ML20083D037

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

ML20083D037
Person / Time
Site:	Vogtle
Issue date:	04/17/1995
From:	Hairston W GEORGIA POWER CO.
To:
References
OLA-3-I-MOS-062, OLA-3-I-MOS-62, NUDOCS 9505230331
Download: ML20083D037 (12)

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MY -3 P5 :01 J W. G. Heltston, m Senor Vce Pres. cent I Noctear Operarons ELV-01729 I 0FFICE OF SECREMRY 947o DOCKETING & ZRVICE June 29,1990 BRANCH f Docket No. 50-424 f U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D. C. 20555 Gentlemen:

V0GTLE ELECTRIC GENERATING PLANT LICENSEE EVENT REPORT ,

LOSS OF OFFSITE POWER LEADS TO SITE AREA EMERGENCY  !

In accordance with 10 CFR 50.73, Georgia Power Company (GPC) 20, hereby 1990. submits tl enclosed revised report related to an event which occurred on March i This revision is necessary to clarify the information related to the number of l successful diesel generator starts as discussed in the GPC letter dated April 9, l 1990 and the LER dated April 19, 1990 and to update the status of corrective l actions in the LER.

If the criteria for the completion of the test program is l

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

Generating Plant (VEGP) procedurethen there were 10 successful starts o:

l starts of Diesel Generator 18 between the completion of the test program and the l end of April 19, 1990, the date the LER 50-424/1990-06 was submitted to the NRC. i The number of successful starts included in the original LER included some of the starts that were part of the test program. The difference is attributed to  ;

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 diesel generator tests in accordance with Regulatory Guide 1.108 rather than the num Th'e number of"valittest's~was established of successful starts since the event.

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

Sincerely, th;h. E ,

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

Enclosure:

LER 50-424/1990-006-01  :

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NUCLEAR REGULATORY COMMISSION Ss- s ts.c u-1 Docket No. Fa "l1s -c' A - 3 0iticial Exh. No. 1 ^ + b 2 in tt:c m3cr et ( A '+ s (+ 2 de3484 StaN IMNilFIED v Appheant iCEIVED intervenar / _ _Pl.JECTED Contg Ottr DATE o 4 - I'l-9 5 o'i - IB- 9 7 Contractor Other Witness AA e 6 o '

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xc: Georoia Power Comoany Mr. C. K. McCoy Mr. G. Bockhold, Jr.

Mr. R. M. Odom Mr.. R. D. Rushton. .

NORMS U. S. Nuclear Reaulatory Commission Mr. S. D. Ebneter, Regional Administrator Mr. T. A. Reed, Licensing Project Manager, NRR ,

'Mr. B. R. Bonser, Senior Resident Inspector, Vogtle O ._

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On 3-20-90, Unit I was irik refueling ;outagef 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 l (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 A Site since Areathe Unit 1 Train Emergency (SAE) was B RAT declared andand DGthe were site out of service for maintenance.

Emergency. Pim was, implemented.. The Reactor Coolant System heated up to 136 degrees F from 90 degrees 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 (ENN).

At 0915 CST, the SAE was downgraded to an Alert after onsite power was 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, extensive testing of the DG, replacement of suspect DG temperature switches, and improvements in the ENN system.

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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) Tec'Hnical Specificatioh" 4.8.1.1.3, because a valid diesel generator failure occurred. Additionally, ,

I this report serves as a summary of the Site Area Emergency event.

B. UNIT STATUS AT TIME OF EVENT Unit I was in Mode 6 (Refueling) at 0% rated thermal power. The reactor had been shut down since 2-23-90 for a 45 day scheduled refueling outage. The reactor core reload had been completed, the initial tensioning of the reactor vessel head studs was complete, and the outage team was awaiting permission from the control room to begin the final tensioning. Reactor Coolant System (RCS) level was being maintained at mid-loop with the Train A Residual Heat Removal (RHR) pump in service for decay heat removal. The temperature of the RCS was being maintained at approximately 90 degrees F.

Due to the refueling outage maintenance activities in progress, some I I equipment was out of service.and several systems were in abnormal configurations. The Train B Diesel Generator (DG1B) was out of service for a required 36 month. maintenance. inspection.cThe-Train 87 Reserve' Auxiliary .

Transformer (RAT 18) had 'been removed from service for'an oili changen Ther = =: ,

Train B Class 1E 4160 Volt switchgear, 1BA03, was being powered from the Train A RAT 1A through its alternate supply breaker. All non-1E switchgear was being powered from the Unit Auxiliary Transformers (UAT) by backfeeding ,

from the switchyard. All Steam Generator (S/G) nozzle dams had been 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 on S/G's 2 and 3. RCS level was being maintained In at mid-loop for valve addition, the pressurizer repairs and the S/G manway restorations.

manway was removed tanprovide am RCSsvent. path..

