ML20237J582

Revised Monthly Operating Rept for June 1987

ML20237J582
Person / Time
Site:	Vogtle
Issue date:	06/30/1987
From:	Dilworth S GEORGIA POWER CO.
To:
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ML20237J554	List: ML20237J551 ML20237J564 ML20237J574 ML20237J582
References
NUDOCS 8708180241
Download: ML20237J582 (6)

Text

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ENCLOSURE 3 l REVISED V0GTLE UNIT 1 MONTHLY OPERATING REPORT FOR JUNE, 1987 j u

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ERATING DATA 8E::RT  ; NIT: '<06ttg 1

CC>ET NO. 50-4:4 ATE: ^7-Jul-87

NPLETED BY: S. C. DILWORTH

'ELEPHONE: (4046 7:4 8114 x3870 -

1 CPERATING STATUS

1. UNIT NAME: A. d. V0GTLE UNIT 1

. ~ . EEPORT SERIOD: Jun-47

!. LICENSED THER4AL 70WER eMWti 7411 4 NAMEPLATE PATIN0 (GROSS MWen j 1160

5. CESIGN ELECTRICAL RATING iNET " Wee '1191 ]

6.'MAI! MUM DEFENDABLE CAPACITY (CROSS "Wel 11:4 ]

7 MAI! MUM DEPENDASLE CAPACITY INET FWe): 1069 * ]

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8. !F CHANGES OCCUR IN CAPACITY PAT?NGS

<!TEMS i THROUSH 7) $!NCE LAST REPORT, 61VE REASONS:  !

NO CHANGES

9. POWER LEVEL TO WHICH RESTRICTED. IF ANY (NET FWe): NO RESTRICTIONS )

10. REASONS FOR RESTRICTION, IF ANY:

NA i

THIS MONTH VR. TO DATE CUMULAT!VE

!!. HOURS IN REPORT!NG PERIOD: 7:0 720 7:0

12. NUMBER OF HOURS REACTOR WAS CRITICAL: *:5.3 3:5.3

13. REACTCR RESERVE SHUTDOWN N0bRS:

3:5.3

• , NA NA NA 14 HOURS BENERATOR DN-LINE: 276.4 276.4 276.4

15. UNIT RESERVE SHUTDOWN HOURS: NA NA NA

16. EROSS THERMAL ENER6Y GENERATED (MWM): 759746 759746 750746 17 GROSS ELECTRICAL ENERGY GENERATED (MWM): :40180 040180 240190

18. NET ELECTRICAL ENER6Y GENERATED (MWM): 202150 20:150 19 REACTOR SERVICE FACTOR: 202150 45.2% 45.:% 45. 1

20. REACTOR AVAILABILITY FACTOR: 45.2% 45.2% 45.2%

21. UNIT SERVICE FACTORS 19.4% '8.4% 18.4%

22. UNIT AVAILABILITY FACTOR: 28.4% 30.4% ;8.4%

23. UNIT CAPACITY FACTOR (USING MDC NET): 26.3% 26.3% 26.0%

24. UNIT CAPACITY FACTCR (USING DER NEfit 25.5% 25.5%

25. UNIT FORCED OUTAGE RATES 25.5%

61.6% 61.4% 61.6%

26. SHUTDOWNS SCHEDULED DVER THE NEIT 6 MONTHS (TYPE, CaTE, AND DURATION OF EACH):

TYPE: MAINTENANCE AND TEST!NS. DATE: OCTOBER 2. 1987 e. DURATION: 10 DAYS

27. IF SHUTDOWN AT END OF REPORT PERIOD, ESTIMATED DATE OF STARTUPt N/A

20. UNITS IN TEST STATUS ( PRIOR 70 COMMERCIAL OPERATION): N/A

• TENTATIVE DATE.

