ML20091J010

Intervenor Exhibit I-MOSBA-62,consisting of Re Loss of Offsite Power Leads to Site Area Emergency

ML20091J010
Person / Time
Site:	Vogtle
Issue date:	05/17/1995
From:	Hairston W GEORGIA POWER CO.
To:
References
OLA-3-I-MOSBA62, NUDOCS 9508170188
Download: ML20091J010 (11)

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'95 JUL 27 A9:5' W. G. Hairston, til sen.or V.ce Pres dent Nucwar Operarons gpyjgggrUEC" ELV-01729 DGCY:TV n479

-June 29, 1990 Docket No.

50-424 NUCLEAR REGULATORY COMMISS!ON Docket No. 50-424/425-Ot.A-3 EXHIBITNO. 1%t d 2 U. S. Nuclear Regulatory Commission in in,, natter of Georai Power co. et ei. voatie Unit. $ a 2 ATTN:

Document Control Desk O statt O Appheant @ intervenor O Other Washington, D. C.

20555 g ioentmed O Received O RejectM Reporter CR nate er-n - w witne..

5+.% Iated

, Gentlemen:

V0GTLE ELECTRIC GENERATING PLANT LICENSEE EVENT REPORT LOSS OF OFFSITE POWER LEADi TO SITE AREA EMERGENCY In accordance with 10 CFR 50.73, Georgia Power Company (GPC) hereby sub 20, 1990.

enclosed revised report related to an event which occurred on March This revicion is necessary to clarify the information rel 19, 1990 and to update the status of corrective 1990 and the LER dated April If the criteria for the completion of the test program is actions in the LER.

understood to be the first successful test in accordance with Vogtle Electric 14980-1 " Diesel Generator Operability Test,"

Generating Plant (VEGP) procedure then there were 10 successful starts of Diesel Generator IA and 1 starts of Diesel Generator 18 between the completion of the test program and the end of April 19, 1990, the date the LER 50-424/1990-06 was submitted to the N The number of successful starts included in the original LER included some of The difference is attributed to the starts that were part of the test program.

diesel start record keeping practices and the definition of the end of the test,

program.

In order to correct the LER and to provide more useful and up to date information the LER has been revised to state the number of valid die generator tests in accordance with Regulatory Guide 1.108 rather than the nu The number of" val'it test's~was estaMished of successful starts since the event.

by reviewing diesel generator testing data from March 21 through June 7, 1990 Sincerely, 40, $.

T W. G. Hairston, III WGH,Ill/HWM/gm

Enclosure:

LER 50-424/1990-006-01 I CU."uws 92 pgo, 686 Od0k $$jf{

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-.bsorgiaPower Exhibit

,page of U. S. Nuclear. Regulatory Comission ELV-01729 1

'xc: 'Georata Power Company

.Mr. C. K. McCoy.

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Mr. G.; Bockhold, Jr.

Mr. R. M.'Odom Mr.,R. D. Rushton.

NORMS'

. U. S.' Nuclear Reculatory Comission l

Mr. S. D. Ebneter, Regional Administrato'r Mr. T. A. Reed, Licensing Project Manager; NRR -

'Mr.'B. R. Bonser, Senior Resident Inspector, Vogtle 4

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On 3-20-90, Unit I was irCa' refueling ;outagef and Unit;2:was operating at '100%

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~ 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 power.

(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 l

a loss of offsite power condition (LOSP). Unit 1 Diesel Generator (OG) 1A and Unit 2 DG28 started, but DGIA tripped, causing a loss of residual heat removal (RHR) to the reactor core since the Unit ! Train B RAT and DG were out of j

l A Site Area Emergency (SAE) was declared and the site service for maintenance.

Emergency,. Pl an, was, impl emented. The Reactor Coolant System heated up to 136 degrees F from 90 degrees F before the DG was emergency started at 085F CST'ana' The initial notifications were not made within the required RHR was restored.

15 minutes due to the loss of power to the Emergency Notification Network (ENN),

At 0915 CST, the SAE was downgraded to an Alert after onsite power was restored.

The The direct cause of this series of events was a cognitive personnel error.

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, extensive testing of the DG, replacement of suspect DG temperature switches, and improvements in the ENN system.

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REQUIREMENT FOR REPORT Y

a) 10 CFR 50.73 (a)(2)(iv), because an 1

This event is reportable per:

unplanned.Engipeered Safety Feature (ESF) actuation occurred when the ESF j

Actuation System Sequencer started, and b)-TecNnical Specificatioh" 4.8.1.1.3, because a valid diesel generator failure occurred.. Additionally, i.

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-this report serves as a sumary of the Site Area Emergency event.