C. DESCRIPTION OF EVENT On March 20, 1990, at approximately 0817 CST, a truck driver with a security I 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 in the area and found that it did not need' fuel. He returned to the fuel truck and was in the. "C" process of i backing out of the area when he hit a support holding the phase insulator for RAT 1A. The insulator and line fell causing a phase to ground )

O fault, and the transformer breakers tripped.

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l At 0820 CST, both Unit 1 RAT 1A and the Unit 2 RAT 2B High Side and Low Side

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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 2BA03, and the 480 volt busses supplied by 1AA02 and 28A03. The Unit 1 Train B Class IE 4160 volt bus IBA03 also lost power since RAT 1A was feeding both Trains of Class IE 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 Generator. 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.

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

the Class IE bus, the engine tripped. This again caused an undervoltage (UV) condition to class IE bus 1AA02. 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 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 l I this reason, DGIA did not automatically re-start after;,it.,tr,ipped.

After the trip, operators were dispatched to the engine control panel to j

investigate the cause~ of the' tripF Acco' rding ~trthe" operator, several annunciators were lit. The operator briefly reviewed several instrument j read-outs and detected no immediate problem. In order to restore emergency l

power, the operator reset the annunciators without delaying to evaluate or  !

record the annunciators that were present. During this time, a Shift went to the sequencer Supervisor (SS) and a Plant Equipment Operator (PEO)he 1A sequencer. The SS panel to determine if any problems were present on t 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 l solenoid to-energize.for.anothar Esecondsswhich caused the. engine. to start. 1 This happened 19 minutes after the DG tripped the first time. The engine j started and the sequencer sequenced the available loads as designed. After t I minute and 10 seconds, the breaker and the engine tripped a second time. l It did not automatically re-start due to the starting logic being blocked as l described above. By this time, operators, a maintenance foreman and the diesel generator vendor representative 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 alarm setpoint is 8 PSIG. Also, the control room observed a lube oil sensor malfunction alarm.

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m, re - . - , - o w,nm Fifteen minutes after the second DGIA trip, DGIA was started The fromenginethe engine m control panel using the emergency start breakglass button. 5-started and loads were manually loaded. When the DG is started in the However, all alarms $

emergency mode, all the trips except four are bypassed.During the eme will be annunciated.

I by.the.per.scu2nel either at the control room or at the engine control panel.

The only alarms noted by the control room operator assigned for*DG* operati were lube oil pressure sensor malfunction and fuel oil level high/ low alarm, o neither of which would have tripped the diesel.

At 1040 CST, RAT IB was energized to supply power to 4160 volt bus }BA03.

DGIA supplied power to 4160 volt bus IAA02 until 1157 CST, at which time bus e, F IAA02 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 form 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-up 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

( l notification was not received by all agencies until 0935 CST. l

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The Emergency Director 3nstruhted pehonnel'to' comp 1ete various.iasks.'for'. 4 . .. _;

restoring containment and'RC5 ~i'nteg~rityt~All work was accomplished and'" ' ' I maintenance personnel exited containment by 1050 CST.

The SAE was downgraded to an Alert Emergency at 0915 CST after restoration of core cooling and one train of electrical power. By 1200 CST, plant conditions had stabilized with both trains of electrical power being ,

supplied from an offsite source (RAT IB). After discussions with the NRC l and local government agencies, the emergency was terminated at 1247 CST and all agencies were notified ty 1256 CST.

D. CAUSE OF EVENT Direct Cause:

1. The direct cause of the loss of offsite Class lE 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.

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 bus lAA02. ,

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3. The direct cause of the failure of the primary ENN system in the  % l control room was the loss of electrical power to Unit 1. TheprimaryJ  !

ENN in the control room is powered from Unit 1 Class IE AC power. i Therefore, whan Unit 1. lost, Class.1E. AC electrical power, th,e primary }

ENN in the control room did not work. g f

Root Cause: i

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

i requirements, including holding a Class 2 Georgia driver's license. I l

However, site safety rules, which require a flagman for backing L vehicles when viewing is impaired, were violated.

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

determined. 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 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.10. seconds. .The... .s..

' annunciators observed' at the*second trip included jacket = water. highJ ::, _. . i temperature along with other-tripseIn 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 l sensors, simulating a tripped condition. The simulation duplicated l both the annunciators and the 70 sec. trip time. The most likely cause of the DG trips was intermittent actuation of the jacket water l l

temperature switches. ,

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

Switch TT-19Il0"was found to' hive' a'setpoint-oF197 degreet F; whiclw I was approximately 6 degrees below its previous setting. Switch l

l TS-19111 was found to have a setpoint of 199 degrees F, which was l

approximately the same as the original setting. Switch TS-19112 was

' found to have a setpoint of 186 degrees F, which as approximately 17 degrees F below the previous setting and was re-aojusted. 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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' I o is lo lo lo l 4l2 l 4 9l0 01016 0l1 0[6 or 0 l9 YEGP - UNIT 1 vent ,-. . = wance mm During the subsequent test run of the DG on 3-30-90, one of the tripped and would not reset. This appeared to be -

switches (TS-19111) lure because it subsequently mechanically reset.

an intermittent fai I This switch and the leaking switch (TS-19112) were replaced with new

- switches.

