ML20005E851

LER 89-042-01:on 891201,main Turbine Generator Tripped, Resulting in Reactor Scram.Caused by Sensing Fault on Offsite 230 Kv Line.Sys Maint Procedure Being Revised to Include Test of Failed Portion of relay.W/900102 Ltr

ML20005E851
Person / Time
Site:	River Bend
Issue date:	01/02/1990
From:	Booker J, England L GULF STATES UTILITIES CO.
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
LER-89-042, RBG-32044, NUDOCS 9001110176
Download: ML20005E851 (6)

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, January 2 ,1990 RBG- 32044' '"

File Nos. G9.5, G9.25.1.3 i

U.S. Nuclear Regulatory Commission

" Document Control. Desk Washington, D.C. 20555' Gentlemen:

River Bend . Station - Unit 1 '

Docket No.*'50-458 -

Please fin'd enclosed Licensee Event' Report No.89-042 for River Bend Station - Unitol. This report;is being submitted pursuant to 10CFR50.73. >

-Sincerely, J. E. Booker s hc) '

Manager-River Bend Oversight River Bend Nuclear Group a.

JEB/TFP/RGW/DCH/DEH /pg cc: U.S. Nuclear Regulatory Commission-611 Ryan Plaza Drive, Suite 1000-Arlington, TX 76011 NRC Resident Inspector P.O. Box 1051 St; Francisville, LA 70775 INP0. Records Center 1100 Circle 75 Parkway Atlanta, GA 30339-3064  :

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R3 actor Scram Due to a Pault on an Offsite Transmission Line EVENT DAf t (5) LIR NUe481R 14) AtPORT DATE 175 OTHER F ACILITitS INVOLvt0 tel l '.

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LICENSit CONTACT FOR TH18 LER (12)

NAME f tLteMONE NUMBER ARtAcOOg L. A.' England - Director, Nuclear Licensing 51014 318111-14111415  !

COMPLETE ONE LINE FOR ( ACH COMPONENT F AILUMt Ot3CRISt0 IN TMit REPORT (131 Sy sT E M MA C. R E POR,T A Lt MA C. R T t CAV88 COMPON E NT CAU$t Sv8TE COMPONENT O N' '

j X EA1 i 15 l9 W l1 l2 l0 Y t i i i i i l  ! I l l l l l 1 1 I I I I SUPPLEME*'TAL REPORT E XPECTED 1141 lMONTM DAY vtAR SuevisSION 4t$ 119 yes. comore,e Ex9tCTfD SUBMIS$10N OATil kO l l l AssTRACTro,,,,, , m .-e,,e ... ., e , ,s,ee,. .u,,.e .m e ,,,e.,,,,e,, ,,,,e., o .i At 0628 on 12/1/89 with the unit at 97 percent power (Operational Condition 1), the main turbine generator tripped, resulting in a reactor scram. The generator tripped due to the main generator protection breakers tripping as a result of sensing a fault on an offsite 230KV line. The fault failed to clear at the 230KV. switchyard due to a failed relay and slow breaker response time following the signal from a backup relay. t Immediately following the generator trip, the station 4.16KV normal switchgear (INNS-SWG1A) failed to successfully transfer to offsite power. This caused an undervoltage condition which initiated an automatic start of the Division III high pressure core sprav (HPCS) emergency diesel generator. Initiation of the Division III standby service water pump ISWP*P2C also occurred due to a momentary loss of power to the initiating trip units. The Division III emergency diesel generator restored power to the bus per design.

The reactor scram placed the unit in the safe shutdown condition.

Since all safety systems functioned as designed, there was no impact on the safe operation of the plant or to the health and safety of the public as a result of this event.

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l 0 12 M ob Ygst? W ausse ausse a seeisud ser adisennef NAC Fame W W Uh REPORTED CONDITION At 0628 on 12/1/89 with the unit at 97 percent power (Operational Condition 1), the main turbine generator (*TG*) tripped, resulting in a reactor scram. The generator tripped due to the main generator protection breakers tripping as a result of sensing'a fault on an offsite 230KV line. The fault failed to clear at the 230KV switchyard due to a failed relay (*RLY*) and slow breaker response time following the signal from a backup relay.

