|Report date||Site||Event description|
|05000285/LER-2017-001||11 May 2017||Fort Calhoun||On March 13, 2017 at 16:00 hours, an unattended opening into a room classified as a vital area was identified by Security management. The unattended opening was created when a physical barrier was removed during decommissioning work within a vital area. The cause was determined to be an inadequate procedure(s) such that this action was not recognized by station personnel as a potential breach of a vital area pathway, therefore no compensatory measures were initiated prior to main steam discharge piping elbow removal. Upon recognition, the appropriate compensatory measures were implemented and a one hour report of Reportable Safeguards Events under 10 CFR 73.71(b)(1) and 10 CFR 73.71 Appendix G Section I (EN 52609) was submitted to the NRC.|
|05000285/LER-2016-002||21 October 2016||Fort Calhoun|
On May 10, 2016, at 1138 Central Daylight Time (CDT), during scheduled maintenance, an unanalyzed condition was discovered as a result of maintenance on Shutdown Cooling Heat Exchanger valves. This condition could have led to the inability of the Component Cooling Water (CCW) system to perform its design function of providing a cooling medium for the Containment atmosphere under Loss Of Coolant Accident (LOCA) conditions.
As part of the maintenance, HCV-484, Shutdown Heat Exchanger AC-4A CCW Outlet Valve, and HCV-481, Shutdown Cooling Heat Exchanger AC-4B CCW Inlet Valve, were open. Under these conditions, with the assumed single failure loss of DC control power and accident condition of a LOCA, CCW would be allowed to flow through both shutdown cooling heat exchangers, bypassing a portion of the flow to the Containment Cooling Units. These conditions are not assumed under plant design basis calculations, and therefore placed the plant in an unanalyzed condition. Both HCV-484 and HCV-481 were returned to service and the condition no longer exists.
|05000285/LER-2016-003||22 August 2016||Fort Calhoun||An automatic turbine trip occurred resulting in an automatic Reactor Protective System (RPS) actuation from mode 1 at 100% power due to loss of turbine load at 0841 Central Daylight Time on June 22, 2016. System actuation and responses were as designed. There were no Safety Systems inoperable that contributed to this event. The trip occurred during Post Modification Testing activities on the turbine Emergency Trip System (ETS) pressure loop trip. Engineering failed to identify and disable the transmitter deviation based trip. The differences between the substituted input values selected for testing and the output of the signal selector block were sufficient to trigger the two transmitters-in-deviation trip for the ETS loop.|
|05000285/LER-2016-001||8 April 2016||Fort Calhoun|
On February 10, 2016 Fort Calhoun Station became aware of a part 10 CFR 21.21 notification from Canberra Industries, Inc. for purchase orders related to Radiation Monitoring (RM) equipment. An investigation identified Time Delay Relay (PO 185167) had been installed in RM-052 Containment and Auxiliary Building Stack Gaseous Swing Radiation Monitor since July 23, 2013. During the period since installation conditions existed such that the maximum number of Technical Specification required radiation monitors allowed out of service was exceeded for periods in excess of the Limiting Condition of Operation.
On 03/1 9/1 6 the Time Delay Relay was replaced with a qualified part (WO 578335) and all necessary surveillance testing completed satisfactorily restoring RM-052 to an operable condition.
NM FORM 366 (11-2015) APPROVED BY OMB: NO. 3160.0104 EXPIRES: 1013112016 comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (1--.5 F53), U.S. Nuclear Regulatory Commissbn, Washington, DC 20555-0001, or by Internet email to NEOB.10202, (31504104), 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,
|05000285/LER-2015-006||11 December 2015||Fort Calhoun|
On October 21, 2015, at 1315 Central Daylight Time (CDT), while conducting design reviews, it was discovered that the isolation function, when transferring control from the Main Control Room to the Alternate Shutdown Panel (Al-185) for pressurizer backup heater bank 4, had been identified as a potential circuit failure.
