ML20054A656
| ML20054A656 | |
| Person / Time | |
|---|---|
| Issue date: | 03/31/1982 |
| From: | Massaro S, Rizzo J NRC OFFICE FOR ANALYSIS & EVALUATION OF OPERATIONAL DATA (AEOD) |
| To: | |
| References | |
| NUREG-BR-0051, NUREG-BR-0051-V03-N6, NUREG-BR-51, NUREG-BR-51-V3-N6, NUDOCS 8204160042 | |
| Download: ML20054A656 (13) | |
Text
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- POWER REAC~DR EVENTS
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United States Nuclear Regulatory Commission September-October 1981/Vol. 3, No. 6 This bi monthly newsletter summarizes noteworthy information about nuclear power plants obtained from Licensee Event Reports and NRC Inspection Reports. This information is reported in the belief that its open communication benefits all interested individuals and organizations. The events reported are or have been under NRC review and usually concern safety-related issues. Although most events summarized have occurred recently, reporting on some is delayed either because certain generic problems become evident only after an extended period or because certain issues require lengthy resolution.
Table of Contents Pane i
" Reactor Scram and Loss of Redundant Safety Signals".
1
" Service Water Spill".
3 I
" Failure of High Pressure Safety injection System" 5
" Steam Voiding in the Reactor Coolant System" 9
"Failure of Main Transformer" 11 References..
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i EDITOR:
Sheryl A. Massaro CONTRIBUTING EDITOR:
John Rizzo Office for Analysis and Evaluation of Operational Data U. S. Nuclear Regulatory Commission PUBLISHED IN:
March 1982 Washington, DC 20555 8204160042 820331 PDR NUREC PDR BR-OO51 R J
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REACTOR SCRAM AND LOSS OF REDUNDANT SAFETY SIGNALS On March 13, 1981, the Tennessee Valley Authority reported to the NRC that a scram occurred at the Browns Ferry Unit 2* facility as a result of an open equalizing valve used with the lower wide-range Yarway water level transmitter.
Equalizing valves, which are closed during normal plant operations, are used to conduct instrument calibrations and to prevent over-ranging the transmitter during instrument isolation valve manipulations. With the plant operating at normal full recirculation flow conditions, there is no clear indication that this equalizing valve is open.
However, once recirculation flow is decreased, th? reference leg will drain, causing erroneous differential pressure (dp) input signals to other transmitters connected to the same reference water calumn.
This affects a large number of safety and control systems that use water level as an input.
A review of the event showed that under reduced flow conditions, the false high water level signals led to loss of redundancy in the logic for initiating safety functions, as well as initiation of a turbine trip which caused the reactor to scram.
Safety system dp transmitters that could be affected by the drained reference leg provide water level input signals to the logic circuits for the following functions:
primary containment isolation, low water level scram protection, automatic depressurization system confirmatory low water level, high water level trip signal for high pressure coolant injection and reactor core isolation cooling, and main turbine trip.
In addition, a number of control functions can be affected, either directly or indirectly, by the drained reference leg.
( Under normal operating conditions with full recirculation flow, the operator would be unaware of the abnormal position of the equalizing valve because the lower wide range Yarway transmitter, which is bypassed by the open equalizing valve and the affected safety system transmitters, would continue to provide signals that appear normal to the control room instrumentation.
The lower wide-range Yarway transmitter is designed to provide accurate water level signals only for accident conditions when there is no jet pump flow.
With full recirculation flow, this transmitter reads full scale (high water level) whether or not the equalizer valve is open because the variable leg is connected near the high pressure outlet section of a jet pump diffuser.
Under these conditions, the common reference leg for the safety system dp transmitters identified above will not drain.
Therefore, even if the equalizing valve is open, the safety system transmitters provide normal signals when there is full recirculation flow.
Following a reduction of flow and power, a turbine trip due to reactor vessel high water level occurred, followed by a reactor trip.
Using other vessel level instrumentation, the water level was verified to be normal.
Thus, the operator was alerted to look for the problem in water level instruments.
The cause of the event was not known at the time of the reactor scram.
- A 1065 MWe BWR located 10 miles northwest of Decatur, Alabama, and operated by Tennessee Valley Authority.
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Evaluation following the scram revealed that as the recirculation flow rate was being reduced as part of a planned reactor shutdown.
Reactor power had been reduced from 100% to 54% over the previous 45 minutes.
