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On December 28, 2016, at 2119 hours (EST), standby liquid control (SLC) subsystem A was declared inoperable in accordance with the surveillance instruction for performance of a routine surveillance test. At 2229 hours, control room operators received an out-of-service alarm for SLC discharge valve B. With both subsystems inoperable, the SLC system was in a condition that required reporting under 10 CFR 50.72(b)(3)(v)(A) and 10 CFR 50.72(b)(3)(v)(D). At 2335 hours, the surveillance was completed and subsystem A was declared operable.

The cause for subsystem B inoperability was an indicated loss of continuity to one of the two firing circuits in the discharge valve due to a loose connection between a pin and jack on the connector. This was not a safety system functional failure since continuity was interrupted to only one of the two redundant firing circuits for discharge valve B and if an initiation signal was sent to the valve, it would have operated as designed and supported chemical injection to the vessel. The risk of this event is considered small in accordance with the regulatory guidance. The power supply cable was replaced and post maintenance testing was completed satisfactorily. The preventative maintenance task will be revised to include a step to inspect connection pins and jacks when changing the firing assembly. Additionally, the cable on the discharge valve for SLC subsystem A will be replaced and sent to FirstEnergy BETA Laboratory for analysis when the valve is replaced during the next refueling outage.

The analysis will be used to determine if a new preventative maintenance task is necessary for periodic replacement of these cables.

On June 2, 2009, during performance of the monthly surveillance on the Unit 2/3 Emergency Diesel Generator (EDG), an oil leak of approximately one-half gallon per minute was identified at the threaded pipe plug in the center of the turbocharger lube oil system "Y" strainer end cap. Following identification of the leak, the EDG was unloaded and shut down normally. The threaded plug was then replaced and was found to be a black 3/8 inch plastic shipping plug typically installed for Foreign Material Exclusion (FME) purposes.

The Unit 2/3 EDG was considered to be inoperable from April 16, 2009 to June 2, 2009, with associated actions required by the plant's Technical Specifications not being completed. Also, concurrently with the and Unit 3 EDGs. This minimally impacted the ability of onsite emergency power to fulfill its safety function.

The Root Cause of this event was determined to be inadequate purchase order description. The corrective actions to prevent recurrence include revision of the purchase order description of the "Y" strainer to specify a pressure retaining pipe plug of appropriate material.

On January 18, 2007, at 2110 hours (CST), with Unit 2 at approximately 100 percent power, Dresden Standby Liquid Control System Tank temperature switch well. The Unit 2 Standby Liquid Control System was declared inoperable and Technical Specification 3.1.7, "Standby Liquid Control System," was entered.

The repair to the tank could not be completed within the allowed Completion Time of Technical Specification 3.1.7 and Dresden Nuclear Power Station requested a Notice of Enforcement Discretion to allow Unit 2 to remain at power during the repair. The NRC granted the Notice of Enforcement Discretion on January 19, 2007. The system was restored to operable status by encapsulating the cracked component on January 20, 2007 at 0015 hours (CST) within the time allowed by the Notice of Enforcement Discretion.

The cause of the event was the result of transgranular stress corrosion cracking that initiated from the threaded inner diameter of the Type 304 stainless steel 1 inch to 3/4 inch Hex-Reducing bushing.

On September 6, 2003 at 1151 hours, the safety-related train 'A' 480-volt load center and the related motor control centers (MCCs) powered from the load center de-energized. The event resulted in several systems including the high pressure coolant injection and the reactor core isolation cooling systems becoming inoperable. The train '8' 480-volt load center and related MCCs were unaffected.

The affected load center and related MCCs were re-energized by 0022 hours and the affected systems were returned to service by 1000 hours on September 7, 2003.

The direct cause of the event was the unplanned trip of the circuit breaker that powers the load center.

The root cause investigation revealed the circuit breaker tripped due to a malfunction of one of the breaker's three current transformers.

Corrective action included the replacement of the circuit breaker. Corrective action planned includes analysis of the current transformer malfunction and related actions to preclude recurrence.

The event posed no threat to public health and safety.

On January 19, 2001, following a request by the NRC resident inspector for work documentation related to a snubber replacement on the High Pressure Coolant Injection (HPCI) system, the Monticello plant staff became aware that the requisite NIS-2 form had not been generated as required by paragraph IWA-7520 of the 1986 Edition of the ASME Code Section Xl.

Further investigation revealed repair and replacement plans and NIS-2 forms had not been generated for replacement activities involving other ASME Code Section XI snubbers and safety-relief valve topworks.

1 Monticello Technical Specification 3.15.A requires that components in quality groups A, B, and C (Class 1, 2, and 3) be declared inoperable if they do not comply with requirements of ASME Section Xl.

1 On January 24, 2001, the Limiting Condition for Operation (LCO) described in Technical Specification Section 3.15.A was entered for the snubbers not meeting code requirements. The snubbers were considered inoperable. Technical Specification 3.6.H was entered which allows 72 hours to perform an engineering evaluation to demonstrate snubber acceptability. On January 25, 2001, it was determined the LCO should have been entered on January 19, 2001, when the problem was first identified.

On January 29, 2001, safety relief valve (SRV) topwork replacements were found to have been performed without complying with code requirements. Therefore, the SRVs were declared inoperable and Technical Specification LCO 3.6.E.2 was entered. A Notice of Enforcement Discretion was requested and verbal approval granted on January 30, 2001. This LER supplement addresses items found after the original reported items.