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On 6/16/87 at approximately 1724 CDT, plant operations personnelperforned a surveillance on the High Pressure Coolant Injection (HPCIEIIS Code BJ). The system was behaving erratically and HPCI was I

determined to be incapable of perforning its intended safety function. |

Corrective maintenance was initiated on the HPCI system and on 6/18/87,two Prinary Containment Isolation System (PCIS EIIS Code J!i) HPCI steamsupply valve isolations occurred. These isolations were unplannedactuations of an Engineered Safety Feature (ESF).

The root causes for the events were: 1) a defective procedure, and 2)personnel errors. Specifically, a calibration procedure did not contain lsufficient directions (or allow the use of reverse or direct acting i

governors), and on site and vendor personnel did not verify that correct |parts were issued. |

Corrective actions for these events included: 1) replacing equipment,2) checking or calibrating equipment, 3) demonstrating HPCI operability,

|

4) issuing an As Built flotice, 5) placing spare parts on hold, 6) '

lreviewing plant document, 7) revising or scheduling revisions toprocedures, 8) initiating vendor feedback and audit reviews, 9) 7performing a 10 CFR Part 21 evaluation, and 10) counseling personnel, h

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A. REQUIREMENT FOR REPORT

This report is required per 10 CFR 50.73 (a)(2)(iv), becauseunplanned actuations of an Engineered Safety Fcature (ESF)occurred. This report is also required per 10 CFR 50.73 (a)(2)(v),because the High Pressure Coolant Injection (HPCI EIIS Code BJ)system was incapable of performing its intended safety function.

.

B. UNIT (s) STATUS AT TIME OF EVENT

This LER describes three events. The initial event describes anoccurrence where an ESF was incapable of performing its intendedsafety function. The second and third events describe occurrenceswhere an unplanned actuation of an ESF occw;ed.

On 6/16/87, Unit 2 was in the run mode at an approximate powerlevel of 2200 MWt (approximately 90 percent of rated thermalpower). This is the first event and the one where an ESF wasincapable of performing its intended safety function.

On 6/18/37, Unit 2 was in the run mode at an approximate powerlevel of 2194 MWt (approximately 90 percent of rated thermal

;power). This is the second event. During this event, the first |

ESF actuation occurred. l

On 6/18/87, Unit 2 was in the run mode at an approximate powerlevel of 2191 MWt (approximately 90 percent of rated thermalpower). This is the third event. During this even't, the secondESF actuation occurred.

|

|C. DESCRIPTION OF EVENT '

On 6/16/87 at approximately 1724 CDT, licensed plant personnel werein the process of performing plant procedure 34SV-E41-002-25 (HighPressure Coolant Injection). This is a HPCI pump operabilitysurveillance procedure. During performance of the procedure, itwas determined that the HPCI system could not be controlled in theautomatic or manual mode with the 2E41-R612 controller.

The HPCI system was declared inoperable and a Limiting Conditionfor Operation (LCO) was initiated per the Unit 2 TechnicalSpecifications section 3.5.1. Plant personnel also initiated aMaintenance Work Order (MWO) to investigate the anomalous systemresponse.

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On 6/17/87, while the HPCI system was still in the LCO, the MWO wasreleased for work on the HPCI system. On 6/17/87, the followingactions occurred:

1. Corrective maintenance was performed on the HPCIsystem, flaintenance personnel determined that theerratic HPCI operation was due to a faulty ElectricGovernor Remote servo (EGR). They disassembled the EGRto verify that none of the oil ports were blocked. It

was determined that none of the ports were blocked.However, by disassembling the EGR, the environmentalqualification of the part was degraded, necessitatingreplacing the component.

2 Maintenance personnel consulted the spare parts listfrom the warehouse to determine what spare parts werein current inventory that were replacements for thedefective EGR. From the spare parts list, theyobtained a stock number which they used to request theneeded part.

3 Using the stock number from the spare parts list, a ;Stock Material Issue (SMI) form was generated.Warehouse personnel filled the SMI request by providingthe requested part. i

4 tiaintenance personnel reviewed the received part numberversus the SMI and verified that they had received thecomponent requested.