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UNIT STATUS AT TIME OF EVENT The reactor had Unit I was in Mode-6 (Refueling) at 0% rated thermal power.

i The been shut down since 2-23-90 for a 45 day scheduled refueling outage.

j reactor core reload had been completed, the initial tensioning of the l

-reactor vessel head studs was complete, and the outage team was awaiting i

I Reactor l

permission from the control room to begin the final tensioning.

Coolant System (RCS) level was being maintained at mid-loop with the Train A l

j The Residual Heat Removal (RHR) pump in service for decay heat removal.

1 temperature of the RCS was being maintained at approximately i

90 degrees F.

Due to the refueling outage maintenance activities in progress, some equipment was out of service and several. systems were in abnormal The Train B Diesel Generator (DG18) was out of service for configurations.

a required 36 month maintenance. inspection.cThe-Tr41n BiReserve' Aux 111ary."

Transformer (RAT 18) had-been removed from service for'an'ailechangemTher = =.

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Train B Class IE 4160 Volt switchgear, IBA03, was being powered from the i

Train A RAT 1A through its alternate supply breaker. All non-lE switchgear l

was being powered from the Unit Auxiliary Transformers (UAT) by backfeeding l

from the switchyard. All Steam Generator (S/G) nozzle dams had been j

removed, but only S/G's 1 and 4 had their primary manways secured.

Maintenance personnel were in the process of restoring the primary manways j

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 i

manway was removed to" provide an~RCS vent. path..

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DESCRIPTION OF EVENT 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 empic3ee l.

The belonging to a service group used to perform various plant services.

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driver. checked the welding machine that was in the area and found that it did not need' fuel.

He returned to the fuel truck and was in the. process of L

backing out of the area when he hit a support holding the phase "C" j

insulator for RAT 1A. The insulator and line fell causing a phase to ground fault, and the transformer breakers tripped.

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At 0820 CST, both Unit 1 RAT 1A and the Unit 2 RAT 2B High Side and Low Side breakers tripped causing a l'oss of'offsite power condition (LOSP)' to the Unit 1 Train A Class IE 4160 volt bus IAA02, the Unit 2 Train B Class IE bus

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28A03, and the 480 volt busses supplied by 1AA02 and 2BA03.

Train 8 Class IE 4160 volt bus IBA03 also lost power since RAT 1A was 4

The loss of power caused i

feeding both Trains of Class 1E 4160 volt busses.

the associated ESF Actuation System Sequencers to send a start signal to one I

DGIA and DG2B started and sequenced Unit I and one Unit 2 Diesel Generator.Further description of the Unit 2 l

the loads to their respective busses.

response to this event is provided in LER 50-425/1990-002.

l One minute and twenty seconds after DGIA started and sequenced the loads to l

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the Class IE bus, the engine tripped. This again caused an undervoltage The UV signal is a maintained signal l

l (UV) condition to class IE bus IAA02.However, since DGIA was coasting down at the sequencer.

shutdown logic did not allow the DG fuel racks or starting air solenoids to This properly caused the engine starting logic open and start the engine.

For to lock up, a condition that existed until the UV signal was reset.

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' tripFAcco~ dinitrthe'~ operator, several r

The operator briefly reviewed several instrument annunciators were lit.

l read-outs and detected no imediate problem.

In order to restore emergency

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power, the operator reset the annunciators without delaying to evaluate or record the annunciators that were present. During this time, a Shift l

Supervisor (SS) and a Plant Equipment Operator (PEO) went to the sequencer The SS panel to determine if any problems were present on the 1A sequencer.

l pushed the UV reset button, then reset the sequencer by deenergizing and l

This caused the DG air start energizing the power supply to the sequencer.

i solenoid te. energize for.anothar 5 seconds..wh.ich caused the engine. to start.

The engine This happened 19 minutes after the DG tripped the first time.

After started and the sequencer sequenced the available loads as designed.

i 1 minute and 10 seconds, the breaker and the engine tripped a second time.

i 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 The initial diesel generator vendor representative were in the DG room.

report was that the jacket water pressure trip was the cause of the trip.

This report was discounted because the maintenance foreman and vendor l

representative observed that the jacket water pressure at the gauge was l

The trip setpoint is 6 PSIG and the alarm setpoint is 8 about 12-13 PSIG.

Also, the control room observed a lube oil sensor malfunction alarm.

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,acitsf 7 esaast its saa o js lo lo le l4 ! 2!4 910 0l0l 6 011014 oF 01 9 VEGP - UNIT 1 wr a mae e manmm Fifteen minutes after the second DGIA trip, DGIA was started from the engine g The engine control panel using the emergency start breakglass button.When the DG is starte

=r started and loads were manually loaded.

However, all alarms E emergency mode, all the trips except four are bypassed.During th will be annunciated.

by.the.per, sonne] 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 IB 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 g

1AA02 was tied to RAT 18.

