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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.

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,

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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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.

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.

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.

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.

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.

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.

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.

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.

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.

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.