) and the addition of information related to this function into licensing documents and procedures.

05000483/LER-2008-0076 February 2009Callaway

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.

05000483/LER-2008-00523 December 2008Callaway

On 11/11/2008, while operating at 97-percent reactor power, with power increasing following Refuel 16, the "B" main feedwater pump (MFP) turbine tripped. Since the loss of one MFP at greater than 80-percent power challenges the plant's ability to maintain steam generator (SG) water levels to support continued plant operations, the reactor was manually tripped per plant operating procedures.

All control rods fully inserted during the event and all safety systems responded as designed. Operation of the Auxiliary Feedwater system restored SG levels. Operation of the main steam supply system provided the heat sink for decay heat removal following shutdown. No primary relief valves or main steam relief valves lifted during the event. No primary to secondary leakage existed. No radioactive material was released. This event was considered an uncomplicated reactor trip.

The cause was that the o-rings in the MFP lube.oil strainer were a material susceptible to swelling in petroleum- based lubrication systems. An o-ring originally located in one of the MFP lube oil basket strainers swelled, became dislodged, and traveled into a MFP turbine bearing oil supply pressure regulating valve. The corrective actions to prevent recurrence included identification of a replacement for the o-rings. The correct o-rings were installed in both strainers for the "A" and "B" MFP turbine oil system.

05000483/LER-2007-00330 August 2007Callaway

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.

05000483/LER-2006-00926 January 2007CallawayPrior to June 2006 Callaway Plant Technical Specification 3.7.2 did not explicitly address Main Steam Isolation Valve actuator trains. Inoperability of actuator trains was addressed through a Technical Specification Interpretation, which specified that due to the redundant actuator design, inoperability of a single actuator train did not render the associated isolation valve inoperable. The interpretation was eventually incorporated into Chapter 16 of the Final Safety Analysis Report and applied to the failure of a single actuator train on December 29, 2004. The NRC questioned the use of this provision and took the position that Main Steam Isolation Valve Technical Specification 3.7.2 requirements should have been imposed. The issue was identified as an Unresolved Item for which NRC Office of Nuclear Reactor Regulation involvement was required. Prior to NRC resolution, Callaway Plant determined that Technical Specification 3.7.2 was inadequate. In May 2005, a license amendment request was submitted to explicitly include requirements for the actuator trains under Technical Specification 3.7.2. The NRC approved and issued the amendment request in June 2006. Following issuance of the license amendment, the ongoing NRC evaluation reached resolution in October 2006. The NRC concluded that the requirements of Technical Specification 3.7.2 were inadequately applied prior to the license amendment and should have been imposed for past instances of actuator train inoperability.
05000483/LER-2006-00410 August 2006Callaway

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.

05000483/LER-2004-0049 April 2004Callaway

At 2258, 2/11/04, with the plant in Mode 3, a Safety Injection (SI) occurred while performing a plant heat up to normal reactor coolant system operating pressure and temperature. The SI was the result of not performing a step contained in the procedure governing a plant heat up. All safety systems actuated as required and flow was initiated to the core due to plant conditions present at the start of the event. Emergency procedures were used to terminate the event and restore the plant to a normal condition. During the event, "B" Steam Generator Auxiliary Steam Dump (S/G ASD) did not properly operate and "A" Reactor Coolant Pump (RCP) exhibited high vibration. The "B" S/G ASD problem was identified as an obstruction of a balance arm within an electropneumatic transducer which was corrected and tested to verify operability. The RCP vibration was determined to be the result of thermal transients caused by the SI and did not require additional action.

A Root Cause Analysis investigation was conducted which revealed inadequate pre-job briefs, weaknesses in supervisory oversight, and cumbersome operating procedures as root causes for this event.

05000483/LER-2004-0059 April 2004Callaway

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.

05000483/LER-2004-0032 April 2004Callaway

At 0439, 2/3/04, with Callaway Plant at 100 percent power, a reactor trip occurred while operating breakers in the site distribution switchyard. Plant operators responded to the event using plant procedures and stabilized the plant in Mode 3. All safety systems initially responded as required to the event. Investigations determined a faulted timer relay in the dead machine protection circuit for the main generator caused a trip of the main generator output breakers and subsequent reactor trip.

