ML20099L270
| ML20099L270 | |
| Person / Time | |
|---|---|
| Site: | Vogtle  |
| Issue date: | 09/06/1995 |
| From: | GEORGIA POWER CO. |
| To: | |
| References | |
| OLA-3-A-171Q, NUDOCS 9512200265 | |
| Download: ML20099L270 (9) | |
Text
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GPC EXHIUTT II-171-Q c
t/l]ID EX. C.17 i
.J DOCKETED USHRC TITLE
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OFFICE OF SECRETARY 00CKETING & CERVICE BHANCii
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Mgr. Engr. Supt.
Date Mgr. HP/ Chem.
Date hdJ/&
/SlY/b r
/
gr. Toth. Supt.
Date Mgr. Maint.
Date
/
/
Mgr. Admin.
Date Mgr. Ops.
Date
/
/
Mgr. Trng.
Date Mgr. Out./ Plan Date
/
/
{
Asst. General Mgr. - Support D ts Asst. General Mgr. - Operations Date i
1
[0-f,(
PRD p Mtg. No.
Please review, sign where appropriate al.d return to I
./l by If there are any questions, please call n
at extension 8/df.
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5 M yo NUCLEAR REGULATORY COMMISSION Docket No. 50-424/4?5 OLA-3 EXHIB!TNO, G /t' IT-I'tIQ In the natte o' terale swe@ et d.. voette Units 1 a ?
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On 3-20-90, Unit I was in a refueling outage and Unit 2 was operating at 100%
power.
At 0820 CST, the driver of a fuel truck in the switchyard backed into a support for the phase "C" insulator for the Unit 1 Reserve Auxiliary Transformer (RAT) 1A. The insulator and line fell causing a phase to ground fault.
Both Unit 1 RAT 1A and Unit 2 RAT 2B High Side and Low Side breakers tripped, causing a loss of offsite power condition (LOSP). Unit 1 Diesel Generator (DG) 1A and Unit 2 DG2B started, but DGIA tripped, causing a loss of residual heat removal (RHR) to the reactor core since the Unit 1 Train B RAT and DG were out of service for maintenance. A Site Area Emergency (SAE) was declared and the site Emergency Plan was implemented. The Reactor Coolant System heated up to 136 degrees F from 90 degree F before the DG was emergency started at 0856 CST and RHR was restored. The initial notifications were not made within the required 15 minutes due to the loss of power to the Emergency Notification Network after onsite po,wer was(ENN). At 0915 CST, the SAE was downgraded to an restored.
The direct cause of this series of events was a cognitive personnel error. The truck driver failed to use proper backing procedures and hit a support, causing the phase to ground fault and LOSP. The most probable cause of the DGIA trip was the intermittent actuation of the DG jacket water temperature switches.
Corrective actions include strengthening policies for control of vehicles.
ertensive testing of the DG, replacement of suspect DG temperature switches, and improvements in the ENN system.
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REQUIREMENT FOR REPORT This event is reportable per: a) 10 CFR 50.73 (a)(2)(iv), because an unplanned Engineered Safety Feature (ESF) actuation occurred when the ESF Actuation System Sequencer started, and b) Technical Specification 4.8.1.1.3, because a valid diesel generator failure occurred. Additionally, this report serves as a sumary.of the Site Area Emergency event.
B.
UNIT STATUS AT TIME OF EVENT i
Unit I was in Mode 6 (Refueling) at 0% rated thermal power. The reactor had
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l been shut down since 2-23-90 for a 45 day scheduled refueling outage. The j
reactor core reload had been completed, the initial tensioning of the 4
reactor vessel head studs was complete, and the outage team was awaiting permission from the control room to begin the final tension ng.
Reactor Coolant System (RCS)l (RHR) pump in service for decay heat remov Residual Heat Remova The temperature of the RCS was being maintained at approximately 90 degrees F.
Due to the refueling outage maintenance activities in progress, some equipment was out of service and several systems were in abnonnal configurations. The Train 8 Diesel Generator (DGlB) was out of service for a required 36 month maintenance inspection. The Train B Reserve Auxiliary Transformer (RAT IB) had been removed from service for an oil change.
4 The Train B Class IE 4160 Volt switchgear, IBA03, was being powered from the Train A RAT 1A through its alternate supply breaker. All non-lE switchgear was being powered from the Unit Auxiliary Transformers (UAT) by backfeeding from the switchyard. All Steam Generator (S/G) nozzle dams had been i
removed, but only S Maintenance personn/G's 1 and 4 had their primary manways secu on S/G's 2 and 3.
