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 Report dateSiteEvent description
05000370/LER-2017-00126 June 2017McGuire

On February 23, 2017, at 19:22 hours, with Unit 1 and Unit 2 operating at approximately 100 percent power, operators commenced a Unit 2 shutdown upon discovery of pressure boundary leakage on Unit 2 Safety Injection (NI) pipe upstream of the connection to "D" Reactor Coolant System (NC) Cold Leg. During a containment walk down inspection in Mode 3 on the next day, a pinhole pressure boundary leak was observed in the body of 2NC-30, Pressurizer Spray Bypass Valve.

The cause of the NI pipe leak is thermal fatigue damage caused by NC cross-loop flows. The cause of the 2NC-30 valve leak is a casting flaw attributed to a combination of defects during the manufacturing process that resulted in a through wall pinhole leak in the valve body. The NI pipe with the flaw and the valve with the pinhole leak could have structurally performed their design functions. Therefore, the health and safety of the public were not affected by these events.

Valve 2NC-30, the NI pipe, and leaking B-Loop NI check valves were replaced. Thermal cycling monitoring and mitigation devices were installed on Unit 2 and will be installed on Unit 1 during the next refueling outage.

05000369/LER-2016-00122 July 2016McGuire

On March 22, 2016, while Unit 1 was in end of cycle (EOC) refueling outage 1E0C24 (Mode 5), a manual ultrasonic (UT) examination of the Chemical and Volume Control System (NV), Charging Line to the 1A Reactor Coolant System (NC) cold leg confirmed a previously identified circumferential indication associated with weld 1NC1F-1374. The current examination results had shown that the indication had changed since the previous examination during 1E0C23 and concluded that the indication no longer met American Society of Mechanical Engineers (ASME) Section XI Code requirements. This condition is reportable under 10CFR50.73(a)(2)(ii)(A) as a degraded condition.

A specific cause for the condition could not be determined. A metallurgical examination concluded that the cause of the UT result could have been influenced by pre-existing welds associated with a legacy modification.

The affected NV piping on Unit 1 was replaced during refueling outage 1E0C24.

APPROVED BY OMB: NO. 3150-0104 EXPIRES: 01/31/2017 Reported lessons learned are incorporated into the licensing process and fed back to industry.

Send comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by internet e-mail to infocollects, and to the Desk Officer, Office of Information and Regulatory Affairs, NEOB-10202, (3150-0104), 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.

05000370/LER-2015-0017 December 2015McGuire

On October 7, 2015, an actuation of the Auxiliary Feedwater (CA) system occurred while Unit 2 was in Mode 4 and operators were restoring from testing of the 2A Solid State Protection System (SSPS) Safety Injection (SI) trip functions for the Main Turbine and the Main Feedwater (CF) pump turbines. The CA actuation caused the 2A CA Train flow control valves to fully open and the associated steam generator (SG) sampling and blowdown valves to close. The actuation occurred as designed, and there was no adverse impact to plant operation.

At the time of the CA actuation, the CF pumps were shut down and SG levels were being maintained by the 2A and 2B Motor Driven CA Pumps (MDCAP)s. During restoration from SSPS testing, a conditional step in the procedure did not clearly require the reset of at least one CF pump. Leaving both CF pumps in the tripped state provided the logic for the CA actuation signal. The actuation occurred when the 2A Train CA auto start defeat switch was placed in "reset" as directed by the test procedure. To prevent the CA actuation, the test procedure should have ensured that at least one CF pump was in "reset" before the 2A CA Train auto start defeat switch was placed in "reset".

Procedures PT/1/A/4200/026A and PT/2/A/4200/026A will be revised to clearly define the CF pump as found and restoration configuration based on actual plant conditions.

APPROVED BY OMB: NO. 3150-0104 EXPIRES: 01/31/2017 Estimated burden per response to Comply with this mandatory collection request: 80 hours.

Reported lessons learned are incorporated into the licensing process and fed back to industry.

Send comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by internet e-mail to infocollects, and to the Desk Officer, Office of Information and Regulatory Affairs, NEOB-10202, (3150-0104), 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.

05000369/LER-2014-00117 December 2014McGuire

On August 18, 2014, approximately 14 hours into a 24 hour surveillance test of Emergency Diesel Generator (EDG) 1B, Operators noted cylinder 5L exhaust temperature decreased by 130 degrees Fahrenheit and power indication began oscillating. Operations began an orderly shutdown of EDG 1B. Subsequently, Operators in the diesel room reported an unusual noise, at which time Operations immediately unloaded and stopped EDG 1B.

EDG 1B was subsequently repaired and tested satisfactorily. This event is being reported under 10 CFR 50.73(a)(2)(i)(B) as an operation or condition which was prohibited by the plant's Technical Specification due to EDG 1B repair and testing exceeding the 72 hour completion time as mandated by TS 3.8.1.