A Site Area Emergency was declared at 0840 CST, due to a loss of all offsite The Emergency Director signed and onsite AC power for more than 15 minutes.

the notification form used to inform offsite government agencies of the The shift clerk attempted to initiate offsite emergency at 0848 CST.

notification utilizing the primary ENN in the control room but found it The shift clerk then went to the back-up inoperable due to loss of power.

ENN and initiated notification after roll call on this system at 0857 CST.

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 lnWuEted peysonnel'to.. complete 'various.hsks. fo f

restoring containment and'RCS"integ~rityi. ~ All work was accomplished and~~~

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maintenance personnel exited containment by 1050 CST.

The SAE was downgraded to an Alert Emergency at 0915 CST after restoration i

of core cooling and one train of electrical power. By 1200 CST, plant conditions had stabilized with both trains of electrical power being l

After discussions with the NRC supplied from an offsite source (RAT 18).and local government ag all agencies were notified by 1256 CST.

4 D.

CAUSE DF EVENT Direct Cause:

4 The direct cause of the loss of offsite Class IE AC power was the fuel l

1.

This was a truck hitting a pole supporting a 230kV line for RAT 1A.

There were cognitive personnel error on the part of the truck driver.

no unusual characteristics of the work location that directly l-L contributed to this personnel error.

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The direct cause of the loss of onsite Class IE AC power was the failure 2.

of the operable DG, DGIA, to start and load the 1.0SP loads on bus IAA02.

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ruwe n ame % as.onm The direct cause of the failure of the primary ENN system in the 3.

control room was the loss of electrical power to Unit 1.

The primary 1 ENN in the control room is powered from Unit 1 Class IE AC power.

Therefore,.whan Unit 1.losts Class. lE. AC electrical power, th,e primary j l

ENN in the control room did not work.

g Root Cause:

L The truck driver met all current site training and qualification 1.

requirements, including holding a Class 2 Georgia driver's ifcense.

I However, site safety rules, which require a flagman for backing L

vehicles when viewing is impaired, were violated.

l The root cause for the failure of DGIA has not been conclusively 2.

There is no record of the trips that were annunciated determined.

after the' first trip because the annunciators were reset before the l

condition was fully evaluated. Therefore, the cause of the first trip can only be postulated, but it was most likely the same as that which caused the :;econd trip. The second trip occurred at the end of the timed sequence of the group 2 block logic. This logic allows the DG to The block l

achieve operating conditions before the trips become active.

logic timed out and.the. trip occurred.at aboutJ0. seconds..The.%...

annunciators observed'at the+second; trip included jacketcwater, high:::....

' temperature along with other-tripsrIn 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 intemittent actuation of the jacket water temperature switches.

Following the 3-20-90 event, all three jacket water temperature switches, which all have a design setpoint of 2000F, were bench tested.

Switch TT-19Il0"was found to-hive' r setpoint of-19Fdegreesr F; whick Switch was approximately 6 degrees below its previous setting.

T5-1911) was found to have a setpoint of 199 degrees F, which was Switch TS-19112 was approximately the same as the original setting.

found to have a setpoint of 186 degrees F, which was approximately 17 Switch degrees F below the previous setting and was re-adjusted.

TS-19112 also had a small leak which was judged to be acceptable to The switches were support diagnostic engine tests and was reinstalled.

recalibrated with the manufacturer's assistance to ensure a consistent calibration technique.

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rn During the subsequent tist run of the DG on 3-30-90, one of the switches (TS-19111) tripped and would not reset. This appeared to be E.

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an intermittent failure because it subsequently mechanically reset.

This switch and the leaking switch (TS-19112) were replaced with new All subsequent, testing was conducted with no additional switcheA.

1 problems.

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A test of the jacket water system temperature transient during engine i

starts was conducted.

The purpose of this test was to determine the actual jacket water temperature'at the switch locations with the engine i

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in a normal standby lineup, and then followed by a series of starts a

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without air rolling the engine to replicate the starts of 3-20-90.

test showed that jacket water temperature at the switch location decreased from a standby temperature of 163 degrees F to approximately 156 degrees F and remained steady.

Humerous sensor calibrations (including jacket water temperatures),

special pneumatic leak testing, and multiple engine starts and runs i

After the 3-20-90 event, the were performed under various conditions.

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control systems of both engines were subjected to a comprehensive test Additionally, the jacket water high temperature switches were program.

sent to an independent laboratory, which found the switches set at 2

l temperatures ranging from 162 degrees F to_195 degrees F rather than The calibration technique i

the 200 degree F setting that was. required.

lled'on DGlB on-

.was changed 'an'd1 witches were're-calibrated and insta

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HokeE'anothef failure occurred on DGIB-(See Technical. -

j 5-23-90.

These switches were also sent Specification Special Report 1-90-4.)found the settings to be from 164 i

to the independent laboratory, which l

degrees F to 169 degrees F.