The pressurizer backup heater bank 4 control circuit isolation vulnerability is a latent issue that originated in modification MR-FC-82-066 which installed the control circuit isolation for the pressurizer backup heater bank 4 in 1983. There have been missed opportunities to identify and correct the issue since 1982, however, it was not identified until CR 2015-12195 on October 21, 2015.
The vulnerability has been added to the pre-existing NFPA 805 Fire Protection compensatory measure for Fire Area 41, the Cable Spreading Room. Fire Area 42, the Main Control Room, is continuously staffed which has been credited as the compensatory measure. Additional actions will be implemented by the corrective action program.
|05000285/LER-2015-005||17 September 2015||Fort Calhoun|
On July 20, 2015, an increase in reactor coolant system leak rate required station personnel to manually trip the reactor. The walkdown on July 21 determined that the location was the result of a middle seal cartridge inlet pressure tap through-wall crack. The piping is a class 1 pressure boundary.
A design weakness resulted in the vibrations from RC-3A combined with the cantilevered pipe load causing cyclical stresses on the toe of a weld on the seal inlet pressure pipe tap. These stresses initiated a fatigue crack at the toe of the weld on the piping which subsequently propagated inward and progressed through the pipe wall causing the failure.
The seal package for the reactor coolant pump was replaced with a spare unit.
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|05000285/LER-2015-004||3 August 2015||Fort Calhoun|
On June 5, 2015, at approximately 1330 Central Daylight Time (CDT), during startup HCV-1107A (Steam Generator (SG) RC-2A Auxiliary Feedwater (AFW) Inlet Valve) was declared inoperable when it failed to move during testing. During the investigation HCV-1108A (SG RC-2B AFW Inlet Valve) was found to hesitate during operation. The valve sealing materials had been replaced during the refueling outage with materials that were not appropriate for the service conditions.
A cause determination determined that the original valve specification for HCV-1107A was not appropriate for the plant application.
HCV-1107A and HCV-1108A were repaired using the original materials. An operability evaluation was completed for use of the original materials for one operating cycle. An engineering solution to the issue will be completed prior to startup from the next refueling outage.
|05000285/LER-2015-003||15 June 2015||Fort Calhoun|
During design basis reconstitution of the Containment Spray (CS) system, it was discovered that the CS piping inside containment and the containment liner have higher stresses during a postulated Main Steam Line Break (MSLB) or Loss of Coolant Accident (LOCA) than previously analyzed. The preliminary analysis concluded that both CS piping trains inside containment and the containment liner failed to meet the operability requirements of American Society of Mechanical Engineers (ASME) Section III Appendix F without implementing compensatory measures.
A cause analysis was performed and determined that thermal expansion was never considered for the containment riser supports. This is a flaw in the original design of the CS header and rings inside containment.
An operability evaluation was completed in support of plant operation. The operability evaluation conclude that the piping and pipe supports of the CS System as well as the Containment liner are capable of performing their intended safety functions per the operability criteria of ASME BPVC Section III Appendix F following modifications completed under Engineering Change (EC) 65926. Additional evaluation determined that only one pipe support exceeded the code allowable stresses. Final corrective action to fully qualify the CS system will be completed under the stations corrective action program.
|05000285/LER-2015-002||28 May 2015||Fort Calhoun|
During a review of station procedures a station operator determined that during the performance of OP-ST-AFW- 3009, "Auxiliary Feedwater Pump FW-6, Recirculation Valve, and Check Valve Tests," the restoration steps momentarily crosstie Main Feedwater (not safety related) with Auxiliary Feedwater system (safety related).
During AFW system restoration a flowpath from the discharge of both the steam driven AFW pump (FW-10) and electric AFW pump (FW-6) is established to main feedwater. At the time of discovery the test was not being performed, however, the test had been performed during the last operating cycle.
The assessment and application of separation requirements in the associated procedures did not identify the cross tie methods and impacts due to reviewers not understanding piping class separation requirements.
