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Between 4/21/2016 and 11/2/2017, containment check valve internal assembly (i.e. hanger / for penetration P-67. The containment isolation penetration P-67, during the time KCV0478 The valve was found in the fully open position the Local Leak Rate Test (LLRT). The valve flow test conducted on 4/21/2016 during Refuel in Modes 1 through 4. In this case, it was not on 5/5/2016. Therefore, a condition prohibited Required Actions specified in the TS for an inoperable The root cause of the valve inoperability was supplied internal assembly (i.e. hanger / disc) new design utilizing corrosion resistant materials.

appears known dimensional typewritten lines) isolation valve This check integrity function inoperable.

10/31/2017 to have 21. Technical that the by TS 3.6.3 subsequently CIV.

KCV0478.

functioning valve (CIV) for pressurize for system Mode 4 the in the vendor with a comments regarding burden estimate to the Information Services Branch (T-2 F43), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to Infocollects Resource@nrc gov. and to the Desk Officer. Office of Information and Regulatory Affairs, NEOB-10202. (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection ' YEAR Callaway Plant Unit 1 05000-483 NUMBER NO 2017 I 003 000

1. DESCRIPTION OF STRUCTURE(S), SYSTEM(S) AND COMPONENT(S):

The issue addressed in this LER concerns the failure of a normally closed check valve that serves as a containment isolation valve (CIV) (EIIS System: JM, Component: ISV). The affected valve is situated in a fire protection line (EIIS System: KP) that penetrates containment at penetration P-67 and runs to hose racks / sprinkler inside containment. The containment isolation provisions for this line consist of CIVs inside and outside containment, consistent with the requirements of General Design Criterion (GDC) 56.

In general, the containment isolation valves form part of the containment pressure boundary and provide a means for fluid penetration flow paths not serving accident consequence limiting systems to be provided with two isolation barriers that are closed on a containment isolation signal. These isolation devices are either passive or active (automatic). Manual valves, de-activated automatic valves secured in their closed position (including check valves with flow through the valve secured), blind flanges, and closed systems are considered passive devices. Check valves, or other automatic valves designed to close without operator action following an accident, are considered active devices.

Two barriers in series are provided for each penetration flow path so that no single credible failure or malfunction of an active component can result in a loss of isolation or inleakage that exceeds limits assumed in the safety analyses. The Limiting Condition for Operation (LCO) of TS 3.6.3, "Containment Isolation Valves," applies to CIVs and was derived from the assumptions related to minimizing the loss of reactor coolant inventory and establishing the containment boundary during a design basis accident (DBA).

TS operability requirements for the CIVs support assumptions in the safety analysis of any event requiring isolation of containment. The DBAs that result in a release of radioactive material within containment are a loss of coolant accident (LOCA) and a rod ejection accident. In the analyses for each of these accidents, it is assumed that CIVs are either closed or function to close within the required isolation time following event initiation. This ensures that potential paths to the environment through CIVs (including containment shutdown purge and mini-purge valves) are minimized.

KCV0478 AND ASSOCIATED PIPING GENERAL OVERVIEW The Reactor Building Fire Protection (FP) water supply is provided by a single 4-inch line that passes through containment penetration P-67. The FP system inside the Reactor Building consists of stand pipes, hose racks and two sprinkler systems (one for each of the Reactor Building cable penetration areas on Elevation 2026').

The configuration of Penetration P-67 consists of a motor-operated, automatic isolation valve outside containment, KCHVO253, and a check valve inside containment, KCV0478, which complies with 10 CFR 50 Appendix A GDC-56, "Primary Containment Isolation," for lines that penetrate containment and connect directly to the containment atmosphere.

The P-67 piping is ASME III Class 2, 150 PSI, carbon steel schedule 40 piping. The valves are ASME Ill Class 2, 150 PSI. Both the piping and valves are seismic Category 1.

Valve KCHVO253 is positioned closed during normal and shutdown plant modes, and is designed to fail in the "as is" position. It is normally operated remotely from a hand switch in the Control Room. The valve can also be manually operated at the valve. The valve is opened only during local leak rate tests (LLRTs), during quarterly stroke testing, and if the FP system is called upon to mitigate a fire inside containment. Valve KCHVO253 also closes automatically on a containment isolation signal to minimize the release of fission products following an accident.

comments regarding burden estimate to the Information Services Branch (T-2 F43), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection iLy .1; The administrative containment leakage limit for penetration P-67 is 9,000 standard cubic centimeters per minute (sccm) for KCHVO253 and KCV0478. When KCHVO253 is opened for LLRTs or stroke testing, the upstream manual isolation valves are closed to maintain the Reactor Building FP piping in a dry condition.

FE AC TOP AUXILIARY

i KCV04 r 3 I I__I KCV04?8 BUILDING BUILDING Figure 1 - Containment Penetration P-67 Diagram KCV0478 Valve Design:

KCV0478 is an ASME Ill Class 2, safety related, swing style check valve. The valve was supplied by Velan Engineering Companies.