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UNIT 1 4VEDABE DAILv JN!it V067LE 1

G=E: LEVEL '0CP E? NO "?-424 i 047E: .. c.i l - 3 7 l

• cLE'ED 8V 3. :. :!LWC27W .I j

" ELE 8 W E: i404) 7:4-!!14 v3970 l

U Net MW f

l ......... 1952

......... .Q5^

3. ....... $83 4 ......... O h

i 5 ......... O e ......... 0 7

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......... O I 8 ......... O i

9 ......... O  !

l 10 ......... 0 - l 11 ......... 0 l 12 ......... 0 13 ......... 145 14 ......... 390 15 ......... 0 16 ......... 0 17 ......... 0 10 ......... 0 19 ......... 0 20 ......... 0 21 ......... 0 22 ......... 258 23 ......... 680 24 ......... 0 25 ......... 0 26 ......... 765 27 ......... 1080  !

28 ......... 1063 29 ......... 1063 l

30 ......... 1057 NOTE: Days marked with an asterisk (*) reflect power greater than 100%. Items 6 and 7 on page E-1 are theoretical and will be corrected after sufficient operating data 1 has been obtained.

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1 UNIT SHUTDQWNS AND 80WER AEDUCt:0NS 'DOCFET NO. !0-424 OATER. 07-JUL-9?

UN!? NAME: v0G7LE 1  : MPLETED Pvt S.C. DILWORTH

'ELEFHONE: '404) 7"4-4118 <!B70)

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!! o 19706071 F ! 1:8.32 : A : 3' + . SJ ! C22,C16 l

,: S 1970614: F : 136.3 A : : + l SK : 796  !

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!.............................l 6: FORCEO REASON - METHOD: EVENTS REPORTED INVOLVE ts' SCHEDULED A EDUIPMENT FAILURE 4EXPLA!N) 1 - MANUAL A GREATER THAN 20%

B-MAINTENANCE OR TEST 2

• MANUAL SCRAM REDUCT!DN IN AVERA6E C-REFUELINS 3 - AUTO. SCRAM DA!Ly PONER LEVEL FOR D REEULATORY RESTRICTION 4 - CONTINUATIONS THE PRECEEDING 04 HOURS.

E-OPERATOR TRAIN!N6 &' LICENSE 5'- LOAD REDUCTION F-ADMIN!STRATIVE 9 - OTHER (EXPLAIN)

G-OPERATIONAL ERROR (EXPLA!N)-

• LER NUMBER TO BE ASSIGNED H-0THER (EXPLAIN)

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OPERATING DATA REPORT V0GTLE-1 . JUNE 1987 A - Cause/B - Corrective Action to Prevent. Reoccurrence

-1. A. h root cause' for the relay. actuation was due to a jumper. The jmper was installed on Phase A & B current transformers for shipment and were not removed during startup, h jumper should have been removed during the. e _

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performance of the Construction Acceptance Test'. (CAT) '

gvcidare (CAT-E-02).. which a caution note concerning current transformer (provided CT) grounds, t

B. The shippfag grounds located on- the current transformer I (CD were removed 'and the construction test procedure (CAT-E-02) was reviewed for adequacy. On previous revisions of the procedure there had been a note concerning the Cr- p ounds. On May 11, 1987, the i

procedure had been revised to include a sign-off step to 1 ansure that only one ground exists in the Cf circuit.

This was considered adequate so no further changes were considered necessary.

2. A. \

The innediate cause of the reactor trip was due to Source  :

Range High Neutron Flux. h root cause of the high flun trip was due to Raactor Operator (R.O.) arter. {

The R.O. '

was not attentive to the reactor startup, did. not recognize the reactor was critical when bank C was at 99 steps, and relied upon a trainee who had never been  !

involved in an actual plant startup, i

3. W R.O. was removed from any -licensed duties until adequate retraining had been performed as determined by the Operations Manager, h R.O. and the Shift Supervisor (SS) have received I additional simulator training for reactor plant starrups.

An Inverse Count Rate Ratio plot shall be required for each reactor plant startup. ,

h wocedure 14940-1, " Estimated Critical Condition Calculation", and the Plant Technical Data Book have been reviewed by Reactor Engineering and revised.-

3. A.

W 4=adiate .cause of the event was the hi-hi water  :

level in Steam Generator No. 2. - The root cause of the event was personnel error. The trip was caused by. the Shift Supervisor who opened the Stean Generator.. No. 2 WRV too far. A contributing cause of ' the event was - a procedure defici in that reactor power was too high i

for transferring the BFKVs' to- MFRVs. Another l contributing cause was that the No.- 3 BPRV seemed to oscillate.

