Semantic search

On July 3, 2017, at approximately 10:15 AM following a grid disturbance, a manual scram was inserted due to degrading main condenser vacuum because of an improper configuration of the Augmented Off-gas (AOG) System.

The loss of main condenser vacuum resulted when Operations personnel failed to execute procedural requirement to align the AOG system into a shutdown lineup. The loss of vacuum was caused by degraded Steam Jet Air Ejectors (SJAE) performance due to a blocked discharge path.

The AOG system tripped 11 hours earlier following a grid disturbance. During the trip, operations personnel failed to re-align the AOG treatment system to a shutdown lineup resulting in the AOG Flame Arrestor siphoning into the inlet piping which filled the lower section of the off-gas hold up line with water.

On June 17, 2016, at 0256 Central Daylight Time, Grand Gulf Nuclear Station experienced an automatic reactor SCRAM. Prior to the SCRAM, Grand Gulf Nuclear Station was operating in Mode 1 at approximately 65% rated thermal power and performing the Turbine Stop and Control Valve Operability Surveillance. During the surveillance, after the 'B' Turbine Stop valve was closed per procedure, the 'D' Turbine Stop Valve unexpectedly closed. The 'A' and 'C' Turbine Control Valves were then challenged to control Turbine and Reactor pressure resulting in Reactor pressure and power oscillations. Attempts were made to reset the 'B' Turbine Stop Valve followed by power reduction. While driving rods to reduce power, an automatic Reactor SCRAM was received at 0257 on a Neutron Monitoring System Oscillation Power Range Monitoring trip. A reset solenoid valve initiated the event due to a malfunction after it was actuated per the surveillance procedure. The solenoid valve remained in the tripped position during the surveillance which allowed the trip header pressure to be inappropriately vented triggering closure of the 'D' stop valve. The solenoid valve was replaced prior to startup. The root cause is still under investigation. This event posed no threat to public health and safety.

APPROVED BY OMB: NO. 3150-0104 EXPIRES: 10/31/2018 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.Resource@nrc.gov, 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 collection.

366A U.S. NUCLEAR REGULATORY COMMISSION

CONTINUATION SHEET

2. DOCKET 3. LER NUMBER 05000 416

NO

PLANT CONDITIONS PRIOR TO THE EVENT

At the time of the event, Grand Gulf Nuclear Station (GGNS) Unit 1 was in Mode 1 at approximately 65% rated thermal power due to a planned power reduction to complete a Control Rod sequence exchange, Steam Jet Air Ejector (SJAE) swap, Cooling Tower acid flush, and Main Turbine Stop and Control Valve Operability Surveillance. All systems, structures and components that were necessary to mitigate the consequences of, or limit the safety implications of an event were available. No safety significant components were out of service.

DESCRIPTION

On June 17, 2016, GGNS was in Mode 1 at approximately 65% rater thermal power performing the Main Turbine Stop and Control Valve Operability Surveillance. During the surveillance, the 'B' Turbine Stop Valve was closed, as directed by the surveillance procedure. While the 'B' Turbine Stop Valve was closed, the 'D' Turbine Stop Valve unexpectedly closed, resulting in a Division II Reactor Protection System (RPS) half SCRAM signal.

With the 'B' and 'D' Turbine Stop Valves closed, the remaining 'A' and 'C' Turbine Control Valves were challenged to precisely control Turbine and Reactor pressure. This resulted in Reactor pressure and power oscillations. Although oscillations were occurring, Reactor pressure and water level maintained margin to SCRAM setpoints.

Multiple attempts were made to reset the 'B' Turbine Stop Valve followed by power reduction. While driving rods to reduce power, the Reactor received an automatic SCRAM at 0257 on a Neutron Monitoring System Oscillation Power Range Monitoring (OPRM) trip.

REPORTABILITY

This Licensee Event Report (LER) is being submitted pursuant to Title 10 Code of Federal Regulations (10 CFR) 50.73(a)(2)(iv)(A) for an automatic actuation of the RPS.