Figure 2 - KCV0478 Design Drawing Side View (M-223C-00021) comments regarding burden estimate to the Information Services Branch (T-2 F43). U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001. or by e-mail to Infocollects Resource@nrc.gov. and to the Desk Officer, Office of Information and Regulatory Affairs, NEOB-10202. (3150-0104). Office of Management and Budget, Washington, DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information cofiecfion The major internal components of valve KCV0478 consist of a disc and hanger which are attached to the valve body. The valve is designed to open with fire water flow from the fire header to the associated containment building hose racks / sprinkler and to close or be closed in the event of increased containment pressure that may occur in an accident in containment. The valve body is carbon steel, and the hanger and disc assembly are stainless steel. The original valve disc was carbon steel. Due to susceptibility to corrosion and challenges with seat leakage during LLRT testing, the disc was replaced with a stainless steel disc in 1999 (Refuel 10).

Per discussion with the vendor representative during the root cause investigation for the identified valve failure, it was identified that the dimensions of the disc were too large for the application and had the potential to cause the valve to stick in the open position. In addition, operating experience was documented in which it was identified/inferred or suggested that the tolerances of the hanger assembly could result in the hanger assembly sticking in the open position.

2. INITIAL PLANT CONDITIONS:

When the LLRT was performed for KCV0478 on October 28, 2017, Callaway Plant was in its Refuel 22 outage. The reactor fuel had been removed from the reactor vessel and placed in the spent fuel pool in the fuel building where cooling was provided by the spent fuel pool cooling system. The plant had shut down for the refueling outage on 10/7/2017. The LLRT on KCV0478 was performed as part of the normally scheduled surveillance for containment isolation valves.

3. EVENT DESCRIPTION:

On October 28, 2017, during Refuel Outage 22, test pressure could not be obtained during the KCV0478 as-found LLRT for containment penetration P-67. Subsequently, on October 31, 2017, during internal inspection of KCV0478, the internal valve disc / hanger assembly was found to be stuck in the fully open position. Upon removal, the valve hanger / disc assembly was inspected for damage and any possible sign of cause. No issues were reported with the hanger / disc assembly, as it was verified to move freely with no discernable damage.

The internal surface of the valve body was cleaned to remove corrosion products. Upon reinstallation of the hanger / disc assembly into KCV0478, the valve internal assembly was stroked / actuated several times manually (with a hanger connected to the valve hanger). After verification of freedom of movement, and hanger / disc measurements, the valve was reassembled. All post maintenance testing (external leak test and LLRT) was completed successfully with satisfactory results.

Prior to finding KCV0478 stuck open on October 31, 2017, the last time KCV0478 was verified to be in the closed position was in RF21 during performance of a LLRT on April 18, 2016. Soon after this LLRT, records show that a flow test of the fire water header to containment was performed on April 22, 2016 via containment penetration P-67 and KCV0478. This test provided sufficient flow to take the valve to its fully open position. Based upon the identification of no other testing, operational line-ups or system transients associated with P-67 or KCV0478 that could have fully opened the valve, prior to Refuel Outage 22, it is likely that KCV0478 was fully open for the entirety of Cycle 22.

As a result of KCV0478 potentially being in the fully open position since the fire protection system flow test on April 22, 2016, it was identified that KCV0478 should have been declared inoperable (incapable of supporting its containment isolation safety function) and that the applicable Conditions and Required Actions under TS 3.6.3 should have been entered. Without knowledge of the condition of the valve, entry into the applicable Conditions and Required Actions under TS 3.6.3 was missed, resulting in a reportable condition.

Infocollects.Resource@nrc goy, and to the Desk Officer, Office of Information and Regulatory Affairs, used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection

• i..21F Callaway Plant Unit 1 05000-483

4. ASSESSMENT OF SAFETY CONSEQUENCES:

2017 003 000 With KCV0478 in a fully open position, the containment isolation function is adversely impacted. As discussed previously, KCV0478 is one of three valves associated with P-67 (i.e., in addition to KCHVO253 and KCV0431). In this case, it was not known that KCV0478 was in fully open position when the plant entered Mode 4 on 5/5/2016. In addition to the mode change with an inoperable CIV, the TS Required Action to isolate the affected penetration flow path by use of at least one closed and de-activated automatic valve (within 1 hour), was not met (as explained further below). Therefore, the event is reportable under 10 CFR 50.73(a)(2)(i)(B), i.e., for an operation or condition prohibited by the plant's Technical Specifications. An LER is consequently required.

Despite the inoperability of KCV0478 for an extended period of time, the event is not considered to be a degraded or unanalyzed condition that significantly affected plant safety per 10 CFR 50.73(a)(2)(ii) since the containment isolation/integrity function was maintained by KCHVO253, the outer containment isolation valve for penetration P-67. The total containment "as-found" minimum pathway leak rate remained within the limits of TS 3.6.1 during the timeframe when KCV0478 was inoperable, and for this reason, the event/condition was of low safety significance.