Subsequent to this testing, the onsite calibration procedure was again revised to provide a technique that is consistent with the actual operating conditions that the switches t

Switches were calibrated using this new technique, experience.

i Since installed and found to operate within the expected parameters.

the event of 3-20-90 through 6-7-90, DG1B had received 12 valid tests l

with the one faflure mentioned-above; and DG1A host receive 616-yalid.

tests with no failures.

l Based on the above facts, it is concluded that the jacket water high f

l temperature switches were the most probable cause of both trips on i

3-20-90.

i The investigation and testing following the 3-20-90 event revealed that J

pressure sensors in the diesel generator lube oil system had not been replaced in accordance with a 10 CFR 21 notification from the The 10 CFR 21 notification was confusing l

manufacturer dated 5-12-88.

relative to the requirements for their replacement.

It was subsequently revised in an addendum dated 6-8-90. The pressure trip i

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l GPC does not believe that these sensors contributed to instructions.

the diesel. generator trip on 3-20-90.

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ANALYSIS OF EVENT The loss of offsite power to Class IE bus IBA03 and the failure of DGIA to start and. operate successfully, coupled with DGlB and RAT IB being out of service for maintenance, resulted in Unit I being without AC power to both With both-Class IE busses deenergized, the RHR System i

Class IE busses.

Based on a noted rate of could not perform its recuired safety function.

rise in the RCS temperature of 46 degrees F in 36 minutues, the RCS water l

would not have been expected to begin boiling until approximately 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and Using more conservative i

36 minutes after the beginning of the event.

assumptions and methods, but the same actual time of the event, the i

calculated worst case time to boiling was found to be approximately I hour l

[

l and 11 minutes, and time to core uncovering was found to be approximately 11 This assumed no gravity feed from the RWST.

hours and 5 minutes.

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3 Restoration of RHR and closure of the containment equipment hatch were i

completed well within the estimated I hour and 36 minutes for the projected j

onset of boiling in the'RCSE A review of information obtained from the Proce'ss and Effluent Radiation Monitoring System (PERBS) and grab sample analysis indicated al1~ norm 11' values. - As a< result-of this event," no'

~^

increase in radioactive releases to either the containment-or the' j

environment occurred, Additional systems were either available or could have been made available f

to ensure the continued safe operation of the plant:

The maintenance on RAT IB was completed and the RAT was returned to 1

1.

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.

Offsite power was avafTable"tb nonalE eqtripment'through the generator 2.

step-up transformers which were being used to "back-feed" the Unit and supply the non-lE busses.

Provided Auxiliary Transformers (UAT)lt was cleared, Class IE busses lAA02 and that the phase to ground fau IBA03 could have been powered by feeding through non-lE bus INA01.

The Refueling Water Sterage Tank could have been used to manually 3.

establish gravity feed to the RCS to maintain a supply of cooling water to the reactor.

Consequently,' neither plant safety nor the health and safety of the public i

1 was adversely affected by this event.

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CORRECTIVE ACTIONS A management policy on control and operation of vehicles has been 1.

established.

Temporary barricades have been erected with signs which direct 2.

authorization for control of switchyard traffic to the SS.

g The Loss of Offsite Power (LOSP) diesel start and trip logic has been

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3.

Il modified on both Unit I and Unit 2 so that an automatic " emergency" start will occur upon LOSP. Therefore, non-essential diesel engine 9-trips are blocked upon LOSP. Additionally, high jacket water temperature has been deleted as a trip signal in the emergency start

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I mode.

The DGIA test frequency was increased to three times per week until l

4.

4-20-90 when the test frequency was changed to once every 7 days in p

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 tests.

Up to and including the two valid failures of the 3-20-90 event, there were a l

valid tests of DGIA.

, total of four valid failures. in

5. iThe jacket water temperature switches for each DG were replaced or

're-calibrated using a more appropriate technique prior to their installation.

A back-up ENN system powered from the AT&T system, which previously L

6.

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 Communicators concerning use of l

the emergency communication systems.

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ADDITIONAL.INFORMATION

t 1.

Failed Components:

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Jacket Water High Temperature Switches manufactured by California

. Controls Company.

Model #A-3500-W3 2.

Previous Similar Events:

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92 PROJECT

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Enemy hidastry Identifieation System Code:

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.o Reactor Coolant System - AB l

&l Residual Heat Removal System - BP Diesel Generator Lube 011 System - LA Diesel Generator Starting Air System - LC Diesel Generator Cooling Water System - LB 9.

Diesel Generator Power Supply System - EK L

Safety Injection System - BQ 13.8 kV Power System - EA 4160 volt non-1E power system - EA 4160 volt Class 1E power system - EB Chemical and Volume Control System - CB Containment Building - NH 480 volt Class IE Power System - EO Engineered Safety Features Actuation System - JE i

Radiation Monitoring System - IL l

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