Telephonic notification was made to the U.S. Nuclear Regulatory Commission (NRC) Emergency Notification System on June 17, 2016, within 4 hours of the event pursuant to 10 CFR 50.72(b)(2)(iv)(B) and 10 CFR 50.72 (b)(3)(iv)(A) for a valid RPS actuation while the reactor was critical.

APPROVED BY OMB: NO. 3150-0104 EXPIRES: 10/31/2018 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.Resource@nrcgov, 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 collection.

NRC FORM

366A U.S. NUCLEAR REGULATORY COMMISSION

CONTINUATION SHEET

CAUSE

2. DOCKET 3. LER NUMBER 05000 416

NO

Direct Cause: The reset solenoid valve 1N32F514C initiated the event due to a malfunction after it was actuated per the surveillance procedure. The actuation of this reset solenoid valve triggered the loss of trip fluid pressure, and subsequent closure of the `D' stop valve. During initial investigation, the solenoid valve was found to have remained in the tripped position during the surveillance which allowed the trip header pressure to be inappropriately vented.

Root Cause: Investigation of the root cause is ongoing. A supplemental report to this LER will be provided upon completion of the root cause investigation.

CORRECTIVE ACTIONS

The immediate corrective action was to replace both the 1N32F514C and 1N32F515C solenoid valves.

SAFETY SIGNIFICANCE

The event posed no threat to the health and safety of the general public or to nuclear safety as RPS performed as designed. No Technical Specification safety limits were violated. Industrial safety was not challenged, and there was no potential or actual radiological release during the event.

PREVIOUS SIMILAR EVENTS

Previous similar events will be discussed in the supplemental report upon completion of the root cause investigation.

On May 25, 2014, with Unit 4 at approximately 20% reactor power during a shutdown to repair an unrelated equipment issue, an automatic reactor trip occurred due to low condenser vacuum. The transfer of steam supply to the gland sealing steam system from the Unit 4 main steam system to the Unit 3 auxiliary steam system while the unit was on-line caused the decrease in main condenser vacuum. Main condenser vacuum reached the turbine trip setpoint, which resulted in the automatic reactor trip. Trip response was uncomplicated.

The root cause was operations personnel did not adequately address the integrated system status as part of the decision making process used to realign the steam supply to the gland sealing steam system. Corrective actions include: 1) Revising procedural guidance to specify that steam supply to the gland sealing steam system cannot be transferred from the main steam system to the auxiliary steam system with a unit in Mode 1 or 2, and 2) Providing training to all licensed operators to demonstrate the integrated system response aspect of risk-based decision making.

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 (1-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by intemet e-mail to Infocollects.Resource©nrc.gov, 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.

Switch (RMSS) in "Startup/Hot Standby", the turbine generator previously removed from service, and the reactor sub- critical on Intermediate Range Monitors Range 2 and lowering, a manual reactor scram was inserted due to reactor pressure decreasing faster than normal. At the time of the manual reactor scram PNPS was conducting a planned reactor shutdown to commence refueling outage (RFO) -19. All control rods fully inserted and Primary Containment Isolation System (PCIS) Group II (Reactor Building) and Group VI (Reactor Water Cleanup System) actuations occurred as designed due to the expected reactor water level shrink associated with the scram signal. All plant systems responded as designed. Off-site power was unaffected and was supplied by the start-up transformer (normal power supply for refuel and reactor shutdown operations).

The Main Steam Isolation Valves (MSIV) were manually closed to terminate the pressure reduction and the High Pressure Coolant Injection (HPCI) system was manually started in the pressure control mode. The plant cooldown continued with the HPCI system in pressure control and reactor water level maintained within normal bands with the condensate and feedwater system.

The Root Cause of the event was that procedure PNPS 2.1.5 did not limit operation of MO-S-2, Steam Seal Bypass Valve, to below the steam line pressure design operating limit (250 psig) of the steam seal bypass. The procedure was revised to preclude recurrence.