5. REPORTING REQUIREMENTS:

This LER is submitted pursuant to 10 CFR 50.73(a)(2)(i)(B) to report a condition prohibited by Technical Specifications.

Specifically, with KCV0478 inoperable, Condition A of TS 3.6.3 would have been required to be entered. This Condition is applicable to penetration flow paths having two containment isolation valves (which is the case for P-67 and its associated penetration flow paths, particularly the KCV0478-KCHVO253 penetration flow path). Per Condition A, for one or more penetration flow paths with one containment isolation valve inoperable, Required Actions A.1 and A.2 must be entered. Required Action A.1 requires isolating the affected penetration flow path by use of at least one de-activated automatic valve, closed manual valve, blind flange, or check valve with flow secured through the valve, within a specified Completion Time of 4 hours. Required A.2 requires verifying that the affected penetration flow path is isolated within a specified Completion Time of 31 days (for isolation devices outside containment). With either (or both) of these Completion Times and Required Actions not met, Condition E applies and its Required Actions E.1 and E.3 become applicable. These Required Actions require the plant to be shut down such that per Required Action E.1, the plant must be in Mode 3 within 6 hours, and per Required Action E.2, the plant must be in Mode 5 within 36 hours.

Since KCV0478 was not known to be inoperable when the plant entered the Applicability of LCO 3.6.3 upon restart from Refuel 21 (assuming the condition existed at the time), the above-noted Conditions and Required Actions were not entered and thus not met. Compliance with Required Action A.1, in particular, would have required CIV KCHVO253 to be closed and deactivated within 4 hours. With Required Action A.1 not met within 4 hours, the plant would have been required to be in Mode 3 within the following 6 hours per Required Action E.1, and in Mode 5 within 36 hours.

It may also be noted that a violation of LCO 3.0.4.a occurred in connection with the plant entering the Applicability of LCO 3.6.3, with the assumed valve inoperability. With an LCO not met, LCO 3.0.4.a only permits entry into the Applicability of that LCO when the associated Actions to be entered permit continued operation in the applicable Mode for an unlimited period of time. This provision would only have been met if Required Actions A.1 and A.2 of LCO 3.6.3 had been met.

comments regarding burden estimate to the Information Services Branch (T-2 F43), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to Infocollects Resource@nrc.gov, and to the Desk Officer, Office of Information and Regulatory Affairs, NEOB-10202, (3150-0104). Office of Management and Budget, Washington, DC 20503 If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

Callaway Plant Unit 1 05000-483 NUMBER NO

6. CAUSE OF THE EVENT:

The reported condition is the result of dimensional interferences due to inadequate design clearances in the vendor supplied internal assembly (i.e. hanger / disc) for KCV0478. The inadequate design clearances resulted in excessive (i.e.

outside of approved design) contact of the KCV0478 internal assembly with the valve body.

7. CORRECTIVE ACTIONS:

The immediate corrective action was to clean the valve, disc, and hanger assembly and successfully re-perform the LLRT. The planned corrective action to prevent recurrence (CAPR) is to replace check valve KCV0478 with a new design utilizing corrosion resistant materials (e.g. stainless steel). Critical dimensions are to be requested and obtained from the vendor for the new valve and they will be incorporated into applicable work instructions to be used for verification of proper design clearances during initial inspection/installation and future maintenance on KCV0478.

The following actions are being taken to ensure the issue does not re-occur until the above CAPR is complete.

a) Revise FP full-flow preventive maintenance (PM) test to include a task to perform a post-test LLRT.

b) Generate new PM to clean check valve KCV0478 every outage.

c) Install or verify the stainless steel disc is still within the vendor provided dimensions in KCV0478 in RF23.

d) Inspect the KCV0478 hanger in the installed configuration to ensure no dimensional interference exists between the hanger stop and valve body. If contact is identified that could impact valve closure, adjust / modify hanger or valve body to ensure KCV0478 internal assembly on the hanger stop is not susceptible to binding and/or the valve will freely move in the open/closed direction as designed.

e) Administrative controls are in place to ensure the actions of TS 3.6.3 are taken for penetration P-67 if water is flowed through KCV0478. This will ensure the penetration is isolated and compliance with TS 3.6.3 actions are met.

8. PREVIOUS SIMILAR EVENTS:

Based upon a review of available internal OE, Callaway had an opportunity to address the condition identified with KCV0478 in Refuel 10 (1999) when the valve internal assembly stuck after replacing the disc assembly. Actions were taken that verified successful operation of the valve in the closed / open direction. However, the cause of the event was not fully understood, and as a result, the issue was not fully addressed, thus leading to recurrence of this issue.

opening a normally closed containment isolation valve was identified. While the LER is associated with the same TS, the cause is completely unrelated and the corrective actions taken would not have prevented the KCV0478 event.

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.

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.

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.

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 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.

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 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 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 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 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 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.

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.

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.

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 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.

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)

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.

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.

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.