RCS level was being maintained at mid-loop for valve repairs and the S/G manway restorations.
In addition, the pressurizer 4
manway was removed to provide an RCS vent path.
C.
DESCRIPTION OF EVENT i
i on March 20, 1990, at approximately 0817 CST, a truck driver with a security escort entered the protected area in a fuel truck. Although not a member of the plant operating staff, the driver was a Georgia Power Company employee belonging to a service group used to perform various plant services. The driver checked the welding machine that was tr. the area and found that it did not need fuel. He returned to the fuel truck and was in the process of backing out of the area when he hit a support holding the phase 'C' insulator for RAT 1A. The insulator and line fell causing a phase to ground j
fault, and the transformer breakers tripped.
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At 0820 CST, both Unit 1 RAT 1A and the Unit 2 RAT 28 High Side and Low Side breakers tripped causing a loss of offsite power condition (LOSP) to the Unit 1 Train A Class lE 4160 volt Bus 1AA02, the Unit 2 Train B Class IE Bus 2BA03, and the 480 volt busses supplied by 1AA02 and 2BA03.
The Unit 1 Train B Class 1E 4160 volt bus IBA03 also lost power since RAT 1A was feeding both Trains of Class lE 4160 volt busses.
The loss of power caused the associated ESF Actuation System Sequencers to send a start signal to one Unit I and one Unit 2 Diesel Generators.
DGIA and DG2B started and sequenced the loads to their respective busses.
Further description of the Unit 2 response to this event is provided in LER 50-425/1990-002.
i One minute and twenty seconds after DG1A started and sequenced the loads to the Class 1E bus, the engine tripped. This again caused an undervoltage (UV) condition to class IE bus IAA02. The UV signal is a maintained signal at the sequencer.
However, since DGIA was coasting down from the trip, the shutdown logic did not allow the DG fuel racks or starting air solenoids to i
open and start the engine. This properly caused the engine starting logic to lock up, a condition that existed until the UV signal was reset. For this reason, DGIA did not automatically re-start after it tripped.
After the trip, operators were dispatched to the engine control panel to investigate the cause of the trip.
According to the operator, several annunciators were lit.
The operator briefly reviewed several instrument read-outs and detected no imediate problem.
In order to restore emergency power, the operator reset the annunciators without delaying to evaluate or record the annunciators that were present.
During this time, a Shift Supervisor (SS) and a Plant Equipment Operator (PEO) went to the sequencer panel to detemine if any problems were present on the 1A sequencer. The SS pushed the UV reset button, then reset the sequencer by deenergizing and energizing the power supply to the sequencer.
This caused the DG air start solenoid to energize for another 5 seconds which caused the en This happened 19 minutes after the DG tripped the first time. gine to start.
The engine started and the sequencer sequenced the available loads as designed.
After 1 minute and 10 seconds, the breaker and the engine tripped a second time., *-
It did not automatically re-start due to the starting logic being blocked as described above.
By this time operators, a maintenance foreman and the diesel generator vendor represe,ntative were in the DG room.
The initial report was that the jacket water pressure trip was the cause of the trip.
This report was discounted because the maintenance foreman and vendor representative observed that the jacket water pressure at the gauge was about 12-13 PSIG. The trip setpoint is 6 PSIG and the alam setpoint is 8 i
PSIG.
Also, the control room observed a lube oil sensor salfunction alarm.
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= a,,ce a,uvem Fifteen minutes after the second DGIA trip, DGIA was started from the engine control panel using the emergency start breakglass button.
- The engine started and loads were manually loaded. When the DG is started in the emergency mode, all the trips except four are bypassed.
However, all alarms will be annunciated. During the emergency run no trip alarms were noticed by the personnel either at the control room or,at the engine control panel.
The only alarms noted by the control room operator assigned for DG operation were lube oil pressure sensor malfunction and fuel oil level high/ low alarm, neither of which would have tripped the diesel.
At 1040 CST, RAT 3B was energized to supply power to 4160 volt bus IBA03, DGIA supplied power to 4160 volt bus IAA02 until 1157 CST, at which time bus 1AA02 was tied to RAT 18.
A Site Area Emergency was declared at 0840 CST, due to a loss of all offsite and onsite AC power for more than 15 minutes.