As the recircula-tion flow was reduced, the pressure across the jet pump diffuser changed so that at lower flow rates the driving force across the equalizing valve reversed, causing the reference leg to have higher relative pressure.
Higher pressure on the reference leg, coupled with an open equalizing valve, allowed the water in the reference leg to drain into the variable leg water column.
This caused all level transmitters connected to the affected reference leg to indicate j
higher-than-actual water level.
The false indication of higher water level l
caused the two-out-of-three trip logic to be satisfied, giving a turbine trip j
and, hence, a stop valve closure scram.
It is not known when the lower wide-j range transmitter equalizing valve was opened.
However, 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> prior to the I
scram a surveillance test was performed on the unit.
Similar problems have occurred previously and, in July 1980, the nuclear steam system supplier (NSSS) prepared an information letter that delineates similar safety concerns with respect to the control of differential pressure transmitter l
equalizing valves.
The NSSS letter also recommends that the licensee consider implementing the following means for controlling critical dp sensor instrumenta-tion equalizing valves:
Installed dp instrumentation equalizing valves may be removed and the low and high side pipe stubs capped to prevent equalizing valving errors and also prevent sensor errors due to installed, leaky equalizing valves.
(Not feasible where valve block assemblies are in use.)
These equalizing valves may be closed in a positive manner by permanently locking the valves in the closed position, or by closing tho valves and removing the valve wheels and extended portions of the valve stems, etc.
(NOTE:
For the two items above, any function of the equalizing valves can be performed by equalizing valves mounted on calibration systems or devices which are disconnected for normal operation.)
Root, vent, drain and equalizing valve handles may be painted different colors, and the color included in calibration and line up verification checks.
Af ter normal checklists are complete, an independent supervisory check may be performed and then valves may be wire and lead sealed in position.
Procedures may include a supervisory comparison of the dp instrument reading taken just prior to surveillance testing / calibration and just after sign-off and channel restoration.
The final reading should only differ from the initial reading due to calibration or a change in plant operating conditions.
A periodic check may be made of dp instrumentation to detect warm instru-ment lines (for instruments connected to systems at high temperatures).
A warm instrument line would indicate significant leakage or an open equalizing valve.1,2 2
i SERVICE WATER SPILL On October 7, 1981 at Brunewick Unit 2,* a spill of approximately 32,000 gallons of salt water was released onto the 50-f t elevation in the reactor building near the residual heat removal (RHR) service water booster pumps 2A and 2C.
The water migrated to elevation -17 ft through unsealed spare floor penetrations near these pumps (Figure 1) over a four-to six-hour period.
The reactor was at 72%
power.
In the spring of 1981, the RHR service water booster pump motor cooler dis-charge drain piping had been replaced with a temporary carbon steel installa-tion with the discharge running to the inlet water box of the 2C reactor building closed cooling water (RBCCW) heat exchanger (see Figure 1).
A flex-ible rubber radiator hose had been connected between the existing piping and the temporary piping using single radiator clamps to secure the hose.
A safety analysis for this installation was done by plant engineering personnel along with an acceptance test which subjected the new system to an inservice leak test.
A shift foreman's clearance was issued to administratively control positioning of valves on the service water side of the 2C RBCCW heat exchanger in order to prevent over pressurization of the piping by the normal RBCCW supply.
This temporary arrangement would experience pressures less than the RBCCW ser-vice water (SW) system pressures as long as the aforementioned clearance was in effect.
The arrangement had been used previously on Unit 1 during plant modifications without incident.
l On October 5, 1981, the clearance on the 2C RBCCW heat exchanger was cancelled in order to perform periodic testing and maintenance on the 2A RBCCW heat exchanger.
The temporary piping with the flexible rubber radiator hose was still in service, since permanent replacement metallic piping had not yet been installed.
The flex hose on the 2A RHR service water booster pump immediately l
slipped off when the periodic testing began, and maintenance personnel rein-stalled the hose using double pipe clamps.
The cuantity of water released was confined to the storm drains located within the flood barrier surrounding the booster pumps.
On October 6, 1981, measurements of water level in the -17 ft elevation were made by operations personnel.
The south RHR room was observed to be dry, while the north RHR room had 4 inches of water due to the reactor building equipment drain tank overflow, and the high pressure coolant injection (HPCI) room had 2-1/2 inches of water.
