05000397/LER-2009-002
| Docket Numbersequential Revmonth Day Year Year Month Day Yearfjjv No. 05000 | |
| Event date: | 05-08-2009 |
|---|---|
| Report date: | 03-17-2010 |
| Reporting criterion: | 10 CFR 50.73(a)(2)(v), Loss of Safety Function |
| Initial Reporting | |
| ENS 45051 | 10 CFR 50.72(b)(2)(iv)(B), RPS System Actuation |
| 3972009002R01 - NRC Website | |
Plant Condition The plant was operating in Mode 1 at 87% power at the time of this event.
Event Description
On May 8, 2009, operations personnel were testing the seal oil system [TI] back up regulator [RG] and air side seal oil back up pump [P]. The system operated on the back up regulator for approximately three minutes before the air side seal oil system pressure dropped to zero. The loss of air side seal oil resulted in a failure of the hydrogen side seal to maintain generator pressure. Hydrogen gas, initially pressurized to approximately 72 psi, escaped through the shaft seals into the turbine building. Due to the release of hydrogen from the generator [GEN], a manual scram of the reactor [RCT] was inserted at 1046 PDT and the turbine building was evacuated. This event occurred 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> prior to a planned shutdown for a refueling outage (R-19) with the plant in an end of cycle final feedwater temperature reduction (FFTR) lineup.
All control rods fully inserted in response to the reactor protection system (RPS) actuation. A reactor pressure vessel [RPV] water low level (level 3) trip occurred with a minimum level of -4.7 inches. One reactor feedwater (RFW) pump was manually tripped prior to level recovery and the FFTR lineup was exited. The long stroke time of the bypass valve for the high pressure feedwater heaters caused the other RFW pump to trip due to RPV high level (level 8). The pump was restarted and RPV water level control was established at 36 inches.
Heat removal through the main condenser [SG] was maintained. Post trip RPV water level was maintained in the normal band using the feedwater [SJ] and condensate systems [SD]. RPV pressure was controlled using automatic control of the main turbine [TRB] bypass valves. Off-site power was available and two of three emergency diesel generators [EK] were operable and available. DG-2 was inoperable and unavailable due to DG-2 fire remote transfer switch functional operability surveillance testing. No other safety systems actuated or were required to actuate. There was no inoperable equipment at the start of the event that contributed to the event.
At 1741 EDT (1441 PDT), the NRC was notified of the RPS actuation per 10 CFR 50.72(b)(2)(iv)(B) (reference event notification number 45051). This LER is submitted pursuant to 50.73(a)(2)(iv)(A) as an event or condition that resulted in manual actuation of the RPS.
Immediate Corrective Action Maintenance actions on DG-2 were stopped and the generator was placed in an inoperable but available status. Plant cooldown was slowed through steam load reduction. Venting of the main generator was completed. The inline seal oil filter, capable of on-line cleaning by rotating the cleaning handle, was cleared and seal oil system pressure was restored. Due to imminent refueling outage, no attempt to restart the plant was made.
Cause
The direct cause of this event was accumulated corrosion products on backup seal oil piping and biological material in the air side seal oil cooler, both due to higher than normal moisture in the oil over the past two years. These materials were released during system backup testing, which plugged the in-line seal oil system filter. Seal oil pressure dropped downstream of the plugged filter.
26158 R4 Two, root causes were identified: 1) The process for addressing compensatory measures for the single point vulnerability of the Cuno filter (SO-F-1) was inadequate. 2) An ineffective and untimely repair of Seal Steam flange leaks contributed to increased levels of moisture in the air side seal oil system. This resulted in formation of corrosion products and biodegradable material in the seal oil system.
Further Corrective Action The following actions are being pursued to prevent recurrence: 1) Seal oil system procedures are being upgraded to ensure the single in-line filter is monitored continuously during seal oil system startup, backup system testing, or alarm for low air side seal oil pressure or backup system activation. Actions will be taken as necessary to clear the filter. 2) Methods, criteria and preventive maintenance that tests turbine seal oil for biological contaminants will be established. This includes monitoring and addressing conditions that lead to bio-fouling and corrosion.
Additional corrective actions to address contributing causes, extent of cause, and recurrence prevention include procedure revisions, leak repairs to restore oil moisture to normal, PM additions and clarifications, and training enhancements.
Assessment of Safety Consequences
For this event, High-Pressure Core Spray (HPCS) [BG], Low-Pressure Core Spray (LPCS) [BM], Reactor Core Isolation Cooling (RCIC) [BN], and Residual Heat Removal (RHR)/Low Pressure Coolant Injection (LPCI) [BO] systems were capable of performing their intended safety functions. Off-site power was available and two of three emergency diesel generators [EB and EK] (one for Division I & II and one for Division III) were operable and available. The other emergency diesel generator was not operable but available fourteen minutes after the event. This event did not involve an event or condition that could have prevented the fulfillment of any safety function described in 10 CFR 50.73(a)(2)(v). This event posed no threat to the health and safety of the public or plant personnel and was therefore, not safety significant.
Similar Events No similar events have been reported by Columbia. Review of the corrective action program database from 2003 to present reveals no documented issues of moisture problems in seal oil prior to October 2007, at which point they became frequent. Moisture content increased by an order of magnitude, roughly 20 ppm to 200 ppm. This exposure is believed to have accelerated corrosion of carbon steel piping and vessels, increased sludge formation in the oil, and provided conditions more conducive to biological growth.
Consequently, corrosion products and biological growth have developed and accumulated over the past two years in significantly higher quantity than previously experienced at Columbia.
Energy Industry Identification System (EllS) Information EllS codes from IEEE Standards 805-1984 and 803-1983 are denoted as [X], [XX], or [XXX] throughout the body of the narrative.
26158 R4