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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.

On 4/18/2002, during an extent of condition review concerning the neutron flux positive rate trip function, a concern was identified where Technical Specification (T/S) Table 3.3.2-1, Allowable Value for the Steam Line Pressure Negative Rate - High (HNPR), is less restrictive than the Safety Analyses Limit (SAL) credited in the Callaway Mode 3 Main Steam Line Break (MSLB) analysis.

T/S lists the allowable value for the HNPR function as less than or equal to 124 psi. T/S Bases lists the Nominal Trip Setpoint (NTS) for the HNPR function as less than or equal to 100 psi. The Safety Analysis Limit (SAL) for the HNPR function is 100 psi.

Consequently, the current T/S allows the HNPR function to be set at a value less conservative than the value assumed in the safety analysis.

Corrective actions being evaluated include either decreasing the T/S Allowable Value from less than or equal to 124 psi to less than or equal to 100 psi, or revising the Callaway Mode 3 MSLB analysis to credit a HNPR SAL greater than or equal to 124 psi.

Because the plant was operating in Mode 1, there were no immediate operability concerns. A Generic Letter 91-18 Operability Determination was completed which included the required compensatory actions for T/S compliance if the plant is taken to Mode 3 with reactor coolant system pressure below the P-I I setpoint of 1970 psig.

At 1419 CST, 11/5/02, in Event Notification # 39345, Callaway reported the following:

"During refueling outage RF12, interim results of "A" Steam Generator tube inspections indicate 62 tubes out of 5431 tubes (i.e., > 1%) have been found to be defective. This steam generator tube inspection result for the "A" Steam Generator is classified as category C-3 in accordance with Technical Specification 5.5.9, Table 5.5.9-2. All defective tubes will be plugged before the steam generator is returned to service. There were no adverse safety consequences or implications as a result of this event. This event did not adversely affect the safe operation of the plant or the health and safety of the public. " This initial notification was reported under 10CFR50.72(b)(3)(ii)(A) as a Degraded Condition, however, under NUREG 1022, section 3.2.4, discussion (A) 3, the present C-3 classification of the "A" Steam Generator (S/G) tubes does not meet the listed criteria for serious S/G tube degradation. The initial notification was amended to reflect that the report was made per requirements of Technical Specification (T/S) 5.5.9, Table 5.5.9-2 only. The C-3 condition does not meet the criteria for serious S/G tube degradation and is not a degraded or unanalyzed condition. This LER is submitted in compliance with T/S requirements, not due to an actual serious S/G tube degradation.

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.

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.

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 9/4/03 with Callaway in Made 1 at 100 percent power, a modification to replace the handswitch for "IT Pressurizer (Pzr) Power Operated Relief Valve Block valve (BBHV8000B) was implemented. During post modification testing, the valve operator and control breaker were damaged. The modification required removal of a wire which had not been specified by the modification work instructions. Repairs were performed and the valve control circuitry was restored to pre-modification conditions. The reportable condition occurred 9/7/03 when the Technical Specification Required Actions were not met within the associated Completion Time. interim corrective actions restrict planning of motor operated valve control circuit work documents. Long term corrective actions include strengthening the training and qualification process for the planning of motor operated valve modification work documents.

NRC FORM W6(7-2001) DOCKET (2) LER NUMBER (6) Callaway Plant Unit 'I FACILITY NAME (1)

At 1830, 1/27/04, while at 100 percent power, Callaway Plant experienced a main electrical generator trip which in turn caused a reactor trip due to power being above 50 percent. The cause of the generator trip was a failed electrical relay.

This relay was designed to sense remote faults in order to prevent exceeding thermal limits for the stator windings. Plant systems responded as designed, including automatic actuation of the auxiliary feedwater system.

The faulted relay was repaired, calibrated, and reinstalled. This relay contained a second set of unused contacts which were used instead of the initial faulted contacts. This relay configuration was successfully retested and plant operation resumed without further problems.

A review of relevant operating experience did not identify similar failures, and a review of past plant preventative maintenance did not reveal abnormalities. Preventive maintenance procedures will be revised to provide additional detailed instructions for inspection of these relay contacts for this failure mechanism.

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.

At 0300, 3/23/05, 72-hour Technical Specification Action 3.7.8.A was entered when a pinhole leak was discovered in "B" Essential Service Water (ESW) system between the "B" ESW pump strainer and discharge isolation valve. Subsequent ultrasonic testing (UT) determined that approximately seven linear feet of piping in the "B" ESW train was affected and required replacement. UT testing was satisfactorily performed on the identical section of "A" ESW train to ensure a similar problem did not exist.

"B" ESW train piping replacement was performed in accordance with planned work documents, however at 2100, 3/25/05 all necessary repairs and retests had not been completed. Although only 66 hours had expired since entering 72-hour Technical Specification Action 3.7.8.A, Callaway Plant proactively decided to commence a reactor plant shutdown in accordance with Technical Specification Action 3.7.8.B for an Inoperable "B" Essential Service Water train.

At 0624, 3/26/05 the reactor was declared shutdown and Callaway Plant entered Mode 3. At 0249, 3127/05 all repairs and retests were completed on the "B" ESW train and it was declared Operable. Instead of beginning a return to operation, plant management decided to perform additional discretionary work to enhance unit reliability and as a result, Callaway did not return to power until 1907, 4/2/05.

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.

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 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.

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.

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.

On 3/23/2013, the filtration fan associated with train 'B' of the Control Room Emergency Ventilation System (CREVS) tripped on thermal overload during restoration from surveillance testing. This occurred approximately 22 minutes after the fan was started. Based on this trip, the CREVS 'B' train was declared inoperable on 3/23/2013 at 2243. Required Action A of TS 3.7.10 was entered, and following replacement of the motor starter, the CREVS 'B' train was restored to operable status on 3/26/2013 at 0659.

Due to evidence of a loose connection and arcing at the termination for the 'C' phase of the filtration fan's starter, it was determined from this as-found condition that the CREVS 'B' train would not have been capable of meeting its Operability mission time of 30 days after 2/11/2013; therefore, this condition is considered reportable. This determination is based on the conclusion that the connection loosened slowly over time. A successful run of the fan on 2/11/2013 (without tripping) indicates that as of 2/11/2013, the connection had not loosened sufficiently to trip the fan on thermal overload.

The most probable cause of failure is tripping on thermal overload, due to a high resistance connection on the fan's starter.

Preliminary corrective actions include periodically checking the tightness of termination screws and inspecting for signs of overheating, for similar starters.

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 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.