AFW procedures were reviewed to ensure that other AFW procedures allow inappropriate lineups. Four (4) procedures were identified that aligned AFW in a similar manner. The use of the affected procedures has been administratively restricted until they can be corrected.
|05000285/LER-2015-001||27 March 2015||Fort Calhoun|
On January 28, 2015, following a station initiated review of operability evaluations, it was determined that a penetration with inadequate jet impingement protection had been previously identified as part of station extent of condition reviews and constituted an unanalyzed condition, but, had not been reported as required. This issue was discovered during an extent of condition review of high energy line break issues that the station initiated due to previously identified concerns. This issue and the other issues identified during the extent of condition review were corrected prior to plant heatup.
The Shift Manager that approved the operability evaluation believed that the reportability aspect of the penetration had been previously reported to the NRC and that no further report was required. The Shift Manager did not confirm that the reportability had been completed under another LER.
These issues were discovered during the Electrical Environmental Qualification Program Reconstitution Project. The deficiencies were discovered during extent of condition reviews. The deficiencies were properly remediated prior to plant startup in December 2013.
|05000285/LER-2015-001, Inadequate Design of High Energy Line Break Barriers||27 March 2015||Fort Calhoun|
|05000285/LER-2014-006||12 November 2014||Fort Calhoun|
During an NRC inspection on September 16, 2014, it was discovered that the calibration procedure for Radiation Monitor (RM) - 091A/B uses a source that is above 1 Roentgen per hour (R/hr). This does not meet the technical specification requirement for calibration at least one decade below 1 R/hr. 1 R/hr is the lower limit of detection of the high range detector for the RM-091 instruments. Calibration at least one decade below 1 R/hr is not possible.
The most likely cause of the event is that a typographical error was introduced into license amendment request (LAR) during review process in 1993 and was not corrected prior to submittal to NRC.
A LAR (LIC-14-0122) was submitted to the NRC to correct the technical specification error.
|05000285/LER-2014-004||3 October 2014||Fort Calhoun|
On April 24, 2014, during a review of previous conditions affecting equipment qualification it was identified that the environmental qualification of Namco EA180 series limit switches were not being properly maintained per vendor requirements. This condition was not verbally reported at the time of discovery as the condition was identified and resolved while the plant was in an extended shutdown.
A cause evaluation was completed and determined that technical requirements from the vendor manual for maintaining environmental qualification of the Namco EA180 series limit switches were not captured in the applicable plant procedure.
The applicable plant procedure has been revised to include vendor information for maintaining environmental qualification of the limit switches. The limit switch top cover gasket and screw assemblies for all environmentally qualified Namco EA180 series limit switches were replaced and torqued in accordance with vendor requirements.
|05000285/LER-2014-005||25 August 2014||Fort Calhoun|
On Friday, June 27, 2014, during performance of a valve exercise test it was discovered that test swagelock plug was missing between the containment penetration and the associated outboard isolation valve. Technicians discovered the test swagelock plug resting on a nearby junction box and not in place on the containment penetration. The technicians immediately notified the Auxiliary Building Operator who was assisting with the surveillance test. Operations shift supervision were notified and operations declared containment inoperable per Technical Specification and entered a 1 hour limiting condition for operation (LCO) to restore containment integrity. The shift manager directed the technicians to reinstall the test swagelock plug on the containment penetration. At that point, operations declared containment operable and exited the associated Technical Specification LCO.
Maintenance personnel exhibited weak Human Performance tool Independent Verification usage. Station personnel completed the Containment Integrity checklists prior to all containment isolation boundary maintenance and/or LLRTs being completed.
Containment integrity was restored.
|05000285/LER-2014-003||14 May 2014||Fort Calhoun|
On March 17, 2014, at 12:02 Central Daylight Time (CDT), a turbine trip and subsequent reactor trip occurred while operating at nominal 100 percent power. Maintenance was in progress on the main generator stator cooling system when system inventory was lost resulting in an automatic turbine trip due to low system pressure.
Immediate response by operations personnel included implementing procedure emergency operating procedure (EOP) -00, Standard Post Trip Actions, and subsequent entry into procedure EOP-01, Reactor Trip Recovery.
Based on plant system response this is considered an uncomplicated trip.
The station determined that the root cause of the plant trip was that operational risk was not effectively identified or mitigated by individuals throughout the organization.