5. Maintenance personnes installed the new EGR per thevendor manual.

6. Quality Control (QC) verified that the part installedwas the same as that identified on the SMI.

On 6/18/87 at approximately 0515 CDT and later at 1802 CDT,licensed plant personnel were in the process of performingprocedure 34SV-E41-002-2S. This procedure was being perforned toverify operability of the HPCI system since corrective maintenancehad been performed on it (on 6/17/87). The HPCI turbine wasstarted and inmediately tripped due to an inboard logic isolationsignal generated when the inboard isolation valve (2E41-F002)closed. This valve closed on a steam line high differentialpressure (high flow) signal. After the 0515 CDT event, plantpersonnel investigated the isolation and they performedcalibrations on the isolation logic for the turbine. No problemswere found. The decision was made to run the HPCI turbine and jmonitor the system performance both locally and in the main control I

roon. Subsequently, the 1802 CDT event occurred. Plant operationspersonnel docunented the anomalous system responses by initiatingDeficiency Cards (DCs) for the two events,

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Valve 2E41-F002, while part of the HPCI system, is also a PrimaryContainment Isolation System (PCIS EIIS Code JM) valve. Theclosure of this valve was the result of an unplanned actuation ofan ESF (the PCIS). Even though the HPCI system was out of service(per the LCO), the PCIS was in service and required to be operable.

On 6/19/87, the |iPCI system was still out of service in the LCOcondition. On this date the following items occurred:

1. Corrective maintenance was perfomed on the HPCIsystem. Maintenance personnel. determined that thecause of the isolation of the HPCI steam line was againdue to a faulty EGR. They determined the EGR needed tobe replaced.

2. Maintenance personnel again consulted the spare partslist from the warehouse to request the needed part(sane stock number as before), t

3. Using the stock number, a Stock Material Issue (SMI)|fom was generated and the replacement part obtained.

4. fiaintenance personnel reviewed the received part numberversus the SiiI and again verified that they had ,received the requested part.

|

S. itaintenance personnel installed the new EGR per the l

: vendor manual.6 Quality Control (QC) verified that the part installed

was the same as that requested in the SMI.7. In light of the previous failures of the EGR module, a

decision was made to test the EGR locally. The testwas conducted by Instrument and Control (I&C) andengineering personnel and the results determined thatthe EGR was controlling backwards in that when thesteam admission valve to the HPCI turbine should haveclosed, it opened and when it should have opened, itwent closed. |

On 6/20/87, trouble shooting for the anomalous response (EGRcontrolling backwards) continued. Maintenance personnel calibratedthe Electric Governor ftagnetic pickup (EGit) by plant procedure |57CP-CAL-068-2S (Woodward EGM EGR HPCI and RCIC Turbine Governor)and found that it calibrated properly. They concluded that theproblem could be a wiring problem between the EGM and the EGR.

Site engineering, in turn, consulted with the EGR vendor. From theconsultation, it was determined that the part provided by thevendor was a reverse acting EGR while the EGR that was originallyin the HPCI system was a direct acting EGR. To function correctly,a direct acting EGR was required or the wiring between the EGR andthe EGM needed O be rolled (switched). The direct acting and thereverse acting EGRs are identical except that two internal wires ,

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On 6/21/87, the system engineer provided the maintenance personnelwith work instructions to roll the wires between the EGM and theEGR. Maintenance personnel performed the rolling and verified thatthe EGR worked properly when tested locally.

On 6/22/87, the HPCI system was tested for operability by procedure34SV-E41-002-2S. The system passed the operability test and wasdeclared operable. The LC0 was removed and the HPCI system wasreturned to service.

D. CAUSE OF EVENT

In order to fully understand the event and the circumstances of the jevent, plant personnel investigated the spare parts replacementhistory of the EGRs. They determined that the original EGR was aWoodward Governor Company part number R8250-133, direct acting,clockwise actuator. This was the part type that was oi |ginallyremoved from the HPCI system on 6/17/87.

However, the Woodward Governor Company no longer makes partR8250-133. Instead, they now manufacture a replacement part,9903-026. This is a direct acting clockwise actuator. They alsomanufacture a R9903-026 part which is a reverse acting clockwiseactuator. The only difference between the 9903-026 and P9903-026part numbers is that the wiring to the coil of the EGR has beer,reversed internally.

