05000285/LER-2005-001
| Docket Number Sequential Rev Month Day Yearnumber No. 05000 | |
| Event date: | |
|---|---|
| Report date: | |
| Reporting criterion: | 10 CFR 50.73(a)(2)(iv), System Actuation 10 CFR 50.73(a)(2)(iv)(A), System Actuation |
| 2852005001R00 - NRC Website | |
BACKGROUND
Fort Calhoun Station (FCS) is a two loop, Combustion Engineering (CE) designed Pressurized Water Reactor (PWR).
Each loop contains two Reactor Coolant Pumps (RCPs) and one Steam Generator (SG). The SGs secondary side is fed by the main feed system. The system uses two (2) of three (3) 50 percent (%) motor driven pumps to feed the SGs. Normal feed to the SGs is controlled by main feedwater flow control valves FCV-1101/1102. Valves FCV-1101/1102 are used to control SG level during normal plant operation from about 30% power to 100% power. During plant startups and shutdowns another set of valves, HCV-1105/1106, are used to control SG level. These valves bypass FCV-1101/1102 to feed the SGs. Valves HCV-1105/1106 and one main feedwater pump are used to feed the SGs from about 1% power to —about 30% power. BeloW igrYfe-e-diTater pump is used IFfierth-e-stEairl' generators. The safety related auxiliary feedwater system is used to feed the SGs in emergencies or, if needed, at low power.
When the main feedwater control valves FCV-1101/1102 are being used to feed the SGs in automatic they are controlled by a three-element self-synchronizing controller. The feedwater control system maintains the proper positioning of the regulating valve for its respective SG. Steam flow and feed flow are first sent to a summing network where any mismatch between the flows will produce an error signal to the flow control section of the controller. SG downcomer level is compared to a programmed level setpoint and any difference will cause the level controller to change its signal to the flow control section of the controller. During low power operations (less than 30%), the three-element control mode is not effective, due to the low inputs from steam flow and feed flow and manual control of the regulating valves is necessary.
To provide greater stability and control during low power operations, the feedwater regulating bypass valves (HCV- 1105/1106) are used in place of the main feedwater regulating valves (FCV-1101/1102). HCV-1105/1106 utilize an automatic controller which operates as follows: The controller compares measured steam generator level to a reference setpoint selected by a dial on the front of the controller. Any error between actual and setpoint level will be sent to the valve controller, which controls the air flow to the pneumatic valve actuator to further open or close the valve. Either the main or bypass valves can be operated manually as well as in an automatic mode.
The Steam Dump and Bypass System is used to rapidly remove stored energy and sensible heat from the Reactor Coolant System (RCS) following a turbine and reactor trip. The total capacity of the system (38% of total secondary steam flow) —allows it to be used to control-secondary steam pressure-without.opening thezecondary.safety_valves.The Steam Dump � and Bypass System is also used to control reactor coolant temperature when the plant is being cooled down or heated up.
The Steam Dump and Bypass System consists of four steam dump valves and one bypass valve. All five valves discharge to the main condenser. The turbine bypass valve is connected in parallel with the steam dump valves. Its function is to control the pressure in the header during plant cooldown, heatup, and standby operations. The bypass valve can also assist in limiting secondary system pressure following a plant trip.
The reactor protection system (RPS) is designed to rapidly shut down the nuclear chain reaction prior to reaching a condition that could damage the reactor core. The RPS generates a reactor trip signal, which releases the control element assemblies and allows the control rods to fall into the core. The loss of load trip is an anticipatory trip that is to protect equipment function. This function trips the reactor if two or more of four main steam stop valves are closed and reactor power level exceeds 15%.
EVENT DESCRIPTION
On February 26, 2005, control room operators completed their scheduled power reduction to 12% power using a 2%/hour ramp rate. The night shift crew was using all appropriate procedures for the scheduled Refueling Outage (RFO) and they were preparing to remove the turbine-generator from service. RO1 (Reactor Operator) was responsible for the Primary Systems. RO2 was responsible for feedwater and reactor temperature control using the steam dump and bypass valves.
RO3 was responsible for the turbine-generator. Turbine testing was to be conducted at about 12% power At 2100 Central Daylight Time (CDT),ped the turbine with no noted complications. At 2121, RO3reset the turbine in preparation for turbine testing. The operator noticed that intermediate stop valve ISV-2 did not open as expected.
At this time, the Control Room Supervisor (CRS) instructed RO1 and RO2 to remain focused on their areas of responsibility while the failure of ISV-2 was investigated by the remainder of the crew. Maintenance and Instrument and Controls (I&C) personnel were notified and asked to investigate the failure.
At 2125, the CRS and RO2 began receiving SG high/low level alarms and the prescribed temperature control band of plus or minus 0.2 Fahrenheit (F) degrees was not able to be maintained. This was attributed to SG levels diverging significantly even though HCV-1105/1106 were in automatic control. After several more alarms were received, the CRS instructed RO2 to take manual control of HCV-1105/1106 and to balance out the diverging level oscillations.
At 2129, RO2 placed HCV-1106 in manual and reduced its controller output signal from 30% to 15% because SG B level was beginning to rise from its low level alarm value of 65%. At that time, HCV-1105 was already closed in manual because SG A was high in level.