The leak was isolated shortly after the trip by fully removing the probe and closing the isolation valve. Fort Calhoun Station will be implementing the Exelon risk management procedure, WC-AA-104, Integrated Risk Management. This procedure provides direction consistent with industry best practices, and requires individual review of each category of risk identification and mitigation.
|05000285/LER-2014-001||7 March 2014||Fort Calhoun|
At approximately 2230 Central Standard Time (CST), on January 8, 2014, CW-14C, Traveling Screen Sluice Gate, motor operator shaft was found damaged (bent) by Operations personnel. At 2330 CST a large block of ice buildup was observed on top of the sluice gate caused by a pinhole leak in the backwash piping located directly above the CW-14C gate. At 0250 CST, January 9, 2014, Operations unsuccessfully attempted manual closing of CW-14C. At 0315 CST the station entered TS 2.0.1(1) due to all raw water (RW) pumps being declared inoperable. At 0518 CST the station commenced a reactor shutdown. At 0900 CST the station completed the reactor shutdown.
The root cause was determined to be that CW-14C MOV torque setting was at a value that allowed the stem to be bent.
CW-14C was lowered and then verified closed by divers. The flooding strategy for the Intake Structure was met at 0350 CST on January 10, 2014. RW Pumps AC-10A, AC-10B, AC-10C and AC-10D were declared operable and TS 2.0.1(1) was exited.
|05000285/LER-2012-002||2 July 2013||Fort Calhoun|
On May 1, 2012, with Fort Calhoun Station (FCS) defueled, Event Notification (EN) 47884 initially reported that during a review of environmental qualification records for containment building electrical penetration feed-through subassemblies, Omaha Public Power District (OPPD) identified six that may not provide an adequate seal during worst-case design-basis accident conditions as required due to failure of the Teflon in the connectors. OPPD updated the EN June 26, 2012, to include the inboard and outboard seals of the penetration, which contain Teflon and updated it again July 17, 2012, to include the containment sump outlet valve submarine hull enclosures and the containment personnel airlock. The initial LER submittal, dated May 1, 2012 did not contain this updated information.
OPPD performed causal analyses to determine why Teflon was used at Fort Calhoun as a containment integrity seal and insulation on power and control cabling to environmentally qualified components. These analyses determined that a lack of managerial and technical oversight allowed Teflon and Teflon like materials to be used in containment penetration applications.
The Fundamental Performance Deficiencies are addressing the managerial and technical oversight causes.
OPPD is replacing all containment penetrations where Teflon is used as sealant or conductor insulation and is capping unused penetrations prior to core reload.
|05000285/LER-2013-002||28 June 2013||Fort Calhoun|
On January 25, 2013, while developing the modification to replace a portion of the Chemical and Volume Control System (CVCS) piping in containment, it was identified that the original piping supports had no calculations of record. When the calculations for the replacement piping were completed using the original support configuration, an overstress condition of the new piping was identified that directly related to the old piping. This condition would have made the original piping susceptible to failure during a seismic event. Portions of the Class 1 charging and letdown lines were affected. The plant was shutdown and defueled at the time of discovery.
The causal analysis determined that station construction project management failed to ensure that initial construction procedures for design and installation of small bore piping systems and supports were in compliance with USA Standard B31.7, Nuclear Power Piping.
Fort Calhoun Station will analyze and modify the supports as required to conform to the piping load requirements of the various operational Modes prior to entering that Mode.
|05000285/LER-2013-003||1 April 2013||Fort Calhoun|
At approximately 1721 Central Standard Time, on January 30, 2013, during hydraulic evaluations for the alternate hot leg injection project, Design Engineering determined that design basis calculations indicated that the high pressure safety injection (HPSI) pumps would operate in a run-out condition under worst case design basis accident conditions. Previous changes to the operation of the HPSI pumps and the containment spray pumps have resulted in an increase in the injection phase time and an increase in HPSI pump flow during the accident. This could have resulted in the HPSI pumps operating in run-out for longer than the one hour manufacturer's recommended time limit.
