|Report date||Site||Event description|
|05000318/LER-2017-001||19 April 2017||Calvert Cliffs||During scheduled testing at the offsite testing facility, the as-found lift setting for the pressurizer safety valve previously installed in Unit 2 at the 2RV200 location was measured outside the Technical Specification allowable values (valve lifted low). The valve had been installed during the 2015 Unit 2 refueling outage and was removed during the 2017 Unit 2 refueling outage for scheduled testing and maintenance. As scheduled, a spare valve was installed during the 2017 refueling outage. The failed valve was disassembled and inspected at the offsite facility. The apparent cause of the pressurizer safety valve failure is due to setpoint drift. The valve was successfully re-certified for use at the plant in a future installation. Setpoint setting criteria were adjusted based on more recent operating experience (setpoint drifting low).|
|05000318/LER-2016-001||24 January 2017||Calvert Cliffs||On December 3, 2016, Operations was conducting a Performance Evaluation of the auto start feature of Unit 2 Main Turbine Electro-Hydraulic Control (EHC) Pumps. At 2223, the standby Main Turbine tripped automatically which was followed by an automatic reactor protection system trip. The Main Turbine tripped on a Main Generator Directional Power Relay trip following the closure of all Unit 2 Main Turbine Governor Valves and Intercept Valves. This was due to an EHC leak on 21 Main Turbine Governor Valve Actuator Emergency Trip Fluid Check Valve which caused a rapid decrease in EHC header pressure. The trip was an uncomplicated reactor trip as all safety functions performed as expected. The failed emergency trip fluid check valve was sent off site to a lab for forensic investigation. This analysis determined the check valve failed due to Inter Granular Stress Corrosion Cracking (IGSCC). The most likely cause of the IGSCC on this check valve was exposure to ammonia during some previous maintenance activity. Corrective actions include replacement of all similar Unit 2 EHC valves during the 2017 refueling outage and establishment of a preventive maintenance strategy to periodically replace similar EHC valves. Unit 2 was returned to full power at 1647 on December 5, 2016.|
|05000317/LER-2016-003||29 July 2016||Calvert Cliffs|
On May 31, 2016 at 1626, Calvert Cliffs Unit 1 experienced an automatic reactor trip. The cause of the trip was a spurious high level steam generator signal due to a failed Steam Generator 11 Channel B High Level Turbine Trip Under Voltage Logic Module, 12/4BL-XA27.
The spurious high level trip signal resulted in a turbine trip followed by an automatic reactor protection system trip on loss of load. The failed under voltage logic module was sent off-site to the vendor to conduct a failure analysis. The analysis identified two most probable causes for the failure. The first most probable cause was due to an intermittent failure of an integrated circuit of the under voltage logic module. The second most probable cause was due to an inadvertent solder bridge between a pin on the integrated circuit chip and the board. A refurbished logic module was installed and subsequently tested prior to the unit returning to power. The corrective action planned to prevent recurrence is to replace the current Engineered Safety Features Actuation System (which includes the non-safety high level turbine trip) with a system that will eliminate single point vulnerabilities within this system.
|05000317/LER-2016-004||20 July 2016||Calvert Cliffs|
The Unit 1 Service Water (SRW) Room high energy line break (HELB) door was opened on 10/19/2015 and 10/21/2015 to conduct a maintenance activity. The door was opened twice for approximately three and a half minutes each time. With the HELB door blocked open, the affected equipment located behind the barrier door should have been considered inoperable.
Affected equipment included the 13 motor driven auxiliary feedwater pump, both trains of saltwater air compressors and both trains of SRW. Since both SRW trains were inoperable, a loss of safety function occurred, an unanalyzed condition existed and a common cause failure of independent trains existed for the time that the HELB door was opened. The HELB door was blocked opened because Maintenance Planners did not include the proper barrier controls in the work order that opened the HELB door, because they were unaware of the barrier control procedure requirements. The apparent cause of the event was that the assigned change management agent (an Engineer) failed to inform Maintenance Planners of the implementation of the barrier procedure. Affected groups were briefed about the barrier control procedure.