All subsequent , testing was conducted with no additional ,

problems.

A test of the jacket water system temperature transient during engine I starts was conducted. The purpose of this test was to determine the i actual jacket water temperature at the switch locations with the engine .

in a normal standby lineup, and then followed by a series of starts The g without air rolling the engine to replicate the starts of 3-20-90. q 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. '

Numerous sensor calibrations-(including jacket water temperatures),

special pneumatic leak testing, and multiple Afterengine the 3-20-90 starts and runsthe event, were performed under various conditions.

control systems of both engines were subjected to a comprehensive test program. - Additionally, the jacket water high temperature switches were sent to an independent laboratory, which found the switches set at l } temperatures ranging from 162 degrees F to_195 degrees.F rather.than ... z

the 200 degree F setting that was< required. The calibration technique-

was changed 'ahd" switches were're-calibrated and insta11ed 'on DGl8 on o -

5-23-90. HoiseE'anotfidf failuVe occurred on DGIBn(See Technical, , ;

. These switches were also sent Specification Special Report 1-90-4.)found the settings to be from 164 j to the independent laboratory, which degrees F to 169 degrees F. Subsequent to this testing, the onsite t

l calibration procedure was again revised to provide a technique that is  !

consistent with the actual operating conditions that the switches i experience. Switches were calibrated using this new technique, Since i installed and found to operate within the expected parameters. j the event of 3-20-90 through 6-7-90, DGIB had received 12 valid tests

~ with the one fatitre mentioned"above; and DGlh hed, receive 616 valit.

tests with no failures.

Based on the above facts, it is concluded that the jacket water high temperature switches were the most probable cause of both trips on 3-20-90.

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

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W sensors have been modified in accordance with the manufacturer's3 instructions. GPC does not believe that these sensors contributed to the diesel generator trip on 3-20-90.

E. 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 baing out of '

service for maintenance, resulted in Unit 1 being without AC power to both l With both Class IE busses deenergized, the RHR System o

~

Class IE busses. Based on a noted rate of could not perform its required safety function.

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

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 j

36 minutes after the beginning of the event. Using more conservative i assumptions and methods, but the same actual time of the event, the calculated worst case time to boiling was found to be approximately I hour 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.

Restoration of RHR and closure of the containment equipment hatch were

( )

completed well within the estimated I hour and 36 minutes for the projected onset of boiling in the1RCS. A review of information obtained from the Proce'ss and Effluent Radiation Monitoring System (PERBS) and grab sample ""~^M '

analysis indicated al1~ normal values. - As a rssult-of this svent,' ho'~ ~- '

increase in radioactive releases to either the containment or the environment occurred.

Additional systems were either available or could have been made available to ensure the continued safe operation of the plant:

1. The maintenance on RAT 18 was completed and the RAT was returned to 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.

2. Off~ site power was avaiTabTe"tb non lE equipment'through the generabr 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 1AA02 and that the phase to ground fau IBA03 could have been powered by feeding through non-1E bus 1HA01.

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 to the reactor.

Consequently, neither plant safety nor the health and safety of the public was adversely affected by this event. .

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). A management policy on control and operation of vehicles has been established.

Tem >orary barricades have been erected with signs which direct 2.

autiorization for control of switchyard traffic to the SS. g*

3. The Loss of Offsite Power (LOSP) diesel start and trip logic has been modified on both Unit I and Unit 2 so that an automatic " emergency" '

start will occur upon LOSP. Therefore, non-essential diesel engine ,-

trips are blocked upon LOSP. Additionally, high jacket water temperature has been deleted as a trip signal in the emergency start l mode. '

4. The DGIA test frequency was increased to three times per week until 4-20-90 when the test frequency was 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 tests. Up to and including the two valid failures f the 3-20-90 event, there were a

( g

, total of four valid failures in alid tests of DGIA.

5. :The jacket water temperature swi es for each DG were replaced or

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

installation.

6. A back-up ENN system powered from the AT&T system, which previously existed and was operational for South Carolina agencies, has be2n extended to include Georgia local and state agencies. Instructions have been given to Emergency Directors and Communicators concerning use of the emergency communication systems.

l 1

G. ADDITIONAL INFORMATION

1. Failed Components:

Jacket Water High Temperature Switches manufactured by California Controls Company.

Model #A-3500-W3 l

' 2. Previous Similar Events:

None 92 PROJECT i 016W69 (

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3. Energy' hidastry Identif teation System Code: &

Reactor Coolant System - AB Residual Heat Removal System - BP l M*

Diesel Generator Lube 011 System - LA -

Diesel Generator Starting Air System .LC ^

Diesel Generator Cooling Water System - LB St.

Diesel Generator Power Supply System - EK Safety Injection System - BQ L 13.8 kV Power System - EA 4160 volt non-1E power system - EA .

4160 volt Class IE 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 Radiation Monitoring System - IL l

W PROJEC1 0168/o

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. SAC Feeus sea. 46 01

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