A preliminary causal analysis identified that the station failed to obtain vendor technical information on HPSI pump performance in a 10 CFR 50, Appendix B, Quality Assurance validated format. An analysis of HPSI pump performance during the injection phase will be performed and design or procedural actions to prevent HPSI pump operation in the extended flow region and to ensure that sufficient net positive suction head is available will be taken.
|05000285/LER-2013-001||19 March 2013||Fort Calhoun|
On January 15, 2013, while reviewing a previous condition report, it was identified that a previous operability determination (OD) completed for General Electric (GE) model HFA relays was incorrect in that it did not appear to fully address the condition of the mounting screws that required torqueing. The seismic test results stated that the GE HFA relays passed the seismic testing, but the relays required two screws to be torqued to 5 foot-pounds. This condition of the additional required torqueing was initially entered into the corrective action program on December 21, 2012.
Currently, approximately 136 relays, that provide various indication and control functions in systems such as high pressure safety injection, charging, containment ventilation, and the emergency diesel generator, have been identified as potentially affected. Relay replacement/torqueing is in progress. A cause analysis is in progress, the results of which will be published in a supplement to this LER.
|05000285/LER-2012-003||16 November 2012||Fort Calhoun|
A non-conservative error was identified in the input calculation for post-LOCA cooling flow (post-RAS (recirculation actuation signal)). The calculation used an incorrect (non-conservative) input for LPSI pump performance. The associated procedure (EOP/AOP Attachment 11) as written does not provide adequate direction during the Alternate Hot Leg Injection mode of operation. Therefore, the procedural guidance may not ensure the completion of the safety function of providing adequate core cooling during the Alternate Hot Leg Injection mode of operation under a worst case scenario.
The apparent cause was identified to be inadequate use of vendor oversight when design information was transmitted to the vendor. The analysis also identified a contributing cause of inadequate review of the calculation provided by the vendor during the owner acceptance process. Procedural requirements to conduct peer reviews prior to transmitting design information to vendors and contractors preparing safety-related calculations have been incorporated into the governing procedures. Additional corrective actions will revise the deficient calculation and procedure.
|05000285/LER-2012-004||27 October 2012||Fort Calhoun|
While investigating industry operating experience, it was determined that Fort Calhoun Station is subject to similar conditions where Static "0" Ring pressure switches with certain housing styles exhibit a setpoint shift when exposed to a change in temperature if the switch body is not vented. Fort Calhoun Station pressure switches that provide signals for high containment pressure to the reactor protection system and engineered safeguards actuation circuitry may have this configuration. The impact of the potential drift was evaluated and it was initially determined that neither reactor protection system nor the engineered safeguard circuitry may actuate at the required containment pressure of 5 psig. A subsequent evaluation of actual data concluded that safety analysis limits were not exceeded. However, two Technical Specification limits were not protected by the calibration procedure nominal trip setpoint when applying the additional uncertainty.
The Apparent Cause was determined to be poor vendor documentation which led to Engineering personnel to improperly interpret and apply the information contained in the Static "0" Ring vendor manual. Corrective actions were initiated to remove the vent caps, revise the affected calculations to the temperature correction factor and drift.
Additional actions to revise and re-perform surveillance testing were initiated.
|05000285/LER-2012-005||1 June 2012||Fort Calhoun|
On February 21, 2012, during a review of Fort Calhoun Station surveillance procedures, it was identified that the Emergency Diesel Generator (EDG) fuel oil transfer pumps have not been tested in accordance with the requirements of Technical Specifications (TSs). The inadequate testing was caused by a procedure change made in 1990 that removed the required monthly test of the automatic low level start feature of the fuel oil transfer pumps. There is reasonable assurance that the EDGs and fuel transfer pumps would function as required as the low level switches are calibrated on a refueling frequency.
The apparent cause of this event is a lack of technical rigor in the procedure change process employed in 1990s.
