ML17227A493

LER 92-001-01:on 920421,three of Four Local Power Density pre-trips in RPS Alarmed & Turbine Remained Tied to Sys Grid.Caused by Inadequate Core Axial Shape Index Mgt Guidelines.Procedures changed.W/920629 Ltr

ML17227A493
Person / Time
Site:	Saint Lucie
Issue date:	06/29/1992
From:	Sager D, Young R FLORIDA POWER & LIGHT CO.
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
L-92-169, LER-92-001, LER-92-1, NUDOCS 9207060235
Download: ML17227A493 (6)

Text

ACCELERATED DISTIUBUTION DEMONSTRATION SYSTEM REGULAT(Q INFORMATION DISTRIBUTIONZSTEM (RIDE)

ACCESSION NBR:9207060235 DOC.DATE: 92/06/29 NOTARIZED: NO DOCKET FACIL:50;389 St. Lucie Plant, Unit 2, Florida Power & Light Co. 05000389 AUTH. NAME AUTHOR AFFILIATION YOUNGFR.J. Florida Power & Light Co.

SAGER,D.A. Florida Power & Light Co.

RECIP.NAME RECIPIENT AFFILIATION

SUBJECT:

LER 92-001-01:on 920421,three of four local power density-pre-trips .in RPS alarmed & turbine remained tied to sys.

grid. Caused by inadequate core axial shape index mgt guidelines. Procedures changed.W/920629 ltr.

DISTRIBUTION CODE: IE22T COPIES RECEIVED:LTR ENCL SIZE:

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

NOTES:

RECIPIENT COPIES RECIPIENT COPIES ID CODE/NAME LTTR ENCL ID CODE/NAME LTTR ENCL PD2-2 LA 1 1 PD2-2 PD 1 1 NORRIS,J 1 1 INTERNAL: ACNW 2 2 ACRS 2 2 AEOD/DOA 1 1 AEOD/DSP/TPAB 1 1 AEOD/ROAB/DSP 2 2 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 DS SPLB8D1 1 1 NRR/DST/SRXB 8E 1 1 Ei~Z -

02 1 1 RES/DSIR/EIB 1 1 RGN2 'FILE 01 1 1 EXTERNAL: EG&G BRYCEFJ.H 3 3 L ST LOBBY WARD 1 1 NRC PDR 1 1 NSIC MURPHY,G.A 1 1 NSIC POORE,W. 1 1 NUDOCS FULL TXT 1 1 NOTE TO ALL "RIDS" RECIPIENTS:

PLEASE HELP US TO REDUCE WAS'< CONTACT THE DOCUMENT CONTROL DESK.

ROOM 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 .32 ENCL 32

P.O. Box 128, Ft. Pierce, FL 34954-0128 June 29, .1992 APL L-92-169 10 CFR 50.73 U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington,,D. C. 20555 Re: St. Lucie Unit 2 Docket No. 50-389 Reportable Event: 92-001 Date of Event: April 21, 1992 Manual Reactor Trip Due to Local Power Density Control Su lemental Re ort 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. S ger Vice r sident St. Lu ie Plant DAS/JWH/kw Attachment cc: Stewart D. Ebneter, Regional Administrator, USNRC Region II Senior Resident Inspector, USNRC, St. Lucie Plant DAS/PSL 4717-92 rq t'ai)U.: ic 9207060235 920629 PDR ADOCK 05000389 S PDR an FPL Group company

FPL acsrrrtlo at Ua. NUCLEAR RE(RAATORYCOMMtsSION IRG Form Ire LlCENSEE EVENT REPORT (LER)

FACILITYNAME (1) DOCKET NUMBER (2) PAGE 3 St. Lucie Unit 2 050003891 0 4

~E (4) Manual Reactor Trip due to Local Power Density Control Problem Caused by Axial Shape Index Guideline Deficiencies EVENT DATE (5) - LER NUMBER (6) REPORT DA fE m OTHER FACILITlES INVOLVED(6)