Immediately following the generator trip, the station 4.16KV normal switchgear_(lNNS-SWGlA) (*SWGR*) failed to successfully transfer to offsite power. This caused an undervoltage condition which initiated an automatic start of the Division III high pressure core spray (HPCS) emergency diesel generator (*DG*). Initiation of standby service water pump ISWP*P2C also occurred due to a momentary loss of power to the Division III initiating trip units. The Division III emergency diesel generator (DG) restored power to the bus per design. Since this event resulted in the actuation of engineered safety features (ESFs) it is hereby reported under 10CFR50.73 (a) (2) (iv) .

INVESTIGATION The investigation that followed the event revealed that the turbine trip was caused by a severed static line on an offsite 230 KV transmission line which caused a phase to ground fault. The fault did not immediately clear due to a failed relay and a slow 230 KV circuit breaker clearing time at the offsite 230 KV switchyard (Fancy Point substation). The slow fault clearing time was sufficient for the 64M relay protecting the main generator to operate and trip circuit breakers 20635 and 20640 at the offsite switchyard isolating the generator from the fault. The initial evaluation for the static line failure indicates a potentially deficient pole ground connection to the static line.

The investigation revealed that the Zone 1 directional distance ground l relay 21GS1 (Westinghouse type SDG relay) failed to operate properly.

l Per design, the Zone 2 (a backup to the Zone 1 relay) directional distance ground relay (21GS2) operated after a 20 cycle delay and simultaneously sent a trip signal to breaker 20745 and initiated a breaker failure timing sequence. The breaker failure relay was energized because breaker 20745 failed to operate within the expected I

time period upon receiving a trip signal from the Zone 2 directional ground relay. The time from the fault initiation to the trip from the l breaker failure backup relay actuation was approximately 31 cycles.

l This was sufficient time for the 64M (*64*) relay for main generator ,

protection to operate and trip breakers 20640 and 20635 to isolate the l unit from the fault. The SDG relay failure was traced to a failed component in a circuit that is only active when the relay is used in a Zone 1 protection application. All remaining SDG relays at the

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l 0 13 OF gg o"Y1 Tit D T O s E chYard in a Zone 1 application have been tested for the failure mode and were found to be functioning properly.

Immediately following the generator trip, the station 4.16KV normal switchgear (INNS-SWG1A & INNS-SWG1B) did not fast transfer to an oftsite power source. This was per design because the voltage was below the transfer permissive value at that time. Switchgear INNS-SWGlB was able to complete a successful slow transfer however, INNS-SWGIA did not. The transfer schemes for INNS-SWGlA&B rely on sufficient voltage levels on the secondary of the station preferred transformers (IRTX-XSRID and 1RTX-XSRIC). When the fault occurred, voltage on the secondary of station preferred transformers 1RTX-XSRIC and 1RTX-XSRID was depressed to 3504 V and per design the 59R (*59*)

relays (undervoltage/overvoltage) on INNS-SWGlA & INNS-SWGlB dropped out. At that time, the auxiliary relays (59RX) operated and removed the permissive for transfer. When the fault cleared, the 59R relay for INNS-SWGlB energized, resetting the 59RX relay for that switchgear thus allowing a slow transfer of INNS-SWGlB. Switchgear INNS-SWG1A did not slow transfer as expected but did manage to complete the transfer in approximately six (6) minutes. Testing of the 59R relay (Westinghouse KV-1) for INNS-SWG1A revealed that it had failed.

Due to the failure of the non-safety related 4.16KV switchgear INNS-SWGlA to transfer (fast and slow) from normal station service transformer ISTX-XNSIC to preferred station service transformer 1RTX-XSRIC, a loss of power to the high pressure core spray (HPCS) safety-related 4.16KV bus 1E22*S004 and the non-safety related 4.16KV bus 1NNS-SWG1C occurred. As a result of the loss of power to the IE22*S004 bus, the HPCS DG received an automatic initiation signal due l to the bus undervoltage condition. The HPCS D/G successfully started

and its output breaker automatically closed restoring voltage to the bus per design.