Corrective action for the human performance issue was handled through the performance management system.
|05000317/LER-2016-002||14 April 2016||Calvert Cliffs|
On February 20, 2016, during Calvert Cliffs Inservice Inspections of Unit 1 dissimilar metal welds, an evaluation of recorded ultrasonic examination (UT) data identified the presence of one axially oriented flaw in a 4 inch Unit 1 pressurizer (PZR) safety relief nozzle (NZL) to safe end weld. The indicated flaw exhibited characteristics indicative of primary water stress corrosion cracking (PWSCC). The flaw was inner diameter connected and measured 81.6 percent through-wall. This measured axial flaw depth did not meet the American Society of Mechanical Engineers (ASME) Code allowable limit. The UT of this weld done in 2006 and 2010 had determined the axial flaw depth was only approximately 8 percent through-wall. After re-analysis of the prior UT data, the root cause was determined to be limitations in sizing data collection and analysis techniques prior to 2016 that were unable to connect the detected inner .
diameter indication to the full through-wall extent of ultrasonic signal response of the flaw. The weld was repaired using a full structural weld overlay repair method using PWSCC resistant material deposited around the circumference of the weld area. Two other Unit 1 welds that had previously shown potential PWSCC were examined with the new techniques and showed no change in their indication characteristics and remain within ASME Code allowable limits.
|05000318/LER-2015-001||28 March 2016||Calvert Cliffs||On December 1, 2015 at 1820, Unit 2 turbine driven 22 Steam Generator Feed Pump (SGFP) tripped. Operations attempted to reset 22 SGFP unsuccessfully. Facing lowering steam generator water level, Operations manually initiated a reactor trip. It was determined that 22 SGFP tripped due to a failed coupling. This occurred because excessive misalignment developed between the pump and turbine due to insufficient tensioning of the pump's casing to pedestal studs thus causing 22 SGFP coupling to fail. Investigation determined that the vender supplied stud tensioning values used in tensioning the hold down studs on both Unit 2 SGFPs during the 2015 refueling outage were incorrect and resulted in insufficient clamping force being applied to all the studs. The root cause of the failure was that Engineering personnel failed to address the full scope and critical parameters associated with use of a different tool for installation of studs in lieu of capscrews for 22 SGFP. The coupling for 22 SGFP was replaced and 22 SGFP was realigned. Corrected tensioning values were then applied to all the hold down studs on 21 and 22 SGFPs. Corrective actions include briefings to applicable groups on adherence to procedure requirements for owner's acceptance review of external technical products. Unit 2 was returned to Mode 1 operations at 1326 on December 6, 2015.|
|05000317/LER-2016-001||21 March 2016||Calvert Cliffs||At 0313 on January 25, 2016, Operators initiated a manual reactor trip on Unit 1 due to high levels of sodium in the Feedwater and Condensate systems that exceeded the threshold levels in Abnormal Operating Procedure 10, Abnormal Secondary Chemistry Conditions. Subsequent investigation determined the high sodium levels were due to a condenser tube leak located in 13A Condenser. The failed condenser tube and several adjacent tubes were plugged and refueling outage eddy current testing confirmed a circumferential crack on the failed condenser tube. The apparent cause is that the condenser tube failure was vibration induced. Radial stakes were installed to help limit future vibration. A causal analysis will be completed following the Unit 1 refueling outage.|
|05000317/LER-2015-003||9 November 2015||Calvert Cliffs|
On June 17, 2015 during 1A diesel generator (DG) Surveillance testing, the 1A2 "lube oil differential pressure high" alarm annunciated on both sides of the engine (side A and side B) shortly after DG start. The DG was shut down and declared inoperable. The cause of the alarms was a leaking cylinder liner which allowed coolant (glycol) to contaminate the lube oil and foul the lube oil filters. The cause of the cylinder leak was determined to be damaged 0 rings on the leaking cylinder. The damaged 0 rings were replaced and the 1A DG was satisfactorily tested and returned to Operable status on June 22, 2015. To address the apparent cause of the degraded 0 rings, a process to ensure 0 rings are stored flat to prevent twists was implemented. Because the 1A DG was determined to be inoperable for 32 days, the Required Action Completion Times of Technical Specification 3.8.1.B, C, E, F, and J were not met and this event is reportable as an operation or condition prohibited by Technical Specifications.