At 2132, I&C requested that the turbine be tripped and reset in an attempt to reset ISV-2's hydraulic fluid positioner. The CRS instructed RO3 to trip the turbine at 2133 and it was then reset. Also occurring at 2133, RO2 opened HCV-1105 and began filling SG A because its level was at 65%. Steam generator pressure began lowering from 885 psia to 840 psia over the next minute.
At 2134, ROI informed the CRS that pressurizer level and pressure were lowering and RO2 informed the CRS that he was experiencing a problem with feedwater control. As the crew identified that RCS temperature was lowering rapidly and power was rising.-At 15% power the-RPS tripped the reactoron the loss of.load trip sincethe main steam stop valves were — shut..
The crew entered Emergency Operating Procedure (EOP)-00 "Standard Post Trip Actions" and proceeded through their actions. RO2 reported that HCV-1105 was full open and HCV-1106 was closed. The CRS instructed RO1 to emergency borate due to indications of an uncontrolled plant cooldown and he instructed RO2 to close the Main Feedwater Isolation Valves (HCV-1385/1386) which terminated the feedwater induced cooldown.
On February 27, 2005, at 0026 CDT, a four hour notification was made to the Headquarters Operation Office (H00) of the NRC per 10 CFR 50.72(b)(2)(iv)(B). This report is being made per 10 CFR 50.73(a)(2)(iv)(A).
CHRONOLOGY
February 26, 2005 2100CDT�Turbine Generator was tripped per OI-ST-3, Attachment 1 per the outage schedule 2121�Turbine was reset per OI-ST-1, Attachment 1. Intermediate Stop Valve #2 (ISV-2) failed to open.
I&C was notified _ 2129�HCV-1105/1106 Bypass Feedwater Valves were taken to manual control due to diverging SG levels 2132�I&C requests that the turbine be tripped and reset in order to cycle ISV-2's hydraulic fluid positioner 2133:15�Turbine was tripped by RO3 2133:35�Turbine was reset by RO3 2134�RO1 informs CRS that Pressurizer Level and Pressure are lowering and RO2 informs CRS that he was experiencing a problem with feedwater control.
2134:13�Loss of Load trip is received.
2134:18�Reactor trip is received.
2136�CRS directs feedwater isolation valves to be closed due to cooldown.
2136�CRS directs Emergency Boration to be initiated due to unplanned cooldown.
CONCLUSION
A root cause analysis was conducted to determine why RCS teifipeiiiiii:elowered whiZ'h—CaTsed reactor pOlVei'fo—fisCfroirc 12 to 15% and initiated the automatic trip on the Loss of Load signal. A combination of personnel interviews, equipment investigations, and procedural reviews were conducted to gather information pertaining to this event.
An analysis of the information gathered for this event determined that the immediate cause for the loss of load reactor trip was due to control board operator performance errors related to control of RCS temperature and Steam Generator level.
The performance errors included (1) establishing too high of a feed rate to the steam generators immediately following placement of the feedwater flow controls into manual operation, and (2) not maintaining steam dump/bypass temperature control stable while at low power conditions. These errors resulted in a lowering of RCS temperature, which, resulted in an increase in reactor power activating the loss of load trip. A thorough examination of this immediate cause determined that the root cause of the event was that, "Administrative controls that are overly biased towards full power operation.
In addition four contributing causes were identified in the course of the analysis:
1. SG level and pressure control procedures did not provide adequate guidance for low power operation.
2. SG feedwater flow indication is inadequate for low power operation 3. Insufficient supervisory oversight regarding activities involving operators with limited experience during low power operation.
There is a minimal amount of recurring low power operation training leading to over reliance on the limited amount of individual operating experience in controlling certain processes at low power operations.
-� The analysis determined that there was not a failure of the feedwater or steam dump and bypass valve control systems.
SAFETY SIGNIFICANCE
The Loss of Load trip is not significant to nuclear safety because this type of trip is an analyzed event. Although the trip challenges plant equipment, all structures, systems and components (SSCs) responded appropriately, and the trip was uncomplicated.
In addition, the relatively low power level of the reactor (-12%) prior to the trip contributes to the assertion that the event was non-safety significant due to the minimal increase in core damage risk. No reactor safety functions were challenged during the event. Therefore, this event had no impact on the health and safety of the public.
CORRECTIVE ACTIONS
Immediate Corrective Actions
The plant shutdown was completed as required by plant procedures and EOP-00 was exited. The SG levels were restored to the normal band.
Long Term Corrective Actions to Correct the Root Cause Provide enhanced low power procedure guidance for operators on steam dump/bypass valves and feedwater bypass valves control. This will be completed by July 1,2005.____ �_ Revise OPD-4-19, "Reactivity Management," and other procedures as necessary to ensure that there are clear expectations for monitoring reactivity manipulations. This will be completed by July 1, 2005.
Additional actions to correct the contributing causes will be tracked by the FCS corrective action program.
SAFETY SYSTEM FUNCTIONAL FAILURE
This event did not result in a safety system functional failure in accordance with NEI-99-02.
PREVIOUS SIMILAR EVENTS
LERs 2003-003 and 1996-007 documented low power reactor trips.