Corrective actions have been developed to revise the EDG surveillances to include fuel oil transfer pump surveillance testing.
|05000285/LER-2010-006||29 April 2011||Fort Calhoun|
Fort Calhoun Station was operating at full power (nominal 100 percent). The station was preparing a scaffolding for an upcoming outage when on December 23, 2010, at 1050 Central Standard Time (CST), a reactor trip occurred. The operators entered Emergency Operating Procedure (EOP) 00, "Standard Post Trip Actions." The main steam and feedwater systems operated normally. All control rods inserted fully.
The apparent cause of the turbine and subsequent reactor trip was the inadvertent actuation, caused by bumping, and sticking of one of four turbine moisture separator high water level turbine trip switches while reactor power was above 15 percent. The root cause was insufficient performance monitoring of the moisture separator high level trip mercury switches which resulted in degraded performance and increased risk for susceptibility to binding.
Following the initial determination of the erroneous moisture separator high level trip signal, immediate actions included: halting all work near the moisture separator sensing lines and level switches, posting the affected areas as "Protected Equipment," and initiating a stop work action for all ongoing scaffold work within the turbine building. The I moisture separator level switches and logic will be replaced during the 2011 refueling outage.
|05000285/LER-2006-005||11 December 2006||Fort Calhoun|
At 1500 CDT, on October 10, 2006, while performing maintenance on one of two installed containment spray header valves (HCV-345), personnel determined that the HCV-345 valve disk had been installed incorrectly during the previous refueling outage. HCV-345 is a vee-ball valve. Actual valve position was found to be nearly the opposite of the remote indication. The resulting effect would be that an accident signal to open HCV-345 would have the valve 20 percent open instead of 100 percent open (or 80 percent open instead of closed during normal operations). A single failure of the other containment spray header valve would have resulted in substantially reduced containment spray flow.
The maintenance procedure allowed for the flexibility of performing selected portions of the procedure without providing adequate annotations to identify risk-important steps that could impact final valve alignment. A test to verify flow and isolation capabilities after the valve was installed in the system is impractical to perform. The procedure used to conduct the maintenance was relied upon to ensure proper valve operation without detailed acceptance criteria or verifications. This resulted in the post maintenance test process failing to identify the problem.
The valve was repaired and verified to be in its correct operating position. Maintenance procedures are being rewritten to preclude this from occurring again.
|05000285/LER-2003-003||11 November 2003||Fort Calhoun|
During a reactor shutdown in preparation for a refueling outage, the power reduction was stopped because the operators were unable to maintain the axial shape index (ASI) within the expected band. In order to minimize the operational challenge, management provided two reactor trip criteria. At 2037, with the power reduction close to a nominal 15 percent power, it was noted that ASI might not be maintained within the required margin if the shutdown continued. At 2055 on September 12, 2003, Operations determined that a reactor trip was required because one of management's reactor trip criteria was about to be met. The reactor operators were directed to trip the reactor using the manual pushbutton. A four (4) hour non-emergency report was made to the NRC Operations Center at 0010 CDT on September 13, 2003, pursuant to 10 CFR 50.72(b)(2)(iv). This report is being made pursuant to 10 CFR 50.73(a)(2)(iv).
No formally approved written guidance was provided to the operator and therefore this event is reportable.
Management failed to recognize that a manual trip of the reactor without a change to the shutdown procedure would be reportable.
Appropriate procedural revisions to allow the flexibility in plant procedures to allow a manual reactor trip from power levels greater than 2 percent are being processed.
|05000285/LER-2014-007||11 November 1111 JL||Fort Calhoun|
On December 17, 2014, at 1014 Central Standard Time (CST), the Fort Calhoun Station (FCS) reactor tripped due to a loss of load signal from the main turbine. The loss of load signal actuates the reactor protective system (RPS) which tripped the plant. The trip of the turbine was caused by a spurious actuation of a relay on the station unit auxiliary transformer that normally provides power to 4160 VAC bus 1A2.
The root cause was that FCS had not ensured that an identified single point vulnerability for T1A-2 transformer was eliminated or had an adequate mitigating strategy.
The control cabinet sealing was improved to reduce moisture from the interior of the cabinet. The relay that caused the trip was removed from the trip circuit. The station will modify the control circuits to eliminate the single point vulnerability in the transformer control cabinets.