3 hours 17 minutes after the trip, the Turbine Driven Auxiliary Feedwater Pump (TDAFP) tripped. Extensive methodical investigation resulted in replacement of three components in the control system, and the TDAFP was declared operable.

Due to the complexity of the TDAFP investigation, an emergency one-time change to Technical Specification 3.7.5 was requested and approved.

The failed timer relay in the dead machine circuit, and the three suspect control system components were all replaced and both pieces of equipment were returned to service.

05000483/LER-2003-00618 March 2004Callaway

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.

05000483/LER-2003-00521 July 2003Callaway

On 5/22/03, with Callaway Plant in Mode 1 at 100 percent power, surveillance testing was being performed involving "B" Containment Spray pump, PENO1B. Upon starting, the pump failed to develop normal discharge pressure and flow for approximately 5 minutes. The pump then developed pressure and the test was completed satisfactorily. Subsequent review determined the pump had been gas bound. Ultrasonic exams and dynamic venting demonstrated that PENO1B was water solid and operable. An extent of condition review revealed that Containment Spray pump, PENO IA had experienced a 2 minute gas binding event on 4/29/03. Ultrasonic exams and venting were conducted and verified that PENO IA was operable. It was determined that both pumps were gas bound due to an inadequate system venting configuration after Mode 5 valve testing on 3/30/03 resulting in both trains of Containment Spray being inoperable upon entering Mode 4 on 3/31/03 until PENO IA was run on 4/29/03, and "A" train was declared operable. This resulted in noncompliance with Technical Specification 3.6.6 for a period of time greater than allowed. Potential corrective actions being evaluated include installing additional vent valves, and procedure improvements to address dynamic venting.

05000483/LER-2003-0049 June 2003Callaway

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.

05000483/LER-2003-0025 May 2003Callaway

At 0148, 3/5/03, EGHVO061 was declared inoperable due to failing to stroke full closed during containment integrity surveillance, 5704626. Technical Specification (T/S) 3.6.3 was entered and EOSL 10582 was written to track T/S time limits.

EGHVO061 is a parallel sliding gate valve. Investigation revealed the valve failed to stroke to the full close position due to a hydraulic lock developing between the two valve discs. This was a repeat of a problem on 1/8/03. Actions taken in January involved valve disassembly and removal of a viscous film discovered on all areas where a no flow or low flow condition existed.

Post maintenance testing indicated that cleaning resolved the problem. This was supported by testing performed under 5539676 on 2/5/03.

Upon the second failure of EGHVO061, further investigations were conducted. Manufacturer Velan Valve Corporation recommended drilling a 0.25-inch hole in the upstream disc to relieve any pressure trapped between the discs. This modification was performed and testing demonstrated proper operation and stroke times. At 1418, 3/7/03, EGHVO061 was declared operable. This failure was caused by changing valve stroke length in RF12. The actual inoperable time span was from the last valve stroke in RF12 at 2116, 11/17/02, until proper restoration was completed at 1418, 3/7/03 for a total time span of 109 days, 17 hours, 2 minutes.

05000483/LER-2002-00412 April 2002Callaway

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.

05000483/LER-2002-00512 April 2002CallawayOn 2/18/02, Callaway Plant received Westinghouse Letter SCP-02-14, which transmitted Nuclear Safety Advisory Letter (NSAL) 02-03. This NSAL addressed an error in the Westinghouse Steam Generator (S/G) water level setpoint analysis in which the pressure drop across a mid-deck plate internal to the S/G separator assembly was not accounted for in analysis calculations. This pressure drop adversely affected S/G low-low setpoint uncertainty calculations. On 2/28/02, Callaway staff engineers determined that this situation was applicable to Callaway with the S/G low-low setpoints being nonconservative and that the S/G Low-Low Trip function might not provide protection against a Main Feed Line Break (MFLB) inside Containment. A decision was made to reduce reactor power to approximately 30 percent and adjust the S/G Low-Low Trip setpoints to 21.6 percent narrow range level for normal containment environment and 27 percent narrow range level for adverse containment environment, which would satisfy the safety analysis requirements. Additional corrective actions included revision of plant procedures utilizing the S/G Low-Low Trip values.