The Emergency Director signed the notification fonn used to inform offsite government agencies of the emergency at 0848 CST. The shift clerk attempted to initiate offsite notification utilizing the primary ENN in the control room but found it inoperable due to loss of power.
The shift clerk then went to the back-u 0857 CST. p ENN and initiated notification after roll call on this system at Due to the loss of power, which rendered the primary Emergency Notification Network (ENN) inoperable, and some mis-communication, the initial notification was not received by all agencies until 0935 CST.
The Emergency Director instructed personnel to complete various tasks for restoring containment and RCS integrity. All work was accomplished and maintenance personnel exited containment by 1050 CST.
I The SAE was downgraded to an Alert Emergency at 0915 CST after restoration of core cooling and one train of electrical power. By 12')0 CST, plant conditions had stabilized with both trains of electrical power being supplied from an offsite source (RAT 18.
After discussions with the NRC and local government agencies, the emerg)ency was terminated at 124 all agencies were notified by 1256 CST.
f D.
CAUSE OF EVENT Direct Cause:
1.
The direct cause of the loss of offsite Class IE AC power was the fuel truck hitting a pole supporting a 230kV line for RAT 1A. This was a cognitive personnel error on the part of the truck driver. There were no unusual characteristics of the work location that directly contributed to this personnel error.
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2.
The direct cause of the loss of onsite Class IE AC power was the failure of the operable DG, DGIA, to start and load the LOSP loads on buss IAA02.
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The direct cause of the failure of the primary ENN system in the control room was the loss of electrical power to Unit 1.
The primary ENN in the control room is powered from Unit 1 Class IE AC sower.
Therefore, when Unit I lost Class IE AC electrical power, tie primary ENN in the control room did not work.
Root Cause:
1.
The truck driver met all current site training and qualification requirements, including holding a Class 2 Georgia driver's ifcense.
However, site safety rules, which require a flagman for backing vehicles when viewing 1.s impaired, were violated.
1 2.
The root cause for the failure of DG1A has not been conclusively deternined. There is no record of the trips that were annunciated after the first trip because the annunciators were reset before the condition was fully evaluated.
Therefore, the cause of the first trip
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can only be postulated, but it was most likely the same as that which caused the second trip.
The second trip occurred at the end of the timed sequence of the group 2 block logic. This logic allows the DG to achieve operating conditions before the trips become active.
The block logic timed out and the trip occurred at about 70 seconds.
The annunciators observed at the second trip included jacket water high temperature along with other trips.
In conducting an investigation, the trip conditions that were observed on the second DG trip on 3-20-90 could be duplicated by venting 2 out of 3 jacket water temperature sensors, simulating a tripped condition.
The simulation duplicated both the annunciators and the 70 sec. trip time. The most likely cause of the DG trips was intermittent actuation of the jacket water temperature switches.
t Following the 3-20-90 event, all three jacket water temperature switches, which all have a design setpoint of 2000F, were bench tested.
Switch TS-19110 was found to have a setpoint of 197 degrees F, which was approximately 6 degrees below its previous setting. Switch TS-19111 was found to have a setpoint of 199 degrees F, which was i
approximately the same as the original setting. Switch TS-19112 was j
found to have a setpoint of 186 degrees F, which was approximately 17 degrees F below the previous setting and was re-adjusted.
Switch TS-19112 also had a small leak which was judged to be acceptable to support diagnostic engine tests and was reinstalled. The switches were recalibrated with the manufacturer's assistance to ensure a consistent calibration technique.
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During the subsequent test run of the DG on 3-30-90, one of the j
switches (TS-19111) tripped and would not reset. This appeared to be an intermittent failure because it subsequently mechanically reset, i
This switch and the leaking switch (TS-19112) were replaced with new switches. All subsequent testing was conducted with no additional problems.
1 A test of the jacket water system temperature transient during engine starts was conducted. The purpose of this test was to determine the 4
actual jacket water temperature at the switch locations with the engine j
in a normal standby lineup, and then followed by a series of starts without air rolling the engine to replicate the starts of 3-20-90. The test showed that -jacket water temperature it the switch location decreased from.a. standby temperature of 163 degrees F to approximately 156 degrees F and remained steady.
Numerous sensor calibrations (including jacket water temperatures),
special pneumatic leak testing, and multiple engine starts and runs 2 id/a.'"'
were performed under various conditions. -Af-t+r-the 3 20 90 cventy[the i
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control systems of both engines % ave been subjected to a comprehensive i
test program. Subsequent-te-tMs-test-program -DGIA-and-0GM-have b::n r
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-started-at-least-la-t hes-eachand-no-fathres-er-problems-h:ve-
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Based on the above facts, it is concluded that the jacket water high j
temperature switches were the most probable cause of both trips on 1
3-20-90.