During this period, a pump had been positioned in the north RHR room and was pumping water into the sump in the HPCI room through the HPCI north door.
The 2A RHR SW booster pump hose again came loose on October 7, 1981.
This time no operations personnel were in the area to observe and correct the problem.
However, the control room operator noted an annunciator alarm on HPCI logic power failure and steam leak ambient Temp-Hi.
Operations personnel were dis-patched to the reactor building and noted water at the 50-ft elevation flowing out from the discharge side of the 2A RHR SW booster pump motor cooler line.
Most of the water being discharged was contained within the equipment floor
- An 821 MWe BWR located 3 miles north of Southport, North Carolina, and operated by Carolina Power and Light.
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Figure 1 - Plan view of the unsealed penetrations at 50' Elevation.
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barrier, while a small floor area of 10 ft outside the barrier was wetted down.
Water was also observed collecting on the reactor core isolation cooling (RCIC) mini steam tunnel roof. At the 20 ft elevation, water was seeping down the south wall of the mini pipe tunnel onto the floor and into the drains.
Moisture also was observed along the east side of the tunnel wall flowing down into the floor access plugs located on top of the HPCI room. Operations inspec-tion of the f t elevation revealed approximately 6 inches of water in the north RHR room, 8 inches of water in the HPCI room, and 2 inches on the floor of the south RHR room.
It was noted that the water in the south room was entering slowly under the locked south HPCI air lock door (see Figure 2).
The north HPCI air lock was open due to the aforementioned pumping operation.
Some water was observed running down the HPCI steam exhaust line.
A visual examination was conducted at the 50-ft elevation (RCIC mini pipe tunnel and tunnel roof), and at the 20-ft elevation (HPCI room roof, the south and north RHR rooms, and the HPCI room).
It was observed that the water had entered from unsealed floor penetrations located within the flood barrier around the 2A and 2C booster pumps.
The penetrations discharge onto the RCIC tunnel roof.
Some of the water entered the tunnel roof floor drain, the RCIC hatch plugs, and the mini pipe tunnel through a spare pipe penetration; the remainder ran dcwn the exterior of the south tunnel wall onto elevation 20 ft.
The water that entered the RCIC pipe tunnO exited through three floor drains to the HPCI and south RHR rooms.
The portion of water that seeped onto the 20-ft elevation apparently entered the HPCI equipment hatches on top of the HPCI room.
Further investigation determined that the drains associated with the RCIC tunnel roof and tunnel discharged into the HPCI and south RHR room sump.
It appeared that the majority of water entered the floor drains and backed up through the f t elevation sump pumps. Some HPCI instrumentation was electrically shorted and HPCI was declared inoperable. One of the high temperature switches (thermo-couple) in the mini pipe tunnel was grounded due to a few drops of water which had entered the switch casing through a small hole caused by corrosion. The A-temperature switch is one-out-of-one AT-network, and failed in a way that caused HPCI isolation.
As a result of this event, the licensee replaced the failed switch and took steps to protect against a repeat of the common mode flooding incident by inspecting and sealing all penetrations located around the booster pumps within the flood barrier and on the tunnel roof.
In addition, ways to improve sump pump reliability were examined together with means of tightening control over the ease and frequency with which water-tight equipment area doors are allowed to be left open for extended periods of time.3 FAILURE OF HIGH PRESSURE SAFETY INJECTION SYSTEM At about 3:30 a.m. on September 3,1981, with San Onofre Unit 1* operating at 88% power, a regulated power supply serving one of the two redundant paths of
- A 436 MWe PWR located 5 miles south of San Clemente, California, and operated by Southern California Edison.
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DRW Sump Core Spray A 0:
RHR (System A)
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Figure 2 Plan view of the Brunswick Unit 2 reactor building basement.
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the reactor protection system and a portion of the control and indication system failed.
As a result, feedwater and steam flow and steam generator water level indications were lost for the steam generator served by this power supply, and oscillations were observed in similar flow and level indication of the other two steam generators.
The operators placed the steam generator water level under manual control and then manually tripped the reactor.
During this period, the reactor coolant system (RCS) water temperature decreased, the steam genera-tor levels increased, and the system pressure decreased.
At 1735 psig, a safety injection actuation signal (SIAS) was automatically initiated, in accordance with system design.
Subsequently, RCS pressure increased and the safety injec-tion actuation signal terminated en1 was reset at 4:00 a.m.