On August 21, 2014, McGuire Unit 1 requested a Notice of Enforcement Discretion (NOED) in anticipation of exceeding TS 3.8.1 "AC Sources - Operating" Required Action Completion Time. The NOED was granted by the NRC on the same day.

The cause of the EDG 1B cylinder 5L failure is high cycle fatigue of the inlet valve due to the combined effects of three inlet valve train parts which were manufactured outside of original equipment manufacturer (OEM) specified tolerances. Procurement of the applicable parts has been placed on hold until the parts specification is revised.

05000369/LER-2014-00224 November 2014McGuire

While Unit 1 was in a refueling outage on September 26, 2014, manual ultrasonic (UT) examinations identified indications on Safety Injection (NI) system piping. On September 27, phased-array UT techniques confirmed two indications as rejectable flaws. Because the flaws were rejectable under American Society of Mechanical Engineers (ASME) Code requirements, this event is reportable as a degraded condition in accordance with 10CFR50.73(a)(2)(ii)(A). Stress analysis showed that the cracks would not have prevented the piping from performing its safety function, so this event did not impact public health and safety.

The cause of both flaws is a legacy issue of previous leakage past valve 1NI-3 (Unit 1 Cold Leg Injection Isolation) creating a high frequency thermal cycle condition. When combined with original construction deficiencies in the affected lines, this condition initiated the fatigue cracks identified during the UT examinations.

Actions were taken to repair the NI piping on Unit 1 and to inspect other susceptible lines before the unit restarted from its refueling outage. As part of planned corrective actions, valves with the potential to cause cold water in-leakage to these lines will be monitored for leakage.

Reference previous McGuire Unit 2 LER 370/2014-01, Revision 1, dated July 24, 2014.

05000369/LER-2013-0036 March 2014McGuire

On November 14, 2013, at 13:13, Unit 1 was manually tripped from 100% power due to 10 dropped control rods associated with Rod Control Power Cabinet 1AC. The remaining control rods fully inserted into the core following the manual reactor trip. Unit 1 was stabilized in Mode 3 at normal operating temperature and pressure. The motor-driven Auxiliary Feedwater Pumps 1A and 1 B were manually started for steam generator level control. This event did not impact public health and safety.

The cause of the event was an inadequate modification, resulting in an over-voltage protection (OVP) setpoint too close to the normal output of both the primary and backup -24 VDC rod control power supplies. The design called for the OVP function to be implemented with an installed jumper configuration that set the OVP setpoint too close to the normal output voltage.

Actions were taken to replace other Unit 1 power supplies with available power supplies that will not shut down under similar conditions. Due to limited spares, immediate replacement was limited to all applicable primary supplies and two backup supplies on Unit 1. The remaining backup power supplies installed in Unit 1 and the susceptible Unit 2 power supplies will be replaced as part of the planned corrective actions.


05000369/LER-2013-00212 August 2013McGuire

During a review of pressure switch (PS) setpoints, it was determined the calibration procedure for Unit 1 Auxiliary Feedwater System PS 1CAPS5390 utilized a water leg value that did not reflect the actual water leg value in the field. This water leg error resulted in a non-conservative 1CAPS5390 actuation setpoint outside the limits required by Technical Specification (TS) 3.3.2, "Engineered Safety Feature Actuation System (ESFAS) Instrumentation", which rendered this PS inoperable. 1CAPS5390 actuates on a Unit 1 Turbine Driven Auxiliary Feedwater Pump (TDCAP) suction pressure - low condition to align the safety related assured water source to this pump. With 1CAPS5390 inoperable, TS 3.3.2 requires the PS be returned to an OPERABLE status within 48 hours or the Unit 1 TDCAP be declared inoperable. Since the inoperable condition with 1CAPS5390 was unknown, the applicable TS Required Actions were not completed within the specified Completion Times.

With this condition, 1CAPS5390 would still have actuated and aligned the safety related assured water source to the Unit 1 TDCAP in time to support the pump's safety function. Therefore, this event was not safety significant.

The cause of this event is weaknesses in the McGuire Nuclear Station (MNS) program for measuring and calculating water leg setpoint corrections. This resulted in the use of an incorrect water leg value for 1CAPS5390.

MNS implemented a modification to correct the 1CAPS5390 setpoint based on actual waterleg value for this PS. The MNS program for determining water legs will be revised to address identified weaknesses.

Applicable procedures will be revised.

