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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 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.

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.

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.

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 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.

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.

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.

On January 25, 2007, the 4160 volt circuit breaker for raw water (RW) pump AC-10B closed on demand, but the auxiliary contacts did not actuate. The failure was determined to be a broken mechanical linkage rod. The rod was replaced. The failure was determined to be due to cyclic fatigue. A visual inspection of the other three RW pump circuit breakers, performed at that time, did not reveal any similar damage. AC-10B was returned to service. On February 8, 2007, a similar event occurred where the circuit breaker for RW pump AC-10C closed on demand, but its auxiliary contact switch did not actuate. Again, the failure was determined to be the same mechanical linkage rod.

The root cause of this failure was that the processes involving the identification of critical interface/operating configurations when specifying material procurement requirements failed to identify the usage of a test flag as a critical constraint.

The mechanical linkages of RW pumps AC-10C, A and D were rebuilt with rods having less than 1000 cycles of operation (the limit established for linkage operability). All other affected circuit breakers having more that 1000 cycles of operation have been rebuilt with rods having fewer than 1000 cycles of operation. A replacement strategy for the mechanical linkages is being developed. Implementation of this strategy will be controlled by the corrective action system.

On November 27, 2006, Fort Calhoun Station (FCS) was in Mode 4, cold shutdown, with shutdown cooling (SDC) in service. Reactor coolant system (RCS) temperature was approximately 119F and RCS pressure was approximately 233 pounds per square inch absolute (psia). Reactor Coolant Pumps RC-3A and RC-3B were in service. The pressurizer had maximum heaters and spray flow in service. RC-3B and RC-3A were secured at 1327 central standard time (CST) and 1330 CST, respectively, which reduced the spray flow to the pressurizer. As a result, RCS pressure rose to greater than 250 psia and initiated closure of shutdown cooling isolation valves, HCV-347 and HCV-348. The crew immediately recognized the loss of SDC condition and entered the appropriate abnormal operating procedure. The crew secured the running low pressure safety injection (LPSI) pumps, secured all pressurizer heaters and initiated auxiliary spray to lower RCS pressure.

When RCS pressure was less than 250 psia, the crew restored the SDC system to operation.

The root cause of this event was determined to be a mismatch between procedural guidance and crew experience.

The SDC system was returned to operation. Operator training and appropriate procedures are being revised.

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.

During a review of the Fort Calhoun Station (FCS) Appendix R "Safe Shutdown Analysis" and "Functional Requirements and Component Selection Calculation," it was determined that a fire in either Corridor 4 (Fire Area 6) or the East Switchgear Room (Fire Area 36A) could affect the operation of the charging pump credited by these analyses. In either of these fire scenarios, the two remaining charging pumps are considered lost to the fire event since power supplies or power cables for these pumps are located in the respective fire areas.

The root cause of this condition is that plant procedures did not adequately document a manual operator action credited in response to a fire as documented in the "Safe Shutdown Analysis." FCS had previously identified this concern generically, and had placed it in the stations corrective action system.

A fire watch was stationed in the affected areas when the problem was determined to exist on December 19, 2002. The appropriate fire protection analyses and procedures will be corrected in accordance with the station's corrective action program.

An inspection found that the quarterly full flow tests on the Auxiliary Feedwater (AFW) system pumps inappropriately took credit for manual operator action to isolate the full flow test line in the event that AFW flow was needed for an accident. Eliminating this unapproved credit rendered both trains of the AFW system inoperable for the length of the test. This test had been performed in this manner since about 1993. A review found that other procedures credited using manual operator actions for automatic actions. During part of a test of the Emergency Core Cooling System (ECCS), the pump recirculation line was isolated for a short period of time. During this time, had an accident signal started the ECCS pumps with plant greater than injection pressure the pumps would have run at shutoff head until the operator took action to restore the minimum flow path.

The Fort Calhoun Station (FCS) review of NRC Information Notice (IN) 97-78 incorrectly assumed that the NRC had approved crediting manual operator actions to maintain the pump operable when a violation on a related AFW issue was closed in an NRC Inspection Report. FCS reviewers assumed that IN 97-78 requirements were being met by administrative control of manual operator actions. This resulted in a less than adequate review.

Plant procedures have been corrected to implement the appropriate guidance and appropriate personnel have been trained.

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