This event is also reportable as an event or condition that could have prevented fulfilment of a safety function, because the inoperability of the second Unit 1 DG for 24 minutes resulted in a loss of safety function for emergency power on Unit 1, and the inoperability of the Unit 2 2B DG for 8 minutes resulted in a loss of safety function for the emergency power to the Control Room ventilation system for Units 1 and 2.
|05000317/LER-2015-002||5 June 2015||Calvert Cliffs||On April 7, 2015 at 1239 Calvert Cliffs experienced a dual unit trip due to an off-site grid disturbance resulting in an undervoltage condition that caused all four Engineered Safety Features (ESF) Buses to trip. Due to this condition, all of the emergency diesel generators (EDGs) started and loaded with the exception of 2B EDG which started but tripped due to a failed electronic speed switch in the startup circuitry. The associated 4 kV ESF bus was repowered from the normal power source. Additionally, while 2A EDG energized its respective 4 kV ESF bus, the associated shutdown sequencer failed to start 21 Saltwater pump which was subsequently manually started. Unit 1 tripped on loss of all power to generator excitation and all required safety systems responded as designed. Unit 2 tripped due to generator loss of load and is classified as an unplanned scram with complications as 24 4 kV ESF bus was de-energized for greater than 10 minutes. The failed 2B EDG speed switch and 2A EDG shutdown sequencer were replaced and tested satisfactorily. Future corrective actions include to design and implement a speed switch modification to eliminate the single-point failure risk, and to procure and install a newly manufactured sequencer in each channel.|
|05000318/LER-2014-002||7 August 2014||Calvert Cliffs||On June 9, 2014 at 1735, a 2A diesel generator field flash monitoring relay alarm was received in the Control Room. Investigation revealed no local alarms and no conditions consistent with an alarm condition existed. The Control Room alarm manual was referenced but critical information was missed. Following investigation by the Operations crew, a determination was made that the issue did not impact diesel generator operability based on proper indications and satisfactory status of standby systems for the diesel generator. Troubleshooting on June 11, 2014 determined that a field flash fuse clip was loose, rendering the diesel generator inoperable. Initial Technical Specification Condition 126.96.36.199 which requires one hour Actions, and subsequent Technical Specification Condition 3.8.1.J to be in Mode 3 in six hours was missed due to the late identification of the diesel generator inoperability. The apparent cause of this event is human performance error. Corrective actions include operator training focused on understanding the causes of the degraded condition and validation of indications for potential inoperability and updating specific guidance for diesel generator alarms.|
|05000317/LER-2014-003||24 April 2014||Calvert Cliffs|
During scheduled testing at the offsite testing facility, the as-found lift settings for the pressurizer safety valves (PSVs) previously installed in Unit 1 at the 1RV200 and 1RV201 locations were measured outside the Technical Specification allowable values (both valves lifted low). The valves had been installed during the 2012 Unit 1 refueling outage and were removed during the 2014 Unit 1 refueling outage for scheduled testing and maintenance.
Spare valves were installed during the 2014 refueling outage. The failed valves were disassembled and inspected at the offsite facility. The apparent cause of the PSV failures is that the internal lift spring assemblies of a specific manufacturer lot failed to hold PSV set pressure. This apparent cause will be verified as the removed internal lift spring assemblies for each valve is further reviewed, examined, and tested to support this apparent cause. No other installed PSVs contain internal lift spring assemblies from this specific manufacturer's lot.
|05000317/LER-2014-002||3 April 2014||Calvert Cliffs|
The event was mis-positioning of the Auxiliary Feedwater (AFW) mud leg drain isolation valve (1-MS-225) and the mud leg steam trap bypass valve (1-MS-228) on 2/7/2014. During operator rounds these valves were cycled but were not returned to their closed position. During the performance of a scheduled surveillance test (STP-0-9-1), steam entered the AFW room through the open valves. The affected AFW pumps were determined to be inoperable with steam entering the room. The apparent cause of the event was that the Turbine Building Operators failed to apply human performance tools (procedure use and adherence, and placekeeping) to maintain proper configuration control. Corrective actions were handled through the performance management system and are complete. The AFW train was determined to have been inoperable for 12 hours, 50 minutes. Technical Specification (TS) 188.8.131.52 requires 1 hour Actions with both AFW pumps inoperable. Since the 1 hour Actions were not performed within 1 hour, TS 3.7.3.E should have been entered. It requires that the Unit be placed in Mode 3 in 6 hours, and Mode 4 in 12 hours from entry into the Condition.
