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At 1000 EDT on September 9, 2017, the Division 2 Mechanical Draft Cooling Tower (MDCT) fans were declared inoperable due to loss of output from the over speed fan brake inverter. The MDCT fans are required to support operability of the Ultimate Heat Sink (UHS) and the Emergency Equipment Cooling Water (EECW) system. The Division 2 EECW system cools the High Pressure Coolant Injection (HPCI) system room cooler. As a result, the non-functionality of the fan brakes lead to an unplanned HPCI inoperability.

Since HPCI is a single train system designed to mitigate the consequences of a loss of coolant accident (LOCA), this event could have prevented the fulfillment of a safety function. The cause of the event was the failure of the Division 2 fan brake inverter.

Corrective Actions were taken to replace the inverter and returning the MDCT fans, the UHS, EECW and HPCI to service on September 9, 2017 at 2351 EDT. A failure modes evaluation was performed by the vendor with no direct cause of the failed output determined. The fan brake system is only required for a design basis tornado and there was no credible tornado threat during this event.

The HPCI system is not required to mitigate a design basis tornado. The safety significance of this event is very low and there were no radiological releases associated with this event.

On May 22, 2017 at 05:10 am (EST), while placing Division 2 Residual Heat Removal Service Water (RHRSW) in service for biocide treatment of the Division 2 Residual Heat Removal (RI IR) Reservoir, the Division 2 RI IRSW Flow Control Valve (FCV) (El 1 50F068B) failed to fully open.

Troubleshooting discovered the direct cause was failure of the anti-rotation bushing stem key. The apparent cause was system operating conditions (high vibration) resulting in the failed tack welds. Previous troubleshooting on an indication issue on May 5, 2017 for the RHRSW FCV was inadequate, and did not identify the failure of the anti-rotation key. As a result, the RHRSW FCV was returned to service at 2:50 pm on May 7, 2017, and subsequently failed on the next on-demand stroke at 5:10 am on May 22, 2017. Seventeen similar Motor Operated Valves (MOVs) were inspected and no MOVs exhibiting the symptoms observed on the E1150F068B prior to the failure of the anti-rotation key were found, and all anti-rotation devices were found to be intact. The Past Operability determination for 131150E068B found that the MOV was unable to perform its design basis functions from May 3. 2017 at 5:48 am, when the RI IRSW FCV was last successfully stroked under dynamic conditions, through May 24. 2017 at 4:04 pun, when the RI IRSW FCV was returned to service. The Division I RI-IRSW was available throughout the event except on two occasions. Division 1 of RHRSW was declared inoperable for Mechanical Draft Cooling Tower (MDCT) Nozzle Cleaning activities on May 9, 2017 from 8:41 am to May 9, 2017 at I I :18 pm. Division I of RI IRSW was again declared inoperable for IVIDCT Nozzle Cleaning activities on May 11, 2017 at 8:35 am through May 11, 2017 at 10:01 pm. The as found condition of the Division 2 RHRSW FCV is a condition prohibited by Technical Specification 3.7.1 and reportable under 10 CFR 50.73 (a)(2)(i)(13) "Operation or Condition Prohibited by Technical Specifications," and 10 CFR 50.73(a)(2)(v)(13) "Any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to: Remove Residual Heat.

On January 6, 2017 an Operations Shift Engineer determined that use of the Reactor Protection System (RPS) test box described in station procedures would result in the loss of two RPS reactor scram functions. Technical Specification (TS) 3.3.1.1 requires that RPS instrumentation for Table 3.3.1.1-1 Function 5 for Main Steam Isolation Valves (MSIVs) and Table 3.3.1.1-1 Function 9 for Turbine Stop Valves (TSV) remain OPERABLE. Operations procedures were revised to incorporate the use of the test box in August of 2016.

Between September 22 and 23, 2016 the MSIV and TSV procedures were each performed one time using the test box. The failure to recognize the impact of the procedure revisions is considered a human performance error by engineering and operations personnel.

The procedures were corrected in January 2017 to remove the use of the RPS test box. Subsequently, on January 7 and 9, 2017, respectively, the procedures for the TSVs and the MSIVs were performed successfully.