When replacement parts (for the R8250-133 EGR) were received onsite, site personnel noted that a part number discrepancy existed.They requested General Electric (GE) to provide documentaticn thatthe received part was an acceptable replacement part.

GE (and subvendor Terry Turbines) furnished documentation,including a Product Quality Certificate (PQC) that indicated thatthe supplied parts were 9903-026, direct acting clockwiseactuators. However, the parts were, in reality, R9903-026 whichare reverse acting clockwise actuators. These were entered intothe plant stocks. When maintenance personnel requested areplacenent for the HPCI EGR on 6/17/87, one of the reverse actingEGRs was issued to them.

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A reverse acting EGR could have been used in the HPCI systen, if it .

was recognized that the EGR was a reverse acting EGR. If some of |the internal wiring going to the EGR is rolled on terminals 4 and 5 ;

at the EGil, the reverse acting EGR will function like a direct |acting EGR. Maintenance personnel were not aware that they had a '

reverse acting EGR and therefore, did not know that the wires j

needed to be rolled.

As such, when the EGR was installed, plant personnel anticipatedthat it would close the governor valve as speed increased above theHPCI controller set point. Instead it opened the governor _ valve.This caused a high steam line flow condition to result and a steam |

line isolatica occurred. |

Once the above information was determined, it was possible todetermine the root cause for each one of the events described inthis LER.

The root cause of the 6/16/87 event is due to an error in anapproved maintenance procedure. Specifically, procedures57CP-CAL-068-1S (Woodward EGri, EGR: HPCI and RCIC Governor) [forUnit 1) and 57CP-CAL-068-2S [for Unit 2] did not contain sufficientoscillation control directions. Additionally, the procedures didnot allcw for a direct or reverse acting EGR replacenent.

The system engineer reviewed the procedure and determined that theprocedure is not clear, nor does it contain enough specificinfornation about dynanic calibration (turbine operation) of theEG?1 and the EGR and their interfaces. The system engineer noted .

that excessive speed variation can be caused either by the EGli !

gain / stability potentiometers being out of adjustment or by the EGRhydraulic actuator needle valve being out of adjustnent. Theprocedure required that the dynamic calibration be performed "asrequired" but should be performed every refueling outage,

i

Additionally, the procedure did not contain sufficient oscillation jcontrol directions. The lack of sufficient oscillation controldirections resulted in the failure to properly calibrate the EGRresponse. This in turn, resulted in equipment instability andsubsequent replacement of the EGR. The EGM was calibrated on9/24/86, but the EGR needle valve adjustment for oscillationcontrol was not performed (because the procedure did not require ;

that the adjustnent be performed). )|

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. The root cause of the two events that occurred on 6/18/87 is due tof cognitive personnel error. The personnel error occurred on the

part of the vendors (Terry Turbine and General Electric) and on thepart of site personnel . The vendor personnel error occurredbecause the vendor supplied documentation stated that thereplacement parts were in accordance with the Georgia Power Company(GPC) purchase order requirements. In fact, reverse acting ratherthan the specified direct acting parts were transmitted to GPC.

Both site Quality Control (QC) and materials department personnelmade cognitive errors. This occurred when the site personnel

,

failed to detect the errors that the vendors had made when theparts were received. {

E. ANALYSIS OF EVENT

The HPCI system is provided to assure that the reactor core is 8

adequately cooled to limit fuel clad temperature in the event of asmall break in the nuclear system where the loss of coolant doesnot result in a rapid depressurization of the the reactor vessel.The HPCI system operates until reactor vessel pressure is below the

|pressure at which the Low Pressure Coolant Injection (LPCI EIIS I

Code 80) operation or Core Spray (CS EIIS Code BM) system operationmaintains core cooling.

4

;

With the HPCI system inoperable, core cooling is achieved via thei

redundant and diverse Automatic Depressurization System (ADS EIIS !

Code JE) operating in conjunction with the low pressure coolingsystems. The Reactor Core Isolation Cooling (RCIC EIIS Code BN)system, (a system for which no credit is taken in the safetyanalysis), will also automatically provide makeup at reactoroperating pressures upon receipt of a reactor low water level ,

condition.