Unit 1 was not placed in Mode 3 within 7 hours from the time the steam-driven AFW pumps were made inoperable. Therefore, the condition existed for a time longer than allowed by TSs.
No similar Licensee Event Reports were found.
|05000318/LER-2014-001||20 March 2014||Calvert Cliffs|
On January 21, 2014, at 9:25 p.m., Unit 2 experienced an automatic reactor trip from 99.5 percent power. The reactor trip occurred when 13 kV Service Bus 21 deenergized due to a ground fault on feeder breaker 252-2104. The loss of the service bus caused a loss of power to non-safety-related 4 kV buses, which caused a loss of circulating water pumps and main condenser vacuum, requiring the use of auxiliary feedwater and atmospheric dump valves to maintain Reactor Coolant System temperature. Power was also lost to safety-related 4 kV Bus 24, which caused an automatic start of the 2B Emergency Diesel Generator to power 4 kV Bus 24.
The loss of power to non-safety-related 13 kV Service Bus 21 was caused by water intrusion when an air filter assembly located at the back of breaker 252-2104 cubicle became dislodged during a snow storm, allowing snow to enter the cubicle, melt, and cause a ground fault. This event is being reported pursuant to 10 CFR 50.73(a)(2)(iv)(A) due to Reactor Protective System actuation and the automatic start of the 2B Emergency Diesel Generator. Corrective actions include repairs to 13 kV Service Bus 21 and installation of a new filter housing. Previous events related to safety-related structures have been documented in Licensee Event Reports 317/2010-001 and 317/2011-003.
|05000318/LER-2013-005||25 October 2013||Calvert Cliffs|
On September 5, 2013, Unit 2's Control Element Assembly (CEA) #27 dropped to the fully inserted position while the CEA was being operated as part of a surveillance test. Operators entered applicable Technical Specifications for the dropped CEA. When operators were unable to restore the CEA to its proper alignment within the required Completion Time, operators commenced a reactor shutdown in accordance with Technical Specification Required Action 3.1.4.F.1. The unit was shutdown at 1735 on September 5, 2013. Troubleshooting identified Control Element Drive Mechanism (CEDM) #27 lift coil lead wire was grounded internally to the coil housing due to a chafed wire. The root cause for the dropped CEA was determined to be a manufacturing defect that resulted in circumferential displacement of the coil within the coil housing-and the misalignment of the lift coil lead wire within the coil housing nipple. Corrective actions included replacement of the CEDM coil stack with one that includes a change in design featuring a protective heat shrink wrap at the point where the lead wire penetrates the coil housing nipple. All other Unit 2 CEDMs were meggered with satisfactory results. A detailed plan to replace the remaining Unit 2 CEDM coil stacks is being developed.
Replacement of the Unit 2 coil stacks is expected to begin during the 2015 refueling outage.