At 1514 EST on January 6, 2016, while operating at 100 percent Reactor Thermal Power (RTP), the East and West Turbine Bypass Valves (TBV) automatically opened as expected for 3 minutes and 32 seconds in response to the number one High Pressure Turbine Stop Valve (TSV) drifting from full open to 25 percent open due to an actuator malfunction.

Per Technical Specification (TS) Bases 3.3.1.1, TBVs must remain shut while RTP is at or above 29.5 percent to consider all channels of the TSV closure and Turbine Control Valve (TCV) fast closure Reactor Protection System (RPS) functions operable.

Reactor Operators lowered RTP to 91.0 percent and at 1518 EST the TBV automatically closed and the TSV closure and TCV fast closure RPS functions were no longer considered inoperable. TS 3.3.1.1 requires that the TSV closure and TCV fast closure RPS functions be operable at or above 29.5 percent RTP. In this event, during the period of time while TBVs were open, reactor power was maintained above 91 percent and the RPS functions were confirmed to be enabled.

The actuator malfunction was caused by faulty connectors within the actuator. The faulty connectors were replaced.

On November 24, 2013, at approximately 00:01 hours EST, during normal plant operations, the non-safety related Reactor Building Heating Ventilation and Air Conditioning (RBHVAC) system tripped on low steam coil heater temperature. Secondary Containment differential pressure exceeded the Technical Specification (TS) Surveillance Requirement limit of -0.125 inches water column (WC), reaching a maximum of +0.08 inches WC. At 00:04 hours EST, the Standby Gas Treatment System (SGTS) was started and Secondary Containment differential pressure decreased to less than -0.125 inches WC. The RBHVAC system tripped due to lack of steam flow through a heating coil caused by inadequate draining of the downstream steam trap. Investigation revealed the presence of some corrosion and a cracked drain seat in the associated steam drain. The degraded steam drain was then replaced and tested. RBHVAC was returned to normal operation and SGTS was shutdown and returned to standby at 23:46 hours EST on November 24, 2013. Preventive maintenance is being scheduled to inspect, and clean or replace the RBHVAC steam traps and strainers.

With Secondary Containment differential pressure exceeding -0.125 inches WC, TS Surveillance Requirement 3.6.4.1.1 was not met and Secondary Containment was declared inoperable. No other degradation of Secondary Containment existed at the time of the event. This event was reported per the guidance of NUREG-1022, Rev. 3, section 3.2.7, as a loss of Safety Function. There were no radiological releases associated with this event.

On January 22, 2013, at approximately 0113 hours EST, during startup of the Reactor Building Heating Ventilation and Air Conditioning (RBHVAC) system, with the Standby Gas Treatment System operating, Secondary Containment pressure went positive for 27 seconds, reaching approximately +0.15 inches of water column (WC).

The RBHVAC Center Exhaust Fan discharge damper appears to have opened after the Supply Fan discharge damper opened contrary to design, causing the Secondary Containment pressure increase. The System was returned to normal with two RBHVAC trains running and Standby Gas Treatment System shutdown and in standby. Reactor building pressure stabilized at less than -0.125 inches WC. The causes of this event appear to be delayed operation of the center RBHVAC exhaust fan discharge damper and relay timing out of tolerance for the RBHVAC Center Supply and Exhaust fan dampers. Work Management procedures are being followed to troubleshoot the actuator for the discharge damper and the supply and exhaust fan relay timing. This event has been entered into the Fermi 2 Corrective Action Program. Investigation continues and could result in additional corrective actions.

General Electric Company submitted a 10 CFR 21 notification identifying that they had determined that the stability Option III period based detection algorithm (PBDA) period confirmation adjustable variables (period tolerance and conditioning filter cutoff frequency) may be non-conservative, and recommended that the Average Power Range Monitoi (APRM) Operating Power Range Monitor - .