The initiation of standby service water pump, ISWP*P2C, resulted from I a loss of power to the initiating trip units which actuate on low normal service water pressure. The trip units are supplied by a 120VAC/24VDC power supply which is powered from the HPCS 480VAC bus (lE22*S002). Power was restored to the Division III bus via the Division III emergency diesel generator. Upon restoring power to the Division III bus, the trip signal from trip units ISWP*ES21/J,K,L and M sealed in via relay ISWPN18-63. The initiation of ISWP*P2C occurred following the timing out of relay ISWPC08-62-A.

Immediately following the scram, recirculation pump breakers 3A, 4A, 3B and 4B (normal feed) tripped on an end of cycle-recirc pump trip (EOC-RPT) signal followed by the tripping of recirculation pump breakers SA and SB due to electrical interlocks. As a result of receiving a turbine trip at 97 percent power, the reactor vessel experienced a pressure transient. The highest pressure recorded b" the emergency response information system (ERIS) was 1126.8 PSI. Due I onu 3ece e U S GPO1986-0 624 636,466

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ARI and ATWS/RPT initiated. The ARI signal sealed in per design and the ATWS/RPT immediately cleared per design due to pressure being reduced below the trip setpoint. The pressure reduction was a normal design function of 9 relief valves opening (5 low-low set function and 4 additional safety relief. valves (SRVs)). Following the ARI/ATWS initiation, the recirculation pump low speed RPM permissive was met and recirculation pump breakers 2A & 2B closed from the initial EOC-RPT signal, placing the pumps on low speed.

Similar events have been reported in LERs85-063, 86-021, and 86-055.

The failure of the static line was an external factor that played a role in initiating this event. One of the similar events listed above also involved an external factor, a lightning strike as reported in LER 85-063. The remaining two events are similar due to their sequential nature. In both events a transformer fault progressively led to a reactor scram. A brief description of each event is provided below.

. LER 85-063: GSU reported a reactor scram due to a main turbine generator trip on a false main turbine generator power-load imbalance caused by a failed pressure transducer coupled with a lightning strike on a-500 KV transmission line, i l . LER 86-021: GSU reported an event in which a transformer fault l led to a voltage transient in a 13.8 KV switchgear which '

l resulted in a reactor scram and a HPCS injection.

. LER 86-055: GSU reported an event in which a faulted transformer caused a loss of power to the reactor protection system (RPS) A bus concurrent with a failure in the RPS B train backup scram circuitry which resulted in a reactor scram.

l CORRECTIVE ACTION The offsite static line which initiated this event is undergoing repairs. The failed relay in the offsite 230 KV switchyard was  ;

replaced and the replacement has been successfully tested. Although the failure of the Westinghouse SDG relay has been determined to be an isolated failure, GSU is revising system maintenance procedures to include a test of the failed portion of the SDG relay circuitry. 1 The failure of the offsite breaker 20745 to operate immediately upon receipt of the signal from the Zone 2 relay has been evaluated.

Subse'quent testing and inspections (internal and external) have revealed no reason for this breaker to function improperly since it passed all of the testing and inspection requirements. Therefore, the circuit breaker has been approved to be returned to service.

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l 0 15 0F 0 15 van . . . . . sea - mu m m The failed relay (59R) which prevented the station normal switchgear from completing a slow transfer was replaced. GSU has initiated a ,

modification (modification request (MR)89-241) to replace the j Westinghouse KV-1 relay with an ITE 59H relay in-the 59R application. I d

All other station applications of this type'of relay were evaluated with none identified in safety related systems. In addition, busses 1NNS-SWGlA and INNS-SWGlB are currently being served from preferred station service transformers 1RTX-XSRIC and 1RTX-XSRID, respectively.

l SAFETY ASSESSMENT There was no impact on the safe operation of the plant or to the health and safety of the public as a result of this event since the  !

reactor scram placed the unit in the safe shutdown condition and all safety systems functioned as designed.

NOTE:. Energy Industry Identification System Codes are identified in the text as (

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