|05000318/LER-2013-003||3 July 2013||Calvert Cliffs||On May 8, 2013, at 2147 eastern daylight time, Unit 2 experienced an automatic reactor trip from 99.5 percent power. The Reactor Protective System actuated on high pressurizer pressure. The high pressurizer pressure condition occurred due to a loss of load event caused when main turbine steam admission valves closed. The most probable cause of the event was an intermittent failure of a component or signal path in main turbine control cabinet 2T11 that resulted in a control signal to the steam admission valves to close. At Calvert Cliffs, there have been no recent similar events involving a reactor trip caused by the failure of the turbine control system. This event is being reported pursuant to 10 CFR 50.73(a)(2)(iv)(A) due to Reactor Protective System actuation. Corrective actions include replacement of circuit cards in the main turbine overspeed protection circuitry, monitoring selected control system signals which could indicate the source of the signal should the event recur, and implementation of a project plan for selected turbine control circuit card replacement during a future refueling outage.|
|05000318/LER-2013-002||2 May 2013||Calvert Cliffs||On March 12, 2013, during scheduled testing at an offsite testing facility, the as-found lift setting for pressurizer safety valve, serial number BN04375, was measured higher than the Technical Specification allowable value. The valve had been installed in Unit 2 at the 2RV200 location (Unit 2 pressurizer safety valve) and was removed during the 2013 Unit 2 refueling outage for scheduled testing and maintenance. No material conditions were found that contributed to the high setpoint discovered during the test. The apparent cause is insufficient margin to address time-related drift. Corrective actions are to increase the Technical Specification setpoint tolerance and revise the procurement engineering standard as-left margin. A similar event is documented in Licensee Event Report 318/2011-002. The cause for that event was setpoint variation.|
|05000318/LER-2013-001||18 April 2013||Calvert Cliffs||On February 17, 2013, while Unit 2 was in Mode 3 during a refueling outage, a pinhole leak was identified at the upper packing leakoff line cap seal weld of pressurizer spray valve 2CV-100F, which constituted a Reactor Coolant System pressure boundary leak. The Technical Specifications limit Reactor Coolant System pressure boundary leakage to zero. Based on visual inspection performed during the boric acid walkdown the leak most likely existed during plant operation. The most likely cause of the pinhole was a latent weld defect created during the installation of the cap seal weld. A similar event is documented in Licensee Event Report 318/2010-002. The most likely cause for that event was a latent weld defect created during manufacture. The valve bonnet assembly, which includes the packing leakoff line, was replaced and inspected satisfactorily prior to startup from the Unit 2 refueling outage.|
|05000317/LER-2012-002||11 September 2012||Calvert Cliffs|
On July 17, 2012, Reactor Coolant System pressure boundary leakage was determined to exist on Unit 1 11A Reactor Coolant Pump differential pressure transmitter tubing. Operators commenced a Technical Specification required unit shutdown. With reactor power at 10 percent a containment entry was made to isolate the leak. This effort stopped the steam emanating from the insulated tubing. Unit 1 returned to full power. Unit 1 leak rate data was monitored for the next several days. It was determined conditions did not improve as expected.
An additional containment entry was made on July 21, 2012 which identified that Reactor Coolant System pressure boundary leakage existed past the previously shut isolation valves.
Operators conducted a Technical Specifications required shutdown of Unit 1 to MODE 5. The source of the leak was a crack in the tubing side weld of the pipe to tube adapter. The cause of the leak was high cyclic fatigue. The cyclic fatigue was caused due to a vertical support for the tubing that was not connected. Corrective actions included replacement of the adapter, the affected portion of tubing, and the connection of a re-engineered vertical support. The similar welds on the other Unit 1 reactor coolant pump differential pressure transmitter tubing runs were inspected with no issues identified. Unit 1 returned to full power on July 25, 2012.
|05000317/LER-2011-003||16 December 2011||Calvert Cliffs|
On October 21, 2011, Calvert Cliffs Nuclear Power Plant discovered that a reportable condition existed. On August 28, 2011, numerous alarms were received for the 1A Emergency Diesel Generator (EDG) (train A, one of two safety-related EDGs dedicated to Unit 1). Water was intruding down the diesel generator intake piping, resulting in a short circuit on the 1A2 engine speed switch circuit. The 1A EDG was declared inoperable and appropriate Technical Specifications were implemented. The 1A2 engine speed switch assembly was cleaned, dried, and inspected. The 1A EDG was returned to operable status. Corrective actions include repair of the affected piping penetrations.