During this event, all of the required backup systems (ADS, LPCIand CS) remained operable. Additionally, the RCIC system was alsooperable. The operability of these systems was required and

-

verified by compliance with the Technical Specifications,specifically section 3.5.1.

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Since these events occurred at a high power level (90 percent ofrated thermal power), it is not be' ad that the consequences ofthese events would be significanti ferent under other reactorpower ecnditions. Since all of th. . quired backup systems andRCIC were capable of performing their intended safety functions, itis concluded that this event had no adverse nuclear safety impact.

|'

F. CORRECTIVE ACTIONS

The corrective actions for this event included:i

1

1. Replacing the original HPCI EGR actuator and checkingthe original EGR for blockage of oil ports. Noblockage was found.

2. Checking and or calibrating plant equipment. The HPCIcontrol loop was checked. The inboard HPCI High SteamLine delta pressure instrumentation, trip units, andtime delay relay were calibrated. Plant Instrument andControl (180) personnel performed these activities and

I they found the loop and other equipment to be withincalibration and functioning correctly. The HPCI EGMwas calibreted per procedure 57CP-CAL-068-2 and found

i to be with tolerances.1

3. Demonstrating HPCI operability and returning the system,

' to service on 6/22/S7. The LC0 was cleared when theHPCI system was returned to service.

I 4 Issuing an As Built Notice (ABN). The ABN was issuedi against the Unit 1 and Unit 2 HPCI manuals. The ABN'

alerts personnel that direct acting and reverse actingEGRs can be used on the HPCI system. However,

| depending on the EGR type, the wiring hookup betweenthe EGR and the EGM will be different.

5. Placing a hold on all Unit 1 and Unit 2 HPCI turbineEGRs that are in current warehouse stock. Anengineering evaluation is required prior to issuance ofthese EGRs.

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6. Reviewing plant documents. It was determined that thematerials department receiving procedures adequatelyaddress part number verification. However, there wasthe need for desk top instructions to provideadditional guidance to senior storekeepers relative toreceipt processing.

These instructions were issued on 8/24/8' and theypartict.larly address the area of receipt discrepancyresolution (part numbers, quantities, etc. ). Theseinstructions also include foreman and supervisoryinvo'ivement in the resolution of discrepancies.

Procedural controls relative to QC parts verificationwere also reviewed. QC personnel concluded that theprocedures are adequate, as written.

7. Revising or scheduling revisions to plant procedures.Plant procedures 57CP-CAL-068-1S (Unit 1) and57CP-CAL-068-2S (Unit 2) were revised with an eff.!ctivedate of 11/11/87 and the following caution was insertedinto the EGR replacement section:

"Caution: Depending on the EGR type, the wiringconnection betweer. the EGR and EGM will bedifferent. New EGR's can be internally wireddifferent which could make EGR's reverse actingor direct acting. Consult system engineer forcorrect type and model number."

The procedure revisions also included the acceptancespeed variation requirements (which includedinformation related to the oscillation requirements),and the frecuency of performance 'every refuelingoutage).

Plant procedure 55MC-MTL-001-0S (Materials Receiving)was scheduled for revision. The revision will reviewthe procedure and, as necessary, incorpo te theappropriate sections of the desk top inst uctions. It

is anticipated that the revision process will becompleted by approxinately 7/1/88.

The remaining portions of the desktop iristructions, asapplicable, will be incorporated irtto a permanent plantprocedure or instruction by 7/1/88.

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PLANT HATCH, UNIT 2 og,,o , ;3 6;6 q7 __ 0; q 4 __ 0,1 }0 1| ;o,

I8 Initiating a vendor feedback form and determining if

other audits of the vendor are required. The vendorfeedback form was generated by the site nuclearprocurement review group and sent to the corporatequalified suppliers list coordinator. This documentedthe method that GE handled the event. It wasdetermined that a recent audit of the parts supplierwas acceptable and additional auditing was not required.

9. Requesting a 10 CFR Part 21 evaluation or the event.The evaluation determined that the event is notreportable per the requirements of 10 CFR 21.