DAY YEAR FACILITYNAMES DOCKET NUMBER(S)

DAY YEAR N/A 0 4 2192 9 2 0 0 1 0 1 0 6 2 9 9 2 N/A THIS REPORT 8 SUBMITTED PURSUANT'TO THE REQUIREMENTS OF 10 GFR:

OPERATING Checlr one or more of the followin (11)

MODE (9) 20A02(b) 20,405(c) X 50.73(a)(2)(iv) 73.71(b)

POWER 20.405(a)(1 )(I) 50.73(a)(2)(v) 73.71(c)

LEVEL 50.36(c)(1)-

(10) 0 1 5 20.405(a)(1)(ii) 50.36(c)(2) 50.73(a)(2)(vii) OTHER (Specifyin Abstract

. 20.405(a)(1)(iii) 50.73(a)(2)(i) 50.73(a)(2)(viii)(A) below and rn Text 20A05(a)(1)(iv) 50.73(a)(2)(viii)(B) NRC Form 368A) 50.73(a)(2)(ii) 20A05(a)(1)(v) 50.73(a)(2)(iii) 50.73(a)(2)(x)

LICENSEE CONTACT FOR THIS LER 12 TELEP E NUMBER AREA CODE Robert J. Young, Shift Technical Advisor 4 0 7 465 -3550 COMPLETE ONE LINE FOR EACH COMPONENT FAILURE DESCRIBED IN THIS REPORT 13 CAUSE SYSTEM COMPONENT

~UFA& RE~TMM CAUSE SYSTEM COMPONENT MANUFAC- REPORTABLE TURER TO NPRDS TURER TO NPRDS X J J 6 2A3 48 Y X J J P S VPO 70 Y SUPPLEMENTAL REPORT EXPECTED 14 EXPECTED MONTH DAY YEAR SUBMISSION YES (tlyes, complete EXPECTED SUBMISSlON DATE) NO DATE (15)

ABSTRACT (Limit to 1400 spaces. l.e. approximately fifteen single-space typewritten lines) (1 6)

On 21 April 1992, with Unit 2 in Mode 1, a plant shutdown was in progress for a scheduled refueling outage.

DNhulty in maintaining Axial Shape Index within limits was expected during the downpower. When reactor power reached approximately 15% three of four kcal power density pre-trips In the reactor protection system alarmed. The nuclear plant supervisor directed a manual reactor trip at 0238. On the manual reactor trip the turbine did not trip automatically, but remained tied to the system grkl carrying approximately 90 megawatts.

Several addithnal attempts were made to trip the turbine from the manual pushbuttons in the control room. The turbine was tripped kcally at the front standard using the emergency trip lever at 0241. "Standard Post Trip Acthns" were performed as per EOP-1 and the plant was stabilized in Mode 3, Hot Standby.

The root cause of the reactor trip was inadequacy in the core axial shape index management guidelines. The-root cause of the failure of the turbine to trip either automatically or by manual pushbutton was the failure of the turbine trip controls to perform their functhn because of a relay problem and patticulate matter bhcking a solenokl valve drain port.

Corrective actions for this event: Procedural changes have been implemented to provide additional guidance on axial shape index control Additional guidance has been incorporated into EOP-1 on actions to take for a reactor

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trip with no subsequent turbine trip. A design change to the setpoint of the heal power density pre-trip was also Implemented. Modifications to the turbine control system were made allowing the turbine trip valves to be tested while the unit is online. Modifications were made to the control circuitry of the turbine providing co'ntinuous monitoring of wiring continuity. The effectiveness of these corrective actions will be evaluated for implementathn on Unit 1.