A root cause analysis determined the most probable root cause to be the penetration around the 1A2 engine combustion air intake pipe on the 80 foot level of the 1A EDG Building was unable to perform its design function of being leak tight. This may have occurred due to improper installation, manufacturing defect, degradation, or original design considerations. This condition may have existed since construction of the 1A EDG Building in 1996. There have been no licensee event reports for similar events at Calvert Cliffs.
|05000317/LER-2011-002||2 December 2011||Calvert Cliffs|
At 1035 on October 3, 2011, Operators entered Limiting Condition for Operation (LCO) 3.0.3 for Calvert Cliffs Units 1 and 2. The LCO 3.0.3 entry was due to an emergent failure of 1A Diesel Generator (DG) Battery Charger which caused 1A DG to be inoperable concurrent with planned maintenance on No. 21 Saltwater Subsystem which caused 2A DG to be inoperable. The concurrent inoperability of both A Train DGs caused the A Train 125 VDC channels for each Unit to be declared inoperable and required entry into LCO 3.0.3 on both Units. At 1605 on October 3, 2011, 1A DG battery charger was returned to service and the 1A DG and all supported A Train components became operable. Limiting Condition for Operation 3.0.3 was exited for both Units at 1605.
The apparent cause of the battery charger failure was age related degradation of its circuit board due to exceeding its expected service life. The affected circuit boards were replaced.
Corrective actions include updating the preventive maintenance task to replace the battery charger circuit boards on a set periodicity.
|05000317/LER-2011-001||20 October 2011||Calvert Cliffs|
On August 27, 2011, at 2248 eastern daylight time, Unit 1 experienced an automatic reactor trip from 100 percent power. The Reactor Protective System actuated on loss of load. The loss of load occurred due to a phase-to-phase short circuit on the main transformer when main transformer lines were struck by dislodged Turbine Building siding caused by winds associated with Hurricane Irene. Immediately following the short circuit, 14 Containment Air Cooler stopped operating. Shortly after the plant trip occurred, 1A Emergency Diesel Generator was declared inoperable due to a shorted speed switch. The root cause analysis performed to address this event concluded that the Turbine Building Northwest corner siding was not installed per design during original construction. This resulted in a weaker siding connection to the Turbine Building structure, allowing the siding to come off in wind speeds less than design.
At Calvert Cliffs, there have been no recent similar events involving a reactor trip associated with severe weather. This event is being reported pursuant to 10 CFR 50.73(a)(2)(iv)(A) due to Reactor ProteCtive System actuation. Corrective actions include testing and inspection of the main transformer, replacement of B and C phase high line drops to the main transformer and inspection and repair of electrical connectors on the 1A Emergency Diesel Generator.
|05000318/LER-2011-001||15 April 2011||Calvert Cliffs||On February 17, 2011, while Unit 2 was in a refueling outage, it was verified that during a bare metal examination of all pressurizer heater locations, dry boric acid.was noted on heater N3 outer sleeve to weld pad J-Groove weld location indicating reactor coolant leakage. Based on this visual examination and the results from chemical analysis, the leak most likely existed during plant operation. Additional non-destructive and destructive examinations were performed. This non-destructive and destructive examination concluded that this leak is attributed to primary water stress corrosion cracking in the J-Groove weld. This heater location was repaired by removal of the N3 heater, sleeves, J-Groove weld, and installing an American Society of Mechanical Engineers Code approved welded plug. An additional thirteen pressurizer heater sleeve locations received additional non-destructive examinations and no additional non-conforming indications were found. All pressurizer heater penetrations received a non-destructive visual examination at normal operating pressure and temperature with no further visual signs of leakage. The scope of identified leakage and pressurizer repair was isolated to the pressurizer heater N3 location.|
|05000317/LER-2010-003||8 July 2010||Calvert Cliffs|
On May 12, 2010 at 13:51, Unit 1 experienced an automatic reactor trip from 100 percent power, when the Reactor Protective System actuated on high pressurizer pressure due to a complete load rejection. At the time of the event, maintenance was being performed in the switchyard requiring two 500 kV breakers to be open with a third 500 kV breaker (552-22) closed, thus allowing Unit 1 main turbine generator output to the grid. However, due to a loose connection in the 125 VDC distribution panel board for the breaker disconnect switches, breaker 552-22 tripped open upon receiving a trip signal from its trip circuitry, resulting in the complete load rejection condition. The root cause of the event was a loose electrical connection in the 125 VDC distribution panel board. After the trip, one of the pressurizer safety valves leaked. The Unit was taken to Mode 5 to repair the leaking pressurizer safety valve.