10. Counseling QC personnel wno were involved in the event.

G. ADDITIONAL INFORMATION

| 1. FAILED COMP 0 MENTIS) JDENTIFICATION

No equipment failed and contributed to this event.This conclusion is based on the root causedetermination. The original EGR is believed to havebeen out of adjustment. If the calibration procedurehad not been defective (because it did not containsufficient oscillation control directions), it isbelieved the original EGR could have been adjusted andwould not have been replaced.

2. PREVIOUS SIMILAR EVENTS

| Previous LERs have reported events where the HPCIsysten was inoperable or where HPCI PCIS valvesactuated. These LERs are 50-366/1986-007 (dated2/13/86) and 50-366/1986-014 (dated 7/17/86).

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LER 50-366/1986-007 described an event where one i

of the HPCI PCIS valves isolated. LER50-366/1986-014 described an event where the HPCIsystem was incapable of perfoming its intendedsafety function. The LER also reported anisolation of one of the HPCI PCIS valves.

The cause of the event described in LER50-366/1986-007 was due to a defective drawingthat did not show one electrical link. When acalibration procedure was written using thedefective drawing, the electrical link that wasmissing from the drawing was not required to beopened (i.e., was always closed). Thus, when the |procedure was perfomed, the isolation logic(since the link was closed) was capable of |perfoming its function and the valve closed.

The cause of the events described in LER50-366/1986-014 was personnel error. Maintenancepersonnel inadvertently left a rag in the HPCIlube oil sump after maintenance was performed.This rag prevented the lube oil system fromfunctioning correctly and it prevented HPCI frombeing capable of perfoming its intended safetyfunction. Additionally, another per',onnel crroroccurred during maintenance in that a cable wasaccidentally damaged such that when the HPCI wastested, an isolation of one of the HPCI PCISvalves occurred.

Corrective actions for these events included: 1) i

developing procedures, 2) perfomingcalibrations, 3) generating an As Built Notice(ABN), 4) repairing damaged equipment, and 5)notifying maintenance personnel of the events andthe consequences of the events,

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The corrective actions for these events would nothave prevented tne event described in LER50-366/1987-004 because the causes of the eventswere different. In the above previous events,the root causes for the events were defectivedrawings and personnel errors. In LER50-366-1987-004, the causes of the events weredefective procedures and personnel errors. Whilepersonnel errors occurred, the errers were made iby different groups of personnel who performeddifferent functions. Additionally, some of thepersonnel errors were performed by personnel whobelong to other companies (off site vendorpersonnel).

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Ananta, Georg a 30308Teiephone 404 52&6526

Maang Address-Post Oftce Box 4545Manta, Georg-a 30302

} Georgia Power"

Ma r uclear Safetyand Lcens,ng

SL-38340044IX7GJ17-H310

March 25. 1988

U. S. Nuclear Regulatory CommissionATTN: Document Control DeskHashington, D. C. 20555

PLANT HATCH - UNIT 2 !

NRC DOCKET 50-366OPERATING LICENSE NPF-5

LICENSEE EVENT REPORTPROCEDURE DEFECT AND PERSONNEL ERRORS

CAUSE SYSTEM INOPERABILITY AND ESF ACTUATIONS i

f Gentlemen:

In accordance with the requirements of 10 CFR 50.73(a)(2)(iv) and10 CFR 50.73 (a)(2)(v), Georgia Power Company is submitting the enclosed,revised, Licensee Event Report (LER) concerning unanticipated actuationsof an Engineered Safety Feature (ESF) and a condition where an ESF couldhave been incapable of performing its intended safety function. Theevents occurred in June of 1987 at Plant Hatch - Unit 2.

Sincerely,

#A%L. T. Gucwa

|'

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Enclosure: LER 50-366/1987-004 Rev 1

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March 25, 1988 !Page Two

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c: Georaia Power Comoany"

. Mr. 3. T. Beckham, Jr., Vice President - Plant Hatch~

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U. S. Nuclear Reaulatory Commission. Washinaton. D. C. .

Mr. L. P. Crocker, Licensing Project Manager - Hatch"

U. S. Nuclear Regulatory Commission. Reaion IIDr. J. N. Grace, Regional-AdministratorMr. P. Holmes-Ray, Senior Resident Inspector - Hatch

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