FPL Facsimile of NRG Form 366 (649)

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EQUENTIAL REVISIO UMBER NUMBER St. Lucie Unit 2 0 500 0389 9 2 0 0 1 0 1 0 2 0 4 TEXT (Ifmore space Is required, use addilronal NRC Form 366A's) (1 7)

On 21 April, 1992, with Unit 2 in Mode 1, a plant shutdown was in progress for a scheduled refueling outage. The unit had Just completed a lengthy continuous run (502 days) and as a precaution, an extra senior reactor operator was assigned to the control room shift. As expected, difficulties in maintaining neutron flux axial shape index (ASI) within limits during the downpower were encountered. Maintaining ASI within limits became increasingly difficult since reactor power, reactor coolant system (RCS) (EIIS: AB) temperature and Xenon buikiup were each affecting ASI. With reactor power at approximately 15%, control rod (EIIS: AA) insertion ori lead control bank ¹5 was no longer having any effect on controlling ASI. Three of four kcal power density (LPD) pre-trips in the reactor protection system (RPS) (EIIS: JC) actuated. At 0238 the nuclear plant supervisor (NPS) directed the reactor control operator (RCO) to manually trip the reactor. On the manual reactor trip the turbine (EIIS: TA)did not trip automatically, but remained tied to the system grid carrying approximately 90 megawatts. Several additional attempts were made to trip the turbine from the manual turbine trip pushbuttons (EIIS: JJ) on the control room console. In addition, the main steam Isolation valves (MSIVs)(EIIS: SB) were dosed, the digital electro-hydrauic control (DEH) (EIIS: TG) pumps were secured and the nuclear watch engineer (NWE) was directed to trip the turbine locally with the emergency trip lever at the front standard of the turbine. The turbine was tripped locally at 0241 with all turbine valves indicating closed. The lowest RCS temperature reached was 525 degrees Fahrenheit. Standard Post Trip Actions" were performed as per EOP-1 and the plant was stabilized in Mode 3, Hot Standby.

DifficuIIIes in controlling ASI were expected due to the high degree of core bumup. This had been discussed prior to the shutdown by operations department supervision and a decision made to trip the reactor manually if ASI control could not be maintained throughout the downpower. The shutdown of the reactor was performed in a slow and conservative manner. As expected, during the downpower ASI became more negative. ASI was being compensated through control rod insertion on group ¹5, the lead group. At approximately 15% reactor power and 85 inches withdrawn on group ¹5, control rod insertion was no longer providing the desired effect on ASI. The reactor was tripped as per previous decisions.

The cause for the failure of the automatic and manual pushbutton turbine trips was investigated by a multidiscipline team. Members of the team Included representatives from maintenance, operations, system engineering, design engineering, and the turbine vendor. Extensive vendor input was obtained and a failure analysis plan was prepared. Several key components were carefully removed and sent to an independent lab for evaluation in the "as found" condition. Hydraulic fluid samples were also taken and analyzed. A test procedure was written and performed to evaluate the operation of all turbine trip functions. A complete circuit wiring inspection was performed.

FPL Facsimile of NRC Form 366 (6-69)

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EQUENTIAL REVISIO NUMBER NUMBER St. Lucie Unit 2 0500 0389 9 2 0 0 1 0 1 0 3 0 4 TEXT (limore spaceis required, use additional NRC Form 366A's) (17)

The failure of the turbine to trip automatically was caused by unrelated failures in the two redundant and electrically independent automatic turbine tripping schemes.

Turbine trip testing showed that turbine trip solenoid valve 20 AST failed due to an intermittent loss of circuit continuity. The wiring inspections revealed two deficiencies at relay 62 ASTX either of which could have caused such a failure. The deficiencies were a kese terminal connection in the circuit at the relay and burned relay contacts within the relay.

Independent lab disassembly and examination of solenokl 20 ET revealed that particulate matter was bkcking a small port which prevented the solenokl valve from dumping the turbine hydraulic flukl and tripping the turbine. Two other identical solenokl valves also connected to the same hydraulic system were clean. Samples of the hydraulic flukf did not contain the type of particulate found in 20 ET. The origin of the particulate could not be determined.