At San Onofre Unit 1, the steam generator feedwater pumps are also part of the safety injection system (see Figure 3).
During normal operation, water from the condensate pumps flows through valves HV 654A and B, the feedwater pumps, and valves HV 852A and B to the secondary side of the steam ger.erators. Another line, which connects at each feedwater pump discharge line is normally isolated by safety injection valves HV 851A or 8: these lines join to a common header which then connects to the three RCS cold leg return lines from the three steam generators to the reactor vessel.
Upon receipt of an SIAS, the feedwater pumps automatically obtain suction from the refueling storage tank rather than the condensate system and discharge to the cold legs of the reactor coolant system rather than the shell side of the steam generators.
This is accomplished by the following automatic actions, with designed time intervals:*
(1) HV 854A and B closed in 5 seconds.
(2) HV 852A and B closed in 5 seconds.
(3) Safety injection pumps started running immediately and at full speed in 10 seconds.
(4) HV 853A and B started opening in 5 seconds and fully opened in 10 seconds.
(5) HV 851A and B started opening in 5 seconds and fully opened in 10 seconds.
(6) MOV 850A, B and C started opening immediately and fully opened in 10 seconds.
Then, if RCS system pressure decreases sufficiently (such as in the case of a loss of coolant accident), borated water from the refueling water storage tank would be pumped by the safety injection pumps through the feedwater pumps and safety injection valves 851A and B into the RCS.
During the September 3, 1981 event, RCS pressure only decreased to about 1700 psi.
Therefore, since the feedwater pump discharge shutoff head pressure is about 1200 psi by design, no safety injection flow would have occurred even if the safety injection valves had opened.
In addition, none was actually required since there was no loss of coolant accident.
However, while SIAS was present, plant operators in the auxiliary building noted that neither valve HV 851A or B had opened.
The valves did open when
^After the event, the sequence was modified to include trip 7ing of the feed-water pumps to reduce the differential pressure across valves HV 851A and B.
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FROM CONDENSATE TO STEAM PUMPS GENERATORS 1r d
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FLOW 1r Figure 3. Simplified Schematic of Safety injection System (San Onofre Unit U
the feedwater pumps were tripped.
After operability of the valves could not be demonstrated by subsequent tests, the licensee placed the plant in a cold shutdown condition and agreed not to restart the plant without NRC concurrence.
The failure of the valves was reviewed by the licensee and NRC.
The following valve design deficiencies were identified by the licensee:
(1) the contact stress between the valve seat and the disk exceeded the threshold of galling (transfer of metal at contact surfaces resulting from local material being overstressed) due to a high pressure differential across the valve disks, and (2) the coefficient of friction between disk and seal assumed for sizing the hydraulic valve activators was too small.
The licensee has found that differential pressure imposed on the valve disks by operating the feed pump with HV 851 closed significantly increases the force required to open the valve and the valve seat stress level.
Also, pressure between the valve disks can add to these effects.
Accordingly, the licensee
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has developed design changes to trip the feed pump and relieve any valve internal pressure prior to opening the valve.
These changes were implemented following approval and testing.4 The licensee instituted an extensive surveillance program.
The licensee has committed to perform a long-term study of the advisability of completely redesigning the safety injection system.
The licensee initiated startup at the plant late on November 3, 1981.
The modified system was tested on Novem-ber 23, 1981 and February 27, 1982, and operated satisfactorily each time.
The NRC issued IE Information Notice No. 81-31 " Failure of Safety Injection Valves to Operate Against Differential Pressure," on October 7, 1981 to licensees to inform them of this event.
)
STEAM VOIDING IN THE REACTOR COOLANT SYSTEM On June 29, 1981, during cooldown of the Oconee Unit 1* reactor coolant system (RCS) for a scheduled refueling outage, an incident involving steam voiding in the RCS "A" hot leg during decay heat removal (DHR) occurred.
The upper area of the hot leg, often referred to as the " candy cane" or "j"-leg (at the entry into the once-through steam generator), was the void location.
The reactor coolant pumps were secured and DHR initiated due to low RCS pres-sure caused by a flow control problem in the auxiliary pressurizer spray line.
This occurred with an RCS temperature and pressure of 225 F and 310 psig, respectively.
Pressurizer temperature was 423 F and pressurizer level was 250 inches.
