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On November 14, 2017, it was identified that the use of the Reactor Protection System (RPS) test fixture described in some operations procedures would result in the loss of two RPS reactor Scram functions. Technical Specification 3.3.1.1 requires that RPS Instrumentation for Table 3.3.1.1-1 Function 5, Main Steam Isolation Valve-Closure and Function 8, Turbine Stop Valve-Closure, remain operable. It was concluded that a closure of three of four Main Steam Lines or Turbine Stop Valves would not necessarily have resulted in a full Scram during testing depending on the combination of closed valves occurring during the bypass condition. Operations procedures were revised to incorporate the use of the test fixture in December, 2008 for the Turbine Stop Valve Closure Scram Test Procedure and February, 2009 for the Main Steam Isolation Valve Closure Scram Test Procedure. The operations procedures were inappropriately revised to allow use of the test fixture on all RPS functions to prevent a half Scram.

The operations procedures were quarantined until revisions were issued in December, 2017 that removed use of the test fixture.

On June 19, 2017 following a planned High Pressure Coolant Injection (HPCI) system maintenance, a HPCI start attempt was performed per the quarterly test procedure. HPCI failed to start during the test due to the steam stop valve HO-7 not opening caused by HO-7 oil relay not functioning properly.

Since the component was not the subject of the maintenance activity, the HPCI failure was reported to the NRC under Emergency Notification System, Event Number 52814.

The HO-7 oil relay was repaired and the HPCI system was returned to operable status at 13:30 on June 23, 2017.

On April 15, 2017 at approximately 10:56 am, with the plant at 0% power in Mode 4 (Shutdown), while performing a plant shutdown procedure the "D" outboard Main Steam Isolation Valve (MSIV), AO-2- 86D was functionally tested. The Monticello Nuclear Generating Plant (MNGP) Technical Specifications (TS) Surveillance Requirement (SR) 3.6.1.3.6 requires that the isolation time of each MSIV is > 3 seconds and ime was measured at approximately 40.7 seconds. The valve was declared inoperable and subsequently repaired. The failure was attributed to the air pack pilot valves.

This component failure is reportable in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by TS 3.6.1.3 "Primary Containment Isolation Valves," since AO-2-86D may have been inoperable for greater than the TS 3.6.1.3, Required Action A.1, Completion Time of 8 hours to isolate a main steam line, and the Completion Time for TS 3.6.1.3, Required Action F, to be in Mode 3 in 12 hours and Mode 4 in 36 hours when the completion time of A.1 is not met. There were minimal safety consequences associated with the condition since the primary containment isolation function was maintained.

On November 27, 2016, the Monticello Nuclear Generating Plant (MNGP) was operating at 100% power. While troubleshooting was in progress for a minor leak on the High Pressure Coolant Injection System (HPCI) turbine, it was discovered that the HPCI turbine exhaust drain pot level switch was not functioning per design to support removal of condensate from the HPCI turbine. Subsequently, HPCI was declared inoperable at 1447 hours due to excessive water level within the HPCI turbine.

Previously, on November 17, 2016, a steam leak was identified on the packing of the HPCI turbine steam supply valve. Following valve packing maintenance on November 21, 2016, the valve was cycled cold (without steam flow), resulting in seat leakage that slowly admitted steam into the HPCI exhaust piping. The steam condensed to water and accumulation began to form in the HPCI turbine. Subsequent troubleshooting found the HPCI exhaust drain pot level switch electrical rocker assembly off its pivot point due to a manufacturer defect (missing spot weld). With the inability to pivot, the level switch became non-functional and thus failed to alert the control room and provide the automatic function to drain condensate from the HPCI exhaust piping. The HPCI exhaust piping was drained of condensate and a temporary modification replaced level switch. HPCI was restored to operable status at 1726 hours on December 1, 2016.

The High Pressure Coolant Injection (HPCI) system was inoperable during a pre-planned maintenance activity when a significant oil leak in HPCI system oil piping occurred because of a cracked oil pipe nipple.

The leak was of sufficient size that if it occurred outside the pre-planned maintenance, HPCI would have been declared inoperable. The equipment failure analysis concluded that the most likely cause was that HPCI pipe nipple was exposed to significant loads, sufficient to initiate a crack, likely from applied wrench torques during oil leak repair activities in 2005. With the presence of the crack and crack propagation mechanism, the engineering evaluation determined that HPCI was inoperable from January 9 through March 24, 2016, i.e. 75 days. The organizational root cause was that management and individuals were tolerant of leaks on the HPCI system. As a result, station personnel did not effectively advocate prompt repair of the HPCI oil leak.