Because these two unrelated failures could not be detected with the existing system design and surveillance program, a loss of the automatic turbine trip capability resulted.

The mechanical and electricai turbine overspeed trips were fully functional but were not challenged during the event. The associated manual trip lever at the turbine front standard did trip the turbine when actuated by the operator during the event.

This event is reportable under 10 GFR 50.73.a.2.iv. as "Any event or condition that resulted in manual or automatic actuation of any engineered safety feature, including the reactor protection system." The NPS decided to manually trip the reactor upon the receipt of the third LPD pre-trip in anticipation of an automatic RPS actuation.

The turbine did not trip automatically or manually and was locally tripped approximately three minutes after the reactor trip. The MSIVs were closed by the RGO at 0239 which terminated the event. The plant response to this event is boundedby section 15.1.5 of the PSL Unit 2 Final Safety Analysis Report (FSAR), "Increased Heat Removal by the Secondary System" as further described below:

1) Virrth a reactor trip at 15% power and with no operator actions taking place, the MSIVs will automatically close when the pressure in a steam generator reaches 600 psia and the cooldown event will be terminated. This cooldown rate is bounded by the limiting FSAR cooldown evept.

2) With a reactor trip at 100% power and with no operator actions taking place, there will be a safety injection actuation signal (SIAS) (EIIS: BQ) recieved but there will be no actual injection. The MSIVs will automatically close when the pressure ln a steam generator reaches 600 psia and the cooldown event will be terminated. The cooldown rate is bounded by the FSAR cooldown event as confirmed by in-house RETRAN analysis.

FPL Facsimile of NRC Form 366 (6-89)

FPL Facalrrso ar IQC Farm $ 8 US. NUCLEAR REGULATORY COMMrssrCN PttIC7%5 ~ IC1 SI%4lrr UCENSEE EVENT REPORT (LER)

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FACIL NAME (1) DOCKET NUMBER (2) LER NUMBER (6) PAGE (3)

EQUENTIAL REVISIO NUMBER NUMBER St. Lucie Unit 2 0500 0389 9 2 0 0 1 0 1 0 4 0 4 TEXT (Ifmore space is requinsd, use additional NRC Form 368A's) (17)

3) With a reactor trip at 100/a power in an FSAR Chapter 15 Accident Scenario (le. Excess Steam Demand with single failure of the turbine stop valves to dose), with operator action, the safe shutdown of the reactor will be achieved because operators-are trained to handle Design Basis Accidents. Multiple failures are procedurally addressed by Emergency Operating Procedures.

1. Procedural changes were implemented to provkle additional guidance for ASI control .

2. Procedural changes were incorporated into EOP-1 providing additional guidance on actions to take for a reactor trip with no subsequent turbine trip.

3. A design change to the setpoint of the local power density pre-trip has been implemented during this refueling outage. Due to hardware limitations the pre-trip setpoint had been at a lower than desired setting. With the installation of new hardware the pre-trip setpoint was moved closer to the trip setpoint and is now at the same setting as Unit 1.

4. A modification to the turbine trip control system has been implemented to provide for continuous monitoring of control circuitry integrity.

5. A modification has been made to the turbine control system hardware allowing online testing of the turbine trip and overspeed protection solenoids.

6. An increased inspection frequency for the 20 AST circuit deenergizing relay has been added to preclude future burnt contacts.

7. The effectiveness of these corrective actions will be evaluted for implementation on Unit 1.

Relay, Agastat Solenoid valve, Patker Hanna Model 7012 PCL Valve ID ¹SE22185 S/N 78441891 Model (piot assembly), R6V2DHV50X2252 125 volt DC The only similar event for a reactor trip caused by heal power density is described in Licensee Event Report 38946-001. This event was an automatic trip, during power ascension, caused by personnel error. There have not been any previous events where the turbine failed to trip following a reactor trip.

FPL Facsimile of NRC Form 366 (6-89)