A procedural step had been omitted which required reduction of pressurizer level to 100 inches prior to turning off the last RCP.
Subse-quently, pressurizer level was lowered to 100 inches to fulfill this require-ment.
The resulting pressurizer outsurge moved a large volume (4000-5000 gallons) of stagnant 423 F water from the pressurizer into the "A" hotleg, and also elevated the "A" loop hot leg temperature instrument reading to approxi-mately 350 F.
- An 887 MWe PWR located 30 miles west of Greenville, South Carolina and operated by Duke Power Company.
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l An evaluation was done concerning repressurizing and restarting a reactor coolant pump to cool the hot leg.
This method was not used due to considera-tion of thermal stresses on the once-through steam generator (OTSG) tubes and other RCS components.
Also, the starting of a reactor coolant pump could have caused a crud burst due to sudden RCS temperature changes.
Efforts to cool the "A" hot leg by feedwater addition to the "A" 0TSG through the main feedwater nozzles slowly decreased the hot leg temperature instrument reading to approximately 315 F.
Operators then turned off the pressurizer heaters to cool the pressurizer and depressurize the plant.
As system pressure was lowered below saturation pressure for the hottest water in the "A" loop, a rapid pressurizer insurge of almost 100 inches occurred as the hotleg void formed.
The void was equivalent to approximately 300 cubic l
feet or a 10-f t drop in hot leg level.
Voiding occurred at the following RCS conditions:
(1) pressure at 110 psig, (2) both cold legs at about 160*F, (3) "B" loop hot leg instrument reading at about 220 F, and (4) "A" loop hot leg instrument reading at 315 F.
The hot leg temperature instrument reading incresed from 315 F tc approximately 360 F during the pressurizer insurge, indicating that hotter areas existed in the regions of the "A" loop above the hot leg resistance temperature device (RTD).
Prior to the voiding, no indication was available to the operator that the "j" leg temperature was not reflected by the hot leg RTD.
Pressurizer heaters were re-energized to repressurize the RCS and compress the void.
However, it is not possible to eliminate a void just by pressurizing it; heat removal from it to either the surrounding fluid, the surrounding walls, or introduction of lower temperature fluid such as a spray is required.
Addi-tion of feedwater via the emergency feedring to high OTSG levels (greater than 85%) combined with operation of the turbine bypass system also induced cooling of the void area.
The hot leg was refilled within the next two hours.
The DHR system maintained reactor core cooling throughout the incident.
Incore temperatures indicated 180 F to 190 F at all times during the hot leg steam voiding.
RCS pressure was maintained at approximately 120 psig until the hot leg temperature was reduced to 240 F.
The licensees' review of this event resulted in the following changes to improve the unit shutdown procedures for minimizing the possibility of steam voiding in the RCS:
l (1) The operators received training to identify the initial RCS conditions for pressurizer cooldown and the symptoms of RCS voiding, should it occur.
The plant procedures include RC pump /LPI pump piggy-back operation to cool j
the RCS hot legs to less than or equal to 165 F prior to securing the RC pumps.
I (2) The licensee has added procedural steps to prevent pressurizer outsurge after the RC pumps are secured.
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I (3) The operators received training such that, in the event of a pressurizer outsurge, they will be capable of maintaining the hot leg subcooled and be able to decrease the temperature with feedwater flow through the auxi-liary feedwater nozzles.5,6 FAILURE OF MAIN TRANSFORMER On July 25, 1981, the North Anna Unit 2* phase C transformer failed two minutes after it was energized from the 500 kV system.
The licensee concluded that the initiating cause of this failure was an incipient failure in the transformer coil resulting from failure of the phase B transformer on July 3.
(See " Power Reactor Events," Vol. 3, No. 5, pp. 1-2.)
In addition, the July 25 failure was the fourth such failure since November 1980.
All four of these failed transformers had been in service on the Unit 2 main generator output distribu-tion system at the time of their failure.
On July 25, 1981, the C phase main transformer experienced an apparent high-voltage winding-to ground failure which tripped the switchyard 500 kV breaker, thus isolating the damaged transformer from the balance of the station 500 kV distribution.
The fault caused extensive damage to the transformer, rt.pturing the casing in several places and damaging the high voltage output bushing and adjacent lightning arrestor insulator.
The oil contained in the transformer was spilled onto the gravel surrounding the transformer base.
There was no fire during this event.