The cracked HPCI oil pipe nipple was replaced. Results of the extent of condition review identified two other pipe nipples and two elbows with thread leakage (no crack present). The pipe nipples were replaced and the elbows were reused. The HPCI system was tested successfully after the repairs.

On November 23, 2015, a trip of the # 11 Reactor Recirculation Pump occurred, followed by a Group 1 isolation which resulted in a reactor scram. A post scram troubleshooting investigation determined a large spike in differential pressure occurred in the 'C' main steam flow instrumentation line at the time of the Group 1 initiation event.

The root cause of this event was determined to be legacy foreign material present in the 'C' main steam flow instrumentation line. This foreign material obstructed the instrumentation line and resulted in the momentary sensed high steam flow. The sensed high steam flow was not due to an actual high steam flow condition in the 'C' main steam line.

Since the presence of foreign material in the instrument line is a legacy issue, the corrective action for the root cause was to remove the foreign material. The corrective action for the trip of the reactor recirculation pump, will be to revise the fleet procedure to require verification of torque on accessible electrical connections for critical components which are bench tested and also to ensure that accessible soldered and crimped electrical terminations are inspected for sians of dearadation durina bench testina.

On June 24, 2015 during performance of turbine stop valve scram testing, the relay associated with the scram logic failed to de-energize as expected. Based on this failure to de-energize, stop valve 4 (SV-4) limit switch would not have contributed an input to the scram logic as designed.

The cause of the failure is unknown at this time but has been isolated to the limit switches through troubleshooting efforts. The limit switches are located in a high radiation area that precludes investigation during reactor operation. The fuse for the logic associated with SV-4 limit switch has been removed to meet Technical Specification requirements, thus there is a half subchannel trip in place on channels A2 and B2.

With the subchannels in trip, the likelihood of a scram is increased. The cause will be supplemented upon completion of investigation. A troubleshooting plan is in place to perform investigation of the limit switches at the next available opportunity.

On May 2, 2015, the Monticello Nuclear Generating Plant (MNGP) was in Mode 5 for a refueling outage.

During performance of surveillances of the non-credited 4kV essential Bus, MNGP experienced a loss of the 4kV Bus and essential Load Center due to an improperly landed jumper wire. Loss of the Load Center de- energized the valve position indication on the Residual Heat Removal (RHR) shutdown cooling inboard isolation valve, causing a subsequent trip of the RHR pump operating in shutdown cooling on a pump suction interlock and a loss of normal shutdown cooling. Control Room operators entered the appropriate abnormal procedures and verified alternate decay heat removal was in service until shutdown cooling could be restored.

Immediate corrective actions included suspension of all work pending approval of the shift manager to ensure outage activities did not further degrade plant conditions and electrical work was limited to protect shutdown cooling. The essential Load Centers were cross tied to restore normal shutdown cooling.

Corrective actions include revising procedures to reinforce human performance tools, adequately assess risk involved with electrical work, and ensuring effective barriers are in place to harden residual heat removal function durina shutdown conditions.

On April 23 and 25, 2015, during planned Reactor Recirculation System modifications and maintenance, the provisions of NRC Enforcement Guidance Memorandum (EGM) 11-003 (Revision 2) were invoked for Operations With a Potential to Drain the Reactor Vessel (OPDRV) in noncompliance with Technical Specification (TS) 3.6.4.1, "Secondary Containment." These conditions are being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as an operation or condition prohibited by the TS that is under enforcement discretion as specified in EGM 11-003.

The safety significance of these noncompliances is minimal as EGM 11-003 specifies interim actions that provide an adequate level of safety. Implementation of EGM 11-003 for these actions was a planned activity and as such, no cause determination was performed for the events. Following development of a Technical Specification Task Force traveler a license amendment request will be submitted to resolve this issue as required by EGM 11-003.

On May 15, 2014, an unsealed conduit penetration was identified between two fire zones, Division I and Division II of safe shutdown equipment in the Emergency Filtration (EFT) Building, which does not meet the two hour fire barrier rating of the wall required per the Fire Hazards Analysis.

The cause of the unsealed penetration is unknown and is considered a legacy issue as this conduit was routed prior to 1991.