On November 22, 2008 at approximately 1019 EST, Unit 1 was in the Run mode at a power level of approximately 2800 CMWT, 99.8 percent rated thermal power. A manual scram was inserted due to Reactor Water Level (RWL) decreasing to 10 inches above instrument zero and continuing to decrease. High Pressure Coolant Injection (HPCI) and Reactor Core Isolation Cooling (RCIC) automatically started on low RWL, Level 2. RWL decreased to approximately negative 68 inches (about 90 inches above the top of active fuel) prior to it being recovered by HPCI and RCIC operation. Due to the RWL reaching the Anticipated Transient Without Scram - Recirculation Pump Trip (ATWS-RPT) low level, the recirculation pumps tripped as designed. As RWL was recovering, HPCI was manually secured and RCIC flow was decreased. The 1A Reactor Feed Pump (RFP) was subsequently restarted and RWL control was then transitioned to the lA RFP.

Investigation determined that the direct cause of the event was failure of DC power supply 1N21-K088 which provides power to the differential pressure (DP) controller for the (Steam Jet Air Ejector) SJAE Intercondenser Cooling water control valve 1N21-F211.

The DC power supply 1N21-K088 was replaced and a repetitive task has been created to replace the component at a prescribed interval.

On September 18, 2002, at 8:25 p.m., an automatic reactor scram occurred while the plant was operating at 100 percent power. This event is being reported in accordance with 10CFR50.73(a)(2)(iv)(A) as an event that resulted in the automatic actuation of the reactor protection system and a manual actuation of the reactor core isolation cooling system.

The sequence of events leading to the scram began with a voltage transient in the main turbine electro-hydraulic control system. This resulted in a "close" signal to the main turbine control valves, which caused reactor steam pressure to rise. The scram was initiated by a high neutron flux signal in the average power range monitors resulting from the rise in reactor steam pressure. Following the scram, a valve in the main condensate pump discharge header closed unexpectedly, shutting off flow to the reactor feedwater pumps. All three reactor feedwater pumps tripped in sequence due to low suction pressure, as designed. Operators initiated the reactor core isolation cooling system to provide makeup water to the reactor.

This event is bounded by the analyses contained in the River Bend Updated Safety Analysis Report, and thus was of minimal significance with respect to the health and safety of the public.

On 02/08/2002, at 2252 EST, Unit 1 was in the Run mode at 27% rated thermal power (746 CMWt). At that time, the Reactor Protection System (RPS) was manually actuated to facilitate placing the Main Condenser mechanical vacuum pump in service. Prior to the reactor shutdown, on 02/08/2002, at approximately 2100 EST, degraded operation of the Main Condenser Off Gas Recombiner System had resulted in high hydrogen in the Off Gas.

Procedure 34AB-N62-001-1S (FAILURE OF RECOMBINER AND CONTROL OF SUSTAINED COMBUSTION IN THE OFF GAS SYSTEM) was entered at about 2100 EST and licensed personnel proceeded to reduce reactor power from 100 percent rated thermal power beginning at about 2105 EST. Per the procedure, the in-service Steam Jet Air Ejector was removed from service at about 2200 EST due to Off Gas Hydrogen concentration reaching approximately 4%. Unit 1 was scrammed to facilitate placing the mechanical vacuum pump in service for maintaining the Main Condenser as the heat sink. The lowest Reactor Water Level during the scram was approximately 165 inches above the top of the active fuel (7 inches above instrument zero) this was above any ESF actuation settings. Therefore, no automatic ESF actuations were received and none were required. There was no Reactor Pressure increases during the scram. Reactor pressure following the reactor shutdown did not exceed the pre-event level of 1035 psig.

The cause of the event was component failures that resulted in blocked drain lines in the off gas system. The blocked drain lines caused the recombining action to degrade resulting in high hydrogen in the off gas system.

Corrective actions included restoring the off gas system drain lines.