ML17223B208

LER 91-003-00:on 910506,heater Drain Pump 1A Tripped & 4 Later SG Feedwater Pump 1A Tripped Causing Turbine Runback. Caused by Possible Grounding of Heater hi-hi Level Switch. Circuit Breaker 27 replaced.W/910604 Ltr

ML17223B208
Person / Time
Site:	Saint Lucie
Issue date:	06/04/1991
From:	Sager D, Wachtel P FLORIDA POWER & LIGHT CO.
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
L-91-155, LER-91-003-01, NUDOCS 9106110130
Download: ML17223B208 (6)

Text

ACCELERATED DISTRIBUTION DEMONSTPA.TION SYSTEM r REGULATORY INFORMATION DISTRIBUTXON SYSTEM (RXDS)

ACCESSXON NBR:9106110130 DOC.DATE: 91/06/04 NOTARXZED: NO DOCKET FACIL:50-335 St. Lucie Plant, Unit 1, Florida Power & Light Co. . 05000335 AUTH. NAME AUTHOR AFFILIATION WACHTEL,P.K. Florida Power & Light Co.

SAGER,D.A. "

Florida Power & Light Co.

RECIP.NAME RECIPIENT AFFILIATION

SUBJECT:

LER 91-003-00:on 910506,heater drain pump 1A tripped & 4 s later SG feedwater pump 1A tripped causing turbine runback., D Caused by possible grounding of heater hi-hi level switch.

Circuit breaker 27, replaced.W/910604 ltr.

DISTRIBUTION CODE: XE22T COPIES RECEIVED:LTR t ENCL SIZE:

TITLE: 50.73/50.9 Licensee Event Report (LER), Tncident Rpt, etc.

NOTES "

RECIPIENT COPIES RECIPIENT COPIES D ID CODE/NAME LTTR ENCL ID CODE/NAME LTTR ENCL PD2-2 LA 1 1 PD2-2 PD 1 1 D NORRIS,J 1 1 INTERNAL: ACNW 2 2 ACRS 2 2 AEOD/DOA 1 1 AEOD/DSP/TPAB 1 1

.AEOD/ROAB/DS P 2 i 2 NRR/DET/ECMB 9H 1 1 NRR/DET/EMEB 7E 1 1 NRR/DLPQ/LHFB10 1 1 NRR/DLPQ/LPEB10 1 1 NRR/DOEA/OEAB 1 1 NRR/DREP/PRPB11 2 2 NRR/DST/SELB 8D 1 1 NRR/DST/SICB8H3 1 1 NRR/DSQ A~BBD1 1 1 NRR/DST/SRXB 8E 1 1 RPG -" 2 1 1 RES/DSIR/EXB 1 1 RGR I-+~0% 1 1 EXTERNAL EG&G BRYCE ~ J ~ H 3 3 L ST LOBBY WARD 1 NRC PDR 1 1 NSIC MURPHY,G.A 1 1 NSIC POORE,W. 1 1 NUDOCS FULL TXT 1 1 D

D D

NOTE TO ALL "RIDS" RECIPIENTS:

S PLEASE HELP US TO REDUCE WASTE! CONTACT THE DOCUMENT CONTROL DESK, ROOiVI Pl-37 (EXT. 20079) TO ELIMINATEYOUR NAME FROM DISTRIBUTION LISTS FOR DOCUMENTS YOU DON'T NEED!

FULL TEXT CONVERSION REQUIRED TOTAL NUMBER OF COPIES REQUIRED: LTTR 33 ENCL 33 ~

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P.O. Sox 1 8, Ft. Pierce, FL 34954-0128 FPL JQN Q4 $ 91 L-91-155 10 CFR 50.73 U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, D. C. 20555 Gentlemen:

Re: St. Lucie Unit 1 Docket No. 50-335 Reportable Event: 91-03 Date of Event: May 6, 1991 Manual Reactor Trip Following a Turbine Runback Due to E i ment Failure The attached Licensee Event Report is being submitted pursuant to the requirements of 10 CFR 50.73 to provide notification of the subject event.