05000369/LER-2013-00122 April 2013McGuire

turbine trip signal initiated after operating main feedwater system (CF) pumps tripped. The CF pumps tripped as a result of the operating Condensate Booster Pumps (CBPs) tripping on emergency low suction pressure following an inadvertent trip of the 1C3 Heater Drain Tank (HDT) Pump. The 1A and Turbine Driven Auxiliary Feedwater System (CA) pumps automatically started (Engineered Safety Feature actuation) as designed following the CF pumps tripping. The 1B CA pump was removed from service prior to the event to support maintenance.

The 1C3 HDT Pump was inadvertently tripped by an operator investigating the cause of an extinguished "on" indicating light bulb which is part of the HDT pump start/stop pushbutton switch. The cause of the HDT pump trip was attributed to an administrative procedure that did not explicitly prohibit intrusive investigation of light bulbs having transient/trip potential. The HDT pump trip caused a secondary system pressure transient that resulted in premature tripping of the CBPs which ultimately led to the reactor trip and CA pump auto-start. The CBP trip was caused by inadequate venting of CBP Suction Header Pressure Switches (PS) and an accumulation of air voids in PS process tubing due to an inadequate slope configuration.

Immediate actions were taken to revise an administrative procedure to prevent intrusive investigation of bulbs having transient/trip/ potential. The slope of process tubing to the CBP suction header PSs was corrected and the PSs were vented, calibrated, and verified functional. Planned action will be taken to ensure the condensate system (CM) is filled and vented and a hotwell pump is running prior to venting the CBP suction header PSs.

05000370/LER-2011-00316 February 2012McGuire

On December 20, 2011, it was determined the 2B Annulus Ventilation (AVS) Filter Train heater did not meet the acceptance criteria of the Ventilation Filter Testing Program (VFTP) heater dissipation test in accordance with Technical Specification (TS) Program 5.5.11 and Surveillance Requirement (SR) It was subsequently determined that the 2B AVS heater was in this condition and inoperable from October 29, 2011 until December 10, 2011. This inoperability time exceeded the Completion Times of TS 3.6.10 Condition B. This event was not safety significant because the AVS heaters are not required or credited for the operability of the AVS Filter Trains.

The causes of this event were insufficient troubleshooting after the 2B AVS heater breaker trip on October 29, 2011 and incorrect acceptance criteria in the AVS Filter Train Operability Test procedure.

Immediate action was taken to replace the 2B AVS heater and test per the VFTP requirements. Subsequent action was to revise the acceptance criteria of the AVS Filter Train Operability Test procedures.

The planned corrective action is to clearly delineate the Operations Procedure requirements for restoring inoperable systems and components to operable status.

05000369/LER-2005-00218 January 2006McGuire

Unit Status: At the time of the event, Unit 1 was in MODE 4 (Hot Shutdown) at 0 percent power.

Event Description: In April 2004, stroking of 1SM-1 ("D" Steam Generator Main Steam Isolation Valve (MSIV)) introduced valve stem scoring. This scoring was indicative of conditions which probably prevented the valve from fully closing. The inability to close renders 1SM-1 inoperable. Since the applicable Technical Specification required actions and completion times were not satisfied, this represented a Technical Specification prohibited operation reportable as per the requirements of 10 CFR 50.73 (a)(2)(i)(B). This event was not significant with respect to the health and safety of the public.

Event Cause: The most probable cause was high valve friction due to main poppet tipping and plowing of the guide rib, actuator to stem misalignment, stem side loading and abnormal packing friction.

Corrective Action: The guide ribs for 1SM-1 were repaired and returned to specifications. A new valve main poppet was installed along with an anti-vibration kit and a stem guiding system with carbon bushing and packing material which will not induce a corrosive environment. The clearance between the valve stem and cover bushing was also increased. The air assist feature has also been installed to provide additional closing margin on Unit 1 MSIVs during Refueling Outage 1EOC17.

05000369/LER-2002-00225 November 2002McGuire

Unit Status: At the time of the event, Unit 1 was in Mode 6 (Refueling) and Unit 2 was in Mode 1 (Power Operation) at 100 percent power.

Event Description: On October 1, 2002, while conducting Engineered Safety Features (ESF) testing on DG 1B, the DG output breaker unexpectedly tripped open, causing a blackout on the 4kV Essential lETB bus. The load sequencer and DG 1B responded accordingly to re-energize the bus and connect the blackout loads to the bus. The redundant 4kV Essential lETA bus remained operable during the event. This event did not compromise the health and safety of the public.

Event Cause: The root cause of the blackout event was failure of the Cutler-Hammer (C-H) pushbutton control switch for the DG output breaker due to its contact block plunger stuck in the depressed position.

Corrective Action: The failed switch was replaced. Other Category "A" (high safety significant and/or critical to production) C-H Model E30 control switches that are constructed with dual-circuit contact blocks with at least one normally-closed contact will be replaced with contact blocks manufactured after 1979.