1 E.
ANALYSIS OF EVENT The loss of offsite power to Class IE bus IBA03 and the failure of DGlA to start and operate successfully, coupled with DGlB and RAT IB being out of 1
3 service for maintenance, resulted in Unit I being without AC power to both Class IE busses. With both Class 1E busses deenergized, the RHR System could not perform its required safety function. Based on a noted rate of rise in the 4tC5 Lyn.h M619egnes T 'in 361minutues, the ItC5 water would not have been expected to begin boiling until approximately I hour and l
36 minutes after the beginning of the event.
Restoration of RHR and closure of the containment equipment hatch were completed well within the estimated J hour and 36 minutes for the projected 4
onset of boiling in the RCS. A review of information obtained from the g
Process and Effluent Radiation Monitoring System (PERMS) and grab sample analysis indicated all normal values. As a result of this event, no o
increase in radioactive releases to either the containment or the
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envtronment occurred.
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Additional systems were either available or could have been made available to ensure the continued safe operation of the plant:
4 1.
The maintenance on RAT IB was completed and the RAT was returned to 4
service approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> into the event.
i 2.
Offsite power was available to non-lE equipment through the generator step-up transformers which were being used to 'back-feed' the Unit Auxiliary Transformers (UAT) and supply the non-1E busses.
Provided that the phase to ground fault was cleared, Class IE busses IAA02 and j
IBA03 could have been powered by feeding through non-lE bus INA01.
3.
The Refueling Water Storage Tank could have been used to manually establish gravity feed to the RCS to maintain a supply of cooling water j
to the reactor.
b-Consequently, neither plant safety nor the health and safety of the public 4
was adversely affected by this event. A more detailed assessment of this event and an assessment of the event had it occurred under more severe j
circumstances will be performed and included in a supplemental LER.
F.
CORRECTIVE ACTIONS 1.
A management policy on control and operation of vehicles has been established.
2.
Temporary barricades have been erected with signs which direct authorization for control of switchyard traffic to the SS.
3.
The loss of Offsite Power (LOSP) diesel start and trip logic has been modified on Unit I so that an automatic ' emergency' start will occur upon LOSP. Therefore, non-essential diesel engine trips are blocked l
upon LOSP. The Unit 2 DG's will be modified by 4-30-90.
4.
The QGIA ' test frequency was increased to three times per week until 4-20-90 when the test frequency will be changed to once every 7 days in accordance with Technical Specification Table 4.8-1.
This frequency will be continued until 7 consecutive valid tests are completed with no more than one valid failure in the last 20 valid tes'ts.
Including the two valid failures of this event, there have been a total of four valid failures in 69 valid tests of DGIA as of 1157 CST on 3-20-90.
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5.
The defective DG temperature switches have been replaced.
In addition, a test program will be conducted at Wyle Laboratories to investigate the reliability of this type of temperature switch under various conditions.
This program is designed to aid in detenntning the failure mode of the i
suspect switches.
4 6.
A back-up ENN' system powered from the AT&T system, which previously existed and was operational for South Carolina agencies, has been extended to include Georgia local and state agencies.
Instructions have been given to Emergency Directors and Comunicators concerning use of the emergency comunication systems.
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7.
Furth'er corre'etive actions will be addressed in a supplemental LER.
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ADDITIONAL INFORMATION 1.
Failed Compone'nts:
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Jacket Water High Tempeiature Switches manufactured by California Controls Company.-
1 Model fA-3500-W3 -
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2.
Previous Stallar Events:
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None
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3.
Energy Industry Identification System Code:
3pv.-e Reactor Coolant Systes - AB 1
Residual Heat Removal Systes - B Diesel Generator' Lube Dil System - LA Diesel Generator Starting Air System - LC i
Diesel Generator. Cooling Water System - LB Diesel Generator Power Su Safety injection' Syste,s: pply System - EK i
BQ
- 13.8 kV Power sten ~j-;EAYPl.
1460 volt' non,-
power.systes '- EA 1460'v01t Class.1E'powe'r system - EB Chemical and Volume Control System - CB Containment Butiding' NN P' 480 volt Class.1E Pow,er Sy' stem - ED Engineered Safety Features Actuation System - JE 4
Radiation Monitoring System..IL l).
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