Very truly yours, D. A. ger Vice r sident St. Lu e Plant DAS:GRM:kw Attachment cc: Stewart D. Ebneter, Regional Administrator, USNRC Region Senior Resident Inspector, USNRC, St. Lucie Plant II DAS/PSL N441 9l061$ 01-"'0 Olr.r604' rrr aDOCV. ~>SC>O03:-:-

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U.S. NUCLEAR REGULATORY COMMISSION APNTOITDDAWN1 $ 550050l F PL Faoalrrire of CXPSNW 40005 NRC oorrrr SQf DCTAAATTDILATIINPrll INIPOAWTD CC001T IPTN TN0 INCITAAllCNCCTACOICN te-ssf LICENSEE EVENT REPORT (LER) 5015NDT: 500 5005 ICITWAITICCANCNIDINITNCTIAT IAITXNTDTAAAICTo TIN IKCCTCS No INPCPDD NIACCINNTWTANCNIP0005 Ila IADACNIINWAATCTTY NAWNIITAWADDNIION, DC 505Nl NCI ro TIN PTTNICIXTII%DUCTION INOICCT f 0IWCI04OIINNCP NACÃACNTAN)500XCT,WANNIOTCPADC505ICL FACILITYNAME (1) DOCKET NUMBER (2) PAGE 3 St. Lucie Unit 1 050003351 0 0 4 Tl LE(4) Manual Reactor Trip Following a Turbine Runback Due to Equipment Failure EVENT DATE (5) LER NUMBER (6) REPORT DATE m OTHER FACILITIES INVOLVED(8)

DAY YEAR YEAR S AL MONTH DAY YEAR FACILITYNAMES DOCKET NUMBER(S)

N/A 0 0 5 069 1 9 1 0 0 3 0 0 0 6 0 4 9 1 N/A 05000 THIS REPORT IS SUBMITTED PURSUANT TO THE REQUIREMENTS OF 10 CFR:

OPERATING Check one or more of the followin (11)

MODE (9) 20.402(b) 20.405(c) X 50.73(a)(2)(iv) 73.71(b)

POWER 20.405(a)(1 )(i) 50.36(c)(1) 50.73(a)(2)(v) 73.71(c)

LEVEL (1o) 0 9 6 20.405(a)(1)(ii) 50.36(c)(2) 50.73(a)(2)(vii) 0 IHER (Specify in Abstract 20.405(a)(1 )(iii) 50.73(a)(2)(i) 50.73(a)(2)(viii)(A) below and in Text 20.405(a)(1)(iv) 50.73(a) (2) (ii) 50.73(a)(2)(viii)(B) NRC Form 366A) 20.405(a)(1)(v) 50.73(a) (2)(iii) 50.73(a)(2)(x)

LICENSEE CONTACT FOR THIS LER 12 NAME TELEP ONE NUMBER AREA CODE Patricia K. Wachtel, Shift Technical Advisor 4 0 7 465 -3550 COMPLETE ONE LINE FOR EACH COMPONENT FAILURE DESCRIBED IN THIS REPORT 13 MANUFAC- REPORTABLE MANUFAC- REPORTABLE CAUSE SYSTEM COMPONENT TO NPRDS CAUSE SYSTEM COMPONENT TURER TO NPRDS S J L I S 0 4 0 S J P S U069 I I I SUPPLEMENTAL REPORT EXPECTED 14 EXPECTED MONTH DAY YEAR SUBMISSION YES (lfyes, complete EXPECTED SUBMISSlOfrf DATE) X NO DATE (15)

ABSTRACT (Limit to 1400 spaces.i.e. approximately fifteen single-space typewritten lines) (16)

On May 6, 1991, St. Lucie Unit 1 was in Mode 1 and holding power at 96% to complete a Nuclear Delta-T Power Calibration before resuming full power operation following a scheduled shutdown. The 1A Heater Drain Pump tripped at 0508 and, four seconds later, the 1A Steam Generator Feedwater Pump tripped causing a turbine runback. The unit was manually tripped at 0509 at the direction of the Nuclear Plant Supervisor in anticipation of an automatic reactor trip and Standard Post Trip Actions were performed. The unit was then stabilized in Mode 3, Hot Standby.

The manual reactor trip was the result of a turbine runback initiated when both the 1A Heater Drain Pump and the 1A Steam Generator Feedwater Pump tripped. An investigation revealed a possible grounding of the 5A Feedwater Heater Hi-Hi level switch which, in turn, opened Circuit Breaker 27 on the 120 VAC Vital Static Uninterruptible Power Supply. This would have caused the normal drain valves to close on several secondary Feedwater Heaters and the alternate drain valves to open. It was also found that the pressure sensing element setpoint for the 1A SGFP had drifted high from the normal value of 275 psig to 291 psig. The end result was a low suction pressure condition on the Feedwater Pump suction line and the trip of the 1A Steam Generator Feedwater Pump on low suction pressure.