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3. (continded)

, B. A 'ercond operzter to support the Steen Gener; tor 1 operation has been ansigned to shift during plant.startup operation for. transferring from BFRVs to MMtVs The Unit Operating procedure (UDP), 12004-1, has been '!

revised to require a low reactor power level (15%) when transferring from BM to MERV.

H I & C' investigated estrol systens and limits for BPRVs  !

and found BPRVs to fuaction properly. The stroke for No. '

2 MFRV Wes also checked and found to function properly.

4. A. h reactor trip was caused by a low low staan generator level condition, h "A" MPP * = % check valve (1-1305-U4-502)- failed and the breaker feeding the discharge actor operated valve (MN) tripped while in the open position.  !

The root cause for the failure of 1305-U4-052 has been steributed to inadequate hinge pin design.for this particular model and size valve. This valve is a Pacific 20 inch Tilting Disc Check Valve, Model 58809-7-WE(120).

B. To revent recurrence. of the check valve failure, rede igned pins . have been installed for the "A" E .I "B" MFP dis e check valves, 1-1305-U4-052 and 1-1305-U4-060. h new design has the following features:

1. The pin head disneter has been enlarged fran 2";to 3" l co provide greater bearing area on the axial stop. 1

2. The width of the pinhead has been increased to minimize the amount of axial novament, thus assuring that the antirotation flat remains engaged with the disc.

3. The pin head exterior mating surface is fully round, i.e., the antirotation flat is only partial width, to i preclude bypassing of the axial.stop.

4 The pin has been 1 d to ensure full engagement through the disc and assembly.

5. A. h root cause of the reactor trip is' vendor fabrication error. The error was the result of : not installing a -

ferrule on the hydraulic fluid tubing connection which failed. Although the connection may have had some preliminary leakage, it was enclosed in guard piping l which prevented early detection. Only after several )

hundred hours of pump turbine operation did the- J connection work loose to the point the major leak  ;

occurred. i B. h faulty hydraulic tubing connection was replaced. . All similar tubing connections on each of the two FW pump turbine ~ skids were inspected to ensure their integrity, i l

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b 6 & 8. A.

-On June 20,1987, at '0942 CDI, while in Mode'3 and with

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shutdown rod banks partially withdrasm, the reactor was

- tnanually tripped to ecuply with the requirements ef.

Technical . Specification 3.1.3.3. . This nanual trip was initiated after receipt of an "RPI t Alarnt' arunciator on indicated failure of the tal Rod Position After Indicator the tri (DRPIT for shutdown bank 'T Rod G-3.

was performed:p, a thorough

however, checkout no failures of the DRPI or problans system.

could be I 1

identified. Subsequently a successful reactor startup was empleted on June 21, 1987, with no DRPI failure.

- On June 25,1987, the Uhit was again in Mode 3 and the shutdowrz rod banks were being withdrawn when another ERPI failure occurred for shutdown Rod G-3. h reactor was therefore manuallytripped trip, a detector at 0119 CDI. . Following this

/ encoder card in the "B" DRPI Data Cabinet was discovered . to have failed. 'Ihis card was than replaced and subsequent testing demonstrated that.

proper indication has been restored for Rod G-3.

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The failed card, . is thought to have escaped detection i following the first event -since apparently only an interndecent failure existed at- that time and since opening the trip breakers allowed the rods to fall-in and reset the LED display data " "

codes for the detector / encoder cards in the "A" gray'T' .E Deca Cabinets.

The technical manual for the DRPI . system calls for  ;

checking these gray codes to determine needed replamt '

for suspect cards. Following the second event, i

failure repeated itself in troubleshooting. and . the was ,

therefore subject to being detected..

7. A.

l The direct cause of the trip was personnel error as the l

field current ~ transducers were improperly calibrated.

1 The root cause of the trip was the field current transducer calibration procedure was not used bypassing measuring and test equipment requirements.

B.

As a result of this trip the following actions were taken:

1.

Recalibrates Field Current Transducers.

2. Preform no load voltage checks of the - generator to l

deterrdne if design was actually seen in tw field.

l 3. Confirmed the field current regulator OPERATED SATISFACTORILY.

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