(OPRM) Upscale trip (Technical Specification Limiting Condition for Operation (LCO) 33.1.1, function 2.0 be considered inoperable for plants with a PBDA period tolerance setpoint less than 100 msec, and with a cutoff frequency of greater than 1.0 Hz. All OPRM channels were declared inoperable (but were maintained in a functional and armed condition) on October 2, 2003, because the Fermi-2 OPRM period tolerance was set at 50 msec, and the conditioning filter cutoff frequency was set at 3.0 Hz. Alternate methods to detect and suppress thermal hydraulic instability oscillations were placed into effect in accordance with Technical Specification LCO 33.1.1, Action J. The apparent deficiency was identified by General Electric (the OPRM and reactor vendor) following a July 24, 2003 instability event at Nine Mile Point-2. The Fermi OPRM settings would have been sufficient to identify a wide range of stability transients. Additionally, the operators have been trained to recognize instabilities and to take appropriate actions should an instability occur. The period tolerance and conditioning filter cutoff frequency setpoints were changed and all OPRM channels were declared operable on November 18, 2003. This event has been documented in the Fermi 2 corrective action program.

NRC FORM 368 (7.2o01)

On October 2, 2002, at 1453 hours, the reactor scrammed from 100 percent power. Condenser pressure increased when Circulating Water Pump (CWP) 2, one of four running CWPs, failed. Condenser pressure exceeded the main turbine trip setpoint. The main turbine tripped, resulting in a reactor scram.

Prior to the scram at 1452 hours the Circulating Water Header Low Pressure annunciator was received.

The Condenser Pressure High annunciator was received and control room operators (licensed, utility) entered the Abnormal Operating Procedure for Loss of Condenser Vacuum. The main turbine automatically tripped causing a reactor scram on main turbine control valve fast closure. All safety systems responded as expected. All rods fully inserted into the core. Reactor level decreased below Level 3, resulting in expected isolation signals. After the reactor scram, condenser vacuum recovered.

Reactor level was recovered with the Feedwater/Condensate System. No Emergency Core Cooling Systems initiated and no Safety Relief Valves lifted. The cause of the event was a failure of CWP 2.

This event is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A), as an event that resulted in manual or automatic actuation of any systems listed in paragraph (a)(2)(iv)(B), i.e., actuation of the Reactor Protection System including reactor scram or reactor trip. The cause of the CWP failure was fatigue failure of the diffuser casing to column bolts due to insufficient or loss of pre-load.

As a result of a fire protection program self assessment, on May 2, 2002, Detroit Edison Company determined that a field modification performed on February 19, 2002 invalidated an inherent assumption in the procedure for controlling the plant from the dedicated shutdown panel. Specifically, the motor operator for motor operated valve (MOV) N2000F636, Condenser Hotwell Emergency Makeup Bypass Valve, was rotated 180 degrees to help alleviate an oil leakage problem. Rotating the MOV relocated the motor operator handwheel away from the first floor of the Turbine Building such that operators could not reasonably close the valve without the use of a ladder. Procedure 20.000.18, "Control of the Plant from the Dedicated Shutdown Panel," directs operators to de-energize and manually close N2000F636 to prevent losing Condensate Storage Tank (CST) water inventory to the Hotwell, in case a hot short caused the valve to open. Losing CST inventory threatens the ability to achieve safe shutdown conditions in the event of a fire. Therefore, this condition is reportable under Section 2.F of the Fermi 2 Operating License as a violation of License Condition 2.C.(9).

Based on the short delay associated with obtaining a ladder and closing the valve, this condition did not result in any adverse effect on the health and safety of the public.

A dedicated ladder has been staged near the valve. Other corrective actions involve the identification of Appendix R components in the plant CECO database, additional training and guidance on dealing with Appendix R components, and periodic verification of the steps in procedure 20.000.18.

On September 28, 2001, Detroit Edison determined that a non-conservative bias existed in the reactor heat balance methodology for calculating core thermal power. Specifically, the main steam moisture carryover fraction used in the heat balance calculations was found to overestimate the actual moisture content of the steam. Due to this condition, it is possible that Fermi 2 exceeded its licensed power limits on one or more occasions; however, this bias represents an insignificant portion of the total thermal power (less than 0.1 percent) and is also small compared to the overall precision of the core thermal power evaluation. Exceeding the thermal power limit in Fermi 2 License Section 2.C.(1) is a reportable condition under Section 2.F. of the Fermi 2 Operating License.

Based on the low order of magnitude of the calculation bias and conservatism inherent in the power levels used for safety analyses, this condition did not result in any adverse impact on the health and safety of the public.

The moisture carryover fraction in the heat balance calculations will be revised to reflect the plant test data. As an interim measure, the maximum reactor power level was administratively reduced by three megawatt thermal.