The EFT fire protection barrier will be restored to functional status and the penetration will be periodically inspected. The Fire Barrier Wall, Damper and Floor Inspection procedure will be revised to add use of additional tools (e.g., cameras or boroscope) to perform inspections on portions of fire barriers that are not easily accessed.

On March 28, 2014, two secondary containment doors in the main access airlock were opened at the same time. With both doors open, Technical Specification Surveillance Requirement 3.6.4.1.3 was not met and secondary containment was declared inoperable. Interviews with individuals involved indicate the doors were open for approximately two seconds.

The cause was determined to be plant employees do not have secondary containment airlock training, and the airlock interlock did not have posted operating instructions.

Corrective actions include affixing permanent labels next to the interlock push button which provide instructions on how to appropriately open the doors. As an additional measure, plans are in place to replace the doors with doors that have windows. The need for training on proper airlock operation will also be evaluated for inclusion in general access training.

On February 10, 2014, Monticello personnel identified that the Emergency Diesel Generators (EDGs) would not energize permanently connected loads until 10.2 or 10.34 seconds for Division I and Division II, respectively, which exceeded the 10 second limitation of Monticello Technical Specification (TS) Surveillance Requirement (SR) 3.8.1.12. As a result, both EDGs were declared inoperable.

The apparent cause of this event is that the description of the EDG TS SR was inadvertently changed during transition from custom TS 4.9.B.3 to improved TS SR 3.8.1.12 due to improper verification and validation practices of the Improved TS preparation team in 2004-2006.

The set-points for the applicable relays have been revised. The time delay set-point change provides a setting to support EDG performance meeting the 10 second acceptance criterion of SR 3.8.1.12. Additionally, the surveillance procedure will be revised as necessary to implement correct testing for SR 3.8.1.12.

On February 7, 2014, while performing the monthly torus to drywell vacuum breaker check procedure, vacuum breaker valve AO-2382A did not indicate closed as expected. The valve was cycled several times per an alarm response procedure for an open torus to drywell vacuum breaker until it indicated closed.

A causal evaluation has determined the cause of the observed indication for vacuum breaker valve AO-2382A after cycling to be interference between the vacuum breaker test lever and vacuum breaker test actuator stem.

This interference was introduced during the 2013 refueling outage when the lever arm was removed for seal replacements. The procedural guidance was not detailed enough to ensure the critical clearances were maintained during removal and replacement of the test lever. The condition was, resolved during the 2015 outage by establishing proper clearances between the test lever and actuator stem for all torus to drywell was removed. In addition, a revision to the torus to drywell vacuum breaker seal replacement procedure was made to ensure proper clearance between the test lever and test actuator stem would be maintained following maintenance activities.

On May 24, 2013, during performance of 4kV load testing on the new 2R-Transformer, operations was unable to observe red light indication for a 4 kV breaker either locally or in the Control Room following closure of the breaker. The lack of red light indication with the breaker closed is indication that the breaker will not be able to be tripped electrically, thus rendering all breaker protective trips and remote tripping from the Control Room unavailable. This resulted in the operators taking procedurally directed action to trip the breaker manually using the mechanical trip button, leading to the Essential Bus transfer. At the time, all credited safety systems were lined up to Division 2-4kV Essential Bus which was not affected by the event, as a defense-in-depth measure.

The apparent cause of the event was damage to a 4kV breaker which was the result of inadequate protection of the breaker during temporary storage.

A spare breaker was successfully tested and installed. Other breakers in temporary storage were inspected for potential damage. The long term corrective action is to revise the operations manual to provide additional guidance regarding the appropriate storage of breakers and to specify items requiring inspection prior to installation into switchgear cubicles.

At approximately 0900 CDT on May 8, 2012, it was determined that the Monticello Nuclear Generating Plant did not meet Technical Specification (TS) Limiting Condition for Operation 3.3.8.1 because the requirement of Table 3.3.8.1-1 for the 4.16 KV Essential Bus Degraded Voltage function time delay transfer to the Emergency Diesel Generators (EDGs) of The degraded voltage transfer scheme has the ability to transfer to a standby offsite source (1AR Transformer) which, under a degraded voltage condition, would delay the transfer to the EDGs an additional 5 seconds. Both EDGs were subsequently declared inoperable.

During the development of the 1980's modification that added the 1AR time delay degraded voltage requirements, the TS submittal did not include the total time delay required to disconnect the Essential Buses from all Offsite Sources.