To determine the pre-operational servicing conducted on this transformer, station and system personnel were interviewed.
This transformer was a replacement obtained from another utility, because a pre-viously failed transformer had been returned to the vendor for repairs.
The handling and pre operational service procedures performed on the failed C main transformer did not disclose any major discrepancies.
A task force comprised of the licensee and Westinghouse (transformer manu-facturer) personnel was established to study the transformer failures.
The four failures were characterized by two failure modes.
Failures 1 and 4 were winding to ground faults.
Failures 2 and 3 were high voltage bushing to ground failures. All of the failures apart from failure 2 involved high voltage to low voltage windings.
The failed Unit 2 transformers shared a rather unique background:
(1) They had all been handled and shipped several times before being placed in service in Unit 2.
(2) They had been in a bank of transformers which had experienced a failure of at least one transformer at least once prior to their own failure.
(3) The high voltage bushing for these transformers had also been handled more than usual and may have been stored improperly.
Improper storage of the high voltage bushing coupled with an over-voltage condition could cause failure of the bushing as experienced in failures 2 and 3.
- An 890 MWe PWR located 40 miles northwest of Richmond, Virginia, and operated by Virginia Electric & Power.
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(4) The transformers associated with failures 1, 2, and 3 had b2:n subjected to several documented over voltage transients.
The transformer associated with failure 4 had been subjected to an over-voltage condition of unknown magnitude and short duration on the low voltage side during failure 3.
It was concluded that failures 2 and 3 were a result of the high voltage bushing failing due to a combination of improper storage and over-voltage.
Failure 1 resulted from a combination of insufficient cooling, mechanical relief device operation, gas pressure control failure, and inoperative transformer alarms, which allowed nitrogen gas to exist in the transformer oil. This gas-in-oil combination reduced the dielectric strength enough to cause failure at operating voltages.
The fourth failure actually began during the time the third failure occurred.
The initiating fault did not lead to the failure of the fourth trans-former simultaneously with the third because the protective relaying de-energized the transformer bank before the fourth transformer fault had grown suf ficiently.
I When the fourth transformer was subsequently back fed, the previously ini'
..d fault in the low voltage winding caused a catastrophic failure to occur o,ter about two minutes.
The licensee has determined the most probable cause of each failure through a careful review of operating logs and records, interviews with watchstanders, analysis of fault recorder data, detailed inspection of the failed components and supporting tests and experiments at the vendor factory.
The existing trans-formers in the Unit 2 output bank, their high voltage bushings, insulating and cooling oil purity, associated on-site high and low voltage distribution com-ponents, protective relaying, alarms, and instrumentation were thoroughly tested and accepted for operation.
In addition, those site procedural and material matters which could have contributed to the failures (e.g., automatic vice manual operation of the transformer oil coolers, winding temperature indication and transformer alarms operable) have been corrected.7 l
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i REFERENCES i
1.
USNRC, IE Information Notice No. 81-25, "Open Equalizing Valve of Differential Pressure Transmitter Causes Reactor Scram and Loss of Redundant Safety Signals," and Attachment 1, August 24, 1981.
J 2.
USNRC, IE Inspection Report 50-259, -260 and -261/81-09, April 9, 1981.
3.
Carolina Power and Light, Brunswick Unit 2, Docket No. 50-324, Licensee Event Report 81-109, October 30, 1981.
4.
Southern California Edison Company, San Onofre Unit 1, Docket No. 50-206, Licensee Event Report Nc. 81-21, September 11, 1981.
5.
Letter from P. Kellogg, NRC, to W. Parker, Jr., Duke Power Company, regarding NRC Inspection Report Nos. 50-269/81-14, 50-270/81-14, and 50-287/81-14, July 23, 1981.
Letter from W. Parker, Jr., Duke Power Company, to J. O'Reilly, NRC-II, 6.
re:
Oconee Nuclear Station, Docket No. 50-269, dated July 31, 1981.
7.
Letter from P. Kellogg, NRC, to R. Leasburg, VEPC0, transmitting IE i
Inspection Reports Nos. 50-338/81-21 and 50-339/61-18, dated September 18, 1981.
i These referenced documents and all IE Information Notices, Bulletins, and Circulars mentioned in the report, are available in the NRC.Public Document-Room at 1717 H Street, Washington, DC 20555, for inspection and/or copying i
for a fee.
Copies may also be obtained from the editor.
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