The immediate Corrective Actions implemented as a result of this event include: testing and replacing Circuit Breaker 27 as a precautionary measure, cleaning and testing the 5A Feedwater Heater Hi-Hi level switch, and lowering the setpoint of the 1A Steam Generator Feedwater Pump to its normal value of 275 psig.

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FACILITYNAME (1) DOCKET NUMBER (2) LER NUMBER (6) PAGE (3)

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YEAR EQUEN TIAL REVISIO Lucie Unit 1 NUMBER NUMBER 0500033591 0 0 3 0 0 0 2 0 4 TEXT (Ifmore spaceis required, use additional NRC Form 366A's) (17)

On May 6, 1991, St. Lucie Unit 1 was in Mode 1 and holding at 96% power to perform a Nuclear Delta-T Power Calibration prior to resuming full power operation. A unit shutdown had been performed to facilitate Control Element Assembly (CEA) (EIIS:AA) testing required every ninety days.

I While the unit was stabilized at 96% power, the board Reactor Control Operator (RCO) noted that there were amperage swings on the 1A Heater Drain Pump (HDP) (EIIS:SN) meter. At approximately 0508, the 1A Heater Drain Pump tripped and, within four seconds, the 1A Steam Generator Feedwater Pump (SGFP) (EIIS:SJ) tripped on low suction pressure which caused a turbine runback.

The board RCO immediately set up the turbine for a 10 MW/min downpower while the desk RCO and extra RCO initiated emergency boration and took manual control of the Control Element Drive Mechanism Control System (CEDMCS) ( EIIS:AA) to insert the control rods. Both Steam Generator (SG) (EIIS:AB) levels were decreasing and Pressurizer (EIIS:AB) pressure was increasing . When the Reactor Coolant System (RCS) (EIIS:AB) pressure reached 2340 psia, the Nuclear Plant Supervisor instructed the board RCO to manually trip the reactor and turbine to avoid an automatic reactor trip on High Pressurizer Pressure (setpoint, 2400 psia). Standard Post Trip Actions were performed and all safety functions were met.

During the post trip recovery, level in the 1B SG rapidly increased and a control room operator noted that the 'B'ain Feedwater Regulating Valve (MFRV) (EIIS:SJ) was approximately 70% open, whereas it should have fully shut upon the turbine trip. At 88% level in the 1B SG, the RCO closed the valve to restore SG water level to 65%. Auxiliary Feedwater Actuation Signal-1(AFAS) (EIIS:BA) occurred normally on. the 1A SG after level decreased to the AFAS setpoint of 19% while the 1B SG never reached its AFAS setpoint due to the MFRV failure. The 1A and 1C Auxiliary Feedwater Pumps (AFW) (EIIS:BA) started and supplied water to the 1A SG and the RCO placed the 15%

Feedwater Bypass Valves (EIIS:S J) in automatic. With SG level controllers in automatic and the 1B SGFP available, both SG levels then returned to 65% narrow range level.

Reactor Trip Recovery, Emergency Operating Procedure-2, was completed with two sets of satisfactory Safety Function Status Checks. Emergency boration was halted, AFAS was reset, and the unit was stabilized in Mode 3, Hot Standby.

The cause of the 1A Heater Drain Pump and the 1A Steam Generator Feedwater Pump trips can be attributed to corrosion and a possible grounding of the 5A Feedwater Heater Hi-Hi level switch (EIIS:

JB), LS-11-28A, which is powered from Circuit Breaker 27 in the 120 VAC Vital Static Uninterrup-tible Power Supply (SUPS) (EIIS: EE). Circuit Breaker 27, which supplies power to both the A & B trains of the 3, 4, and 5 Feedwater Heater Controls and the A, B, C, and D Moisture Separator Reheater Drain Collector (EIIS:SN) normal drains, was found in the tripped condition atter the plant trip. The failure of this circuit resulted in the normal drains of the 3 and 5 Feedwater Heaters to fail closed and the alternate drains of all Feedwater Heaters to fail open. The decreasing level in the shell side of the A & B Feedwater Heaters caused the HDP discharge valves to close and the FPL Facsimile of NRC Form 366 (6-89)

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YEAR EQUENTIAL 'EVISIO St. LUCie Unit 1 NUMBER .. NUMBER 0 500 0335 9 1 0 0 3 0 0 0 3 0 4 TEXT (fimore spaceis reguf'red, use additional NRC Form 366A's) (17) suction pressure for the SGFP to decrease. The HDP tripped on either low flow or at the low level setpoint in the 4A Feedwater Heater. The resulting low suction pressure condition in the SGFP suction line caused the 1A SGFP to trip at 291 psig. Normal setpoint for the feedwater pump trip is 275 psig; a subsequent Instrumentation and Control test of the pressure sensing element indicated that its setpoint had drifted high from the normal value of 275 psig to 291 psig.