The interim corrective action was to remove 1AR Transformer from service which disabled the additional 5 second degraded time delay and restored TS compliance. A license amendment request has also been submitted which, pending NRC approval, would remove the 5 second time delay for 1AR Transformer and directly transfer the Essential Buses to the EDGs under a degraded voltage condition. This would allow 1AR Transformer to be returned to service.

On November 27, 2011, while performing the Rod Worth Minimizer (RWM) Operability Test as part of startup activities, it was discovered that the RWM control switch was in Bypass. With the control switch in the Bypass position, the RWM was inoperable and did not enforce the pre-determined control rod withdrawal sequence.

The RWM control switch was restored to the Operate position and the RWM was verified to be operable.

The apparent cause was determined to be the crew failed to precisely identify the sequence of surveillances/procedures required to be completed, prior to the mode change. The pre-job brief was inadequate in that the specific sequence and details were not discussed and the licensed operators on duty failed to identify that the RWM configuration did not support the mode change. Additionally, control room indications available to the operators were not properly utilized to prevent the out of sequence control rod withdrawal.

At 1250 on October 21, 2011, at the Monticello Nuclear Generating Plant, a 2R Auxiliary Transformer lockout unexpectedly occurred causing off-site power to automatically transfer to the 1R Auxiliary Transformer, which resulted in a reactor scram.

One cable of the "A" phase conductor, supplying power from 2RS to 2R Transformer, faulted to ground, resulting in the 3N4 breaker opening, as designed, to protect 2RS Transformer and other equipment from fault current damage. Subsequent testing indicates the cable suffered from environmental and age-related degradation.

Implementation efforts to replace the cables between 2R Transformer and 2RS Transformer were in progress at the time of the event. A portion of the new raceway was under construction.

The cables were replaced entirely employing a route designed to avoid cable submergence in water.

Subsequent to installation, cables were successfully tested and returned to service.

On September 2, 2011, at approximately 1600, Mechanical Maintenance personnel informed Operations that portions of the Intake Structure sprinkler system piping were found to be partially blocked and incapable of passing flow. The Intake Structure sprinkler system is relied upon in part to satisfy an approved exemption to 10 CFR 50 Appendix R, Section III.G.2.b concerning separation of components in the Intake Structure.

Installation of the Intake Structure sprinkler system in 1983 did not comply with design requirements for providing required pipe slope to ensure proper draining. This condition allowed excessive water to remain in the system which then contributed to accelerated internal corrosion and accumulation of corrosion byproducts in the piping system.

Immediate corrective actions taken included flushing the sprinkler system and performing internal inspections to confirm removal of blockage before returning the system to service.

On June 8, 2011 at 0800, with the reactor operating at 100% power, secondary containment (SCT)(NG) was declared inoperable after swapping the operating refuel floor supply air handling unit from V-AH-4A(AHU) to V-AH-4B. SCT differential pressure (D/P) was reduced to 0.17 inches of water column (WC) vacuum, which did not meet Technical Specification (TS) surveillance requirement SR 3.6.4.1.1 to maintain secondary containment vacuum greater than or equal to 0.25 inches WC vacuum. Refuel floor ventilation was restored to the previous configuration and secondary containment D/P returned to greater than 0.25 inches of WC vacuum. Vacuum was less than 0.25 inches WC vacuum for approximately 4 minutes.

The event was caused by a change in supply air flow rates between V-AH-4A and V-AH-4B when swapped.

Corrective actions include repairing a seized bypass damper (CDMP) on V-AH-4A and a procedure change to add precautions to the operating procedure for transferring refuel floor fans.

NRC FORM 266 (10-2010)

During the review of Nuclear Instrument surveillances, plant personnel discovered that the current method of isolating the flow transmitter isolation valves for the Average Power Range Monitor (APRM) Recirculation Flow Instrumentation resulted in a condition that could � .

momentarily prevented a flow bias scram signal in the trip system being tested. This event was the result of an incorrect procedure revision performed in 1992. � ,

While operating at 100% power at 1727 on March 22, 2002, an automatic Group 3 containment isolation signal was generated after sensing high Reactor Water Cleanup (RWCU) system flow. At the time, operations personnel were in the process of restoring the RWCU system to service following investigation of leakage associated with filter demineralizer isolation valves.. The re-performance of the filling and venting portion of the restoration procedure was not performed, because personnel failed to realize that during the investigation process voids had been created within the system.

When repressurizing the system, high flow rates resulted in actuation of the protection logic. Following resolution of these issues and completion of maintenance, the RWCU system was pressurized and returned to service at 0310 on March 24, 2002.