This event is being reported pursuant to 10 CFR 50.73(a)(2)(iv)(A) due to a valid actuation of the Reactor Protective System. Corrective actions include checking the electrical connections in the 125 VDC distribution panel for tightness, increasing the time delay to the re-trip feature of the subject type relays, replacing the disconnect bucket and revising the risk management procedure.
|05000317/LER-2009-001||4 May 2009||Calvert Cliffs||On March 6, 2009, Calvert Cliffs Nuclear Power Plant discovered that procedural requirements for starting a Reactor Coolant Pump (RCP) were not consistent with the pump start requirements contained in Technical Specifications 3.4.5, Note 2, 3.4.6, Note 2, and 3.4.7, Note 3. These notes provide Reactor Coolant System (RCS) criteria, such as pressure, level, and secondary water temperature acceptable for starting any RCP when the RCS temperature is less than 365 degrees F. Contrary to these pump start requirements, RCPs were started on April 6, 2006, December 20, 2006, and March 11, 2008 without meeting the RCS pressure requirement of Technical Specification 3.4.5, Note 2. This condition was prohibited by Technical Specifications. No adverse conditions resulted during these RCP starts. This event appears to be caused by a failure to recognize that when Improved Technical Specifications were adopted at Calvert Cliffs in 1998 a change was made that affected the applicability of the start criteria for this function. The corresponding operating procedure was not adequately updated to match the Improved Technical Specifications. The affected operating procedures are being revised to incorporate Technical Specification requirements for RCP starts. This condition does not apply to Unit 2 because the start conditions for RCPs are different than those on Unit 1 and have been met.|
|05000317/LER-2008-001||25 April 2008||Calvert Cliffs||On February 25, 2008, during performance of a bare metal visual examination, dry boric acid was noted on pressurizer heater sleeve C-2 indicating reactor coolant leakage. Subsequent ultrasonic examination confirmed the absence of a circumferential flaw., All other pressurizer heater sleeves were inspected with no additional findings. The most likely cause of the leak is Primary Water Stress Corrosion Cracking. The heater sleeve was repaired by installing an approved mechanical clamp. As a preventive action, the Unit 1 Pressurizer Heater Sleeves will be repaired/replaced in a future refueling outage which eliminates their susceptibility to Primary Water Stress Corrosion Cracking. This preventive action was established due to similar events discussed in Licensee Event Reports 318/89-007 arid 317/94-003.|
|05000318/LER-2007-001||29 May 2007||Calvert Cliffs||On April 2, 2007, while in Mode 1 during a Unit 2 startup, Operations staff determined that Channel C Linear Range Nuclear Instrument (LRNI) did not provide indication on the Reactor Protective System Calibration and Indication Panel. Troubleshooting determined that a circuit card was in the wrong slot on the circuit board, resulting in an inoperable condition for Channel C LRNI. This condition was created during the 2007 Unit 2 Refueling Outage while the plant was shutdown and the LRNI channels were not required to be operable. The inoperability of Channel C LRNI was related to human performance. Technician error led to the incorrect installation of the circuit card which resulted in a Reactor Protective System channel out-of- service. Additionally, post-maintenance testing failed to find the mis-located A3 circuit card prior to the mode of applicability for the affected channel. Operations personnel bypassed the inoperable channel until the problem was corrected. Maintenance, operations, and surveillance test procedure revisions are planned to prevent recurrence of this condition.|
|05000317/LER-2006-005||29 May 2007||Calvert Cliffs|
On December 17, 2006, at 04:25 a.m. plant personnel determined that the Reactor Protective System (RPS) Rate of Change of Power-High (or Startup Rate (SUR)) Trip would not be enabled at the Technical Specification required value of 12 percent Rated Thermal Power (RTP), decreasing, on Unit 1 RPS Channel A and Unit 2 RPS Channel C. This condition was identified RPS Channel A arid Unit 2 RPS Channel C recorded the Nuclear Instrument (NI) Level 1 Bistable resets as 11.9 percent and 11 percent RTP by local indication, respectively. The failure of the SUR Trip enabling function to reset prior to 12 percent RTP decreasing is prohibited by Technical Specifications. This condition rendered the automatic bypass removal feature inoperable for the affected channels. This event was caused by a failure to recognize that when Improved Technical Specifications were adopted at Calvert Cliffs Nuclear Power Plant in 1997, new acceptance criteria were added to the Technical Specifications for this function. The affected Unit 1 and Unit 2 SUR Channel Trip Units were placed in bypass mode upon discovery of the condition. Corrective actions to ensure the automatic bypass removal setpoints were within specifications for Unit 1 and 2 were completed at 11:30 p.m. on December 17, 2006.