The manual reactor trip by the utility operators was in anticipation of an automatic reactor trip on High Pressurizer Pressure after the turbine runback caused by the 1A SGFP trip.

This event is reportable to the NRC under 10CFR50.73(a)(2)(iv) as any event or condition that results in a manual or automatic actuation of any Engineered Safety Feature, including the Reactor Protection System .

The plant response during this event was bounded by Section 15.2.8 of the St. Lucie Unit 1 FUSAR, "Loss of Normal Feedwater Flow." The plant response was much more conservative than that described in the FUSAR analysis for several reasons: 1) Only one Steam Generator Feedwater Pump stopped whereas the FUSAR assumes a total loss of feedwater. 2) The reactor trip was manually initiated prior to exceeding any protective setpoints. 3) RCS pressure remained below the setpoint of the Power Operated Relief Valves and the Pressurizer Code Safety Valves.

The loss of the 1A HDP and the 1A SGFP resulted in a main turbine runback and a reduction in normal feedwater flow. The turbine runback is initiated when one of the two running SGFPs trip and turbine load, as measured by the main turbine's first stage pressure, is greater than 60% or both HDPs trip and turbine load is greater than 92%. The turbine runback is not required for reactor safety; it is intended to reduce the turbine steam demand in response to the reduced feed flow and subsequent decrease in SG feedwater inventories. Had the turbine runback failed to activate following the 1A SGFP trip, the Reactor Protective System (RPS) (EIIS:JC) would have automatically tripped the reactor on Low SG level and then tripped the turbine. This would have assured sufficient SG feedwater inventories to provide an adequate heat sink for the primary system.

The Auxiliary Feedwater Actuation System functioned as required when the 1A SG level reached the AFAS setpoint of 19% and the 1A and 1C AFW pumps automatically started, initiating auxiliary feedwaterflowtothe1A SG. Operatormitigationofthe18 Main Feedwater Regulating Valve failure precluded SG level from reaching the 90% level setpoint for tripping off the remaining SGFP.

Therefore, with the SG level controllers in automatic and the 18 SGFP available, level was restored to the 65% narrow range level and the unit was stabilized in Mode 3.

The St. Lucie Training Department prepared a simulator scenario which was similar to this event. The results from that simulation were compared with the actual plant response to this event and was a validation of the root cause of this reactor trip.

FPL Facsimile of NRC Form 366 (6-89)

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YEAR EQUENTIAL REVISIO St. Lucie Unit 1

'UMBER NUMBER 0 5 0 0 0335 9 0 0 3 0 0 0 40 0 4 TEXT (Ifmore spaceis required, use additional hlRC Form 366A's) (17)

The plant response during this reactor trip was observed to be normal for the given conditions. All safety related systems functioned as designed and all safety functions were met. At no time during this event was the health and safety of the public endangered.

I T C'.

Circuit Breaker 27inthe120VAC Vital SUPSwas multi-amptestedbythe ElectricalMaintenance Department and found to be satisfactory, as was its associated fuse. As a precautionary measure, Circuit Breaker 27 was replaced, then tested for grounds, and instrumented for amperage.

2. The instrumentation and Controls (l8C) Department inspected all solenoids and level switches associated with Circuit Breaker 27.

3. The 5A Feedwater Heater Hi-Hi level switch, LS-11-28A, was cleaned and tested to be satisfactory by the I&C Department.

4. I8C lowered the low pressure trip setpoint for the 1A SGFP to its normal value of 275 psig.

5. System Engineering and Operations tested the 1B MFRV before power ascension. The cause of the valve's misoperation was due to a grounding relay, K2, failing to properly ground out the level control signal after a turbine trip. The K2 relay had dirty contacts and was replaced.

6. A design change is under evaluation to split the Unit 1 A and B Feedwater Heater level control circuits so they are powered by separate breakers, which is similar to the Unit 2 design.

n LIII Magnetrol Liquid Level Switch Model Number 601 MPX United Electronics Controls Pressure Switch Type J120 Model Number 9852 376 I I I The last previous manual reactor trip is described in LER¹335-90-07, "Manual Reactor Trip following leakage of DEH control fluid due to the installation of improperly sized O-Rings.H FPL Facsimile of NRC Form 366 (6-89)