Technical Specification Bases and STP changes will be made to prevent future recurrence.
|05000317/LER-2007-001||19 March 2007||Calvert Cliffs||Results from the hydrostatic pressure test performed in January 2007 on the Pump Cover Heat Exchanger (FIX) previously installed on 11B Reactor Coolant Pump (RCP), indicates that a Reactor Coolant System (RCS) pressure boundary leak existed when the component was installed in Unit 1. The HX was removed during the 2006 Unit 1 refueling outage as a corrective action to address failures of the lower seal stage and RCS detected in the Component Cooling Water (CCW) system. The RCS leakage was documented in September 2004. The RCS leak I rate was so small (approximately 0.016 gallons per day) that the exact location could not be identified by sampling. The leakage was considered unidentified RCS operational leakage, and was less than the one gallon per minute Technical Specification allowable. The Technical Specifications limit RCS pressure boundary leakage to zero. Chemistry tests performed on the CCW system subsequent to startup from the 2006 refueling outage indicated that the active RCS leak was no longer present. The hydrostatic pressure test results, and the fact that the RCS leakage stopped after the 11B RCP HX was replaced, confirm that an RCS pressure boundary leak existed.|
|05000317/LER-2006-001||26 December 2006||Calvert Cliffs|
On March 24, 2006 with Unit 1 shutdown in Mode 6, Motor Control Center (1MCC123) Feeder Breaker (52-1703) tripped on short-time overcurrent during performance of a surveillance test procedure. Unit 2 was operating in Mode 1 at the time of the event. The feeder breaker powers safety-related auxiliaries required for operation of the 1A Emergency Diesel Generator (EDG).
As a result of the feeder breaker tripping, operations personnel secured the 1 A EDG and secured the surveillance test. Subsequent investigation determined that the short-time overcurrent amptector setpoint was set too low and had drifted down to a value lower than the associated inrush starting current, resulting in the feeder breaker trip. An engineering evaluation determined that the original amptector design setpoint, established by a vendor, was not adequate because the setpoint did not consider all potential loads that could be realized upon an EDG start and load during a design basis event. Corrective actions included installing a new amptector, increasing the amptector setting, and notifying the vendor. Additional actions planned include training engineering personnel and evaluating safety-related feeder breakers to ensure setpoints have adequate margin. The 1A EDG was subsequently tested satisfactorily and returned to service on March 25, 2006. This event is also reportable per 10 CFR Part 21.
|05000318/LER-2003-001||23 April 2003||Calvert Cliffs|
Calvert Cliffs Nuclear Power Plant's Technical Specifications requires one door in the emergency air lock (a containment penetration) to be closed during core alterations or during movement of irradiated fuel assemblies within the Containment Building. However, on February 24, 2003 at 1500 during a Containment Building tour, it was identified that the Unit 2 Emergency Air Lock was not in the Technical Specification required status. Specifically, "daylight" was seen around a hose penetrating the emergency air lock temporary closure device. The emergency air lock temporary closure device can be used in place of an emergency air lock door. Subsequent investigation determined that the violation occurred on February 23, 2003 at approximately 1300 when a contract employee cut through the foam sealant in the temporary closure device to install an oxygen hose needed to support steam generator replacement activities. The oxygen hose was removed and the hole was sealed on February 25, 2003, prior to commencing core off-load.
However, since core alterations (specifically control element assembly uncoupling) were performed on February 23, 2003 from 0955 until 1805, a condition existed that is prohibited by the plant's Technical Specifications.