05000324/LER-1980-066-01, /01T-0:on 800907,reactor Core Isolation Cooling Turbine Tripped on High Turbine Exhaust Pressure.Caused by Improper Valve Positioning Apparently Due to Personnel Error

/01T-0:on 800907,reactor Core Isolation Cooling Turbine Tripped on High Turbine Exhaust Pressure.Caused by Improper Valve Positioning Apparently Due to Personnel Error

ML19332B377
Person / Time
Site:	Brunswick
Issue date:	09/19/1980
From:	Tollison A CAROLINA POWER & LIGHT CO.
To:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
Shared Package
ML19332B373	List: 05000324/LER-1980-066-01, /01T-0:on 800907,reactor Core Isolation Cooling Turbine Tripped on High Turbine Exhaust Pressure.Caused by Improper Valve Positioning Apparently Due to Personnel Error
References
LER-80-066-01T, LER-80-66-1T, NUDOCS 8009260638
Download: ML19332B377 (6)

LER-1980-066, /01T-0:on 800907,reactor Core Isolation Cooling Turbine Tripped on High Turbine Exhaust Pressure.Caused by Improper Valve Positioning Apparently Due to Personnel Error

Event date:
Report date:
3241980066R01 - NRC Website

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4 60 64 DOCsCET NUM8ER 64 69 EVLNT DATE 74 75 REPORT DATE to EVENT DESCRIPTION AND PROBA8LE CONSEQUENCES h l o l 2 l lVnile performing the Unit No. 2 RCIC Flow Rate Test at 150 psin reactor pressure.

I l the RCIC turbine tripped on high turbine exhaust pressure. An investigation re-I o 3 l o 141 Ivealed the manually operated stop check in the RCIC turbine exhaust to the torus was I

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• LER ATTICINEI'T - RO NO. 2-80-62 Facility: BSEP Unit No. 2 Event Date:

9-7-80 Title:

HPCI and RCIC Turbine Exhaust Manual Stop Check Valves - Found Closed Initial Conditions:

. Unit No. 2 was in the startup mode on September 7,1980, at approximately 150 psig. The unit had started up on September 3,1980, following the 1980 refueling / maintenance outage.

Reactor pressure had been up to approximately 180 psig during unit starcup. The unit had been held in the startup mode due

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to problems with condenser leaks, condensate leaks, and HPCI control valve problem during the period from September 3-7, 1980.

Event Descript'fon:

At approximately 2100 hours0.0243 days <br />0.583 hours <br />0.00347 weeks <br />7.9905e-4 months <br /> on September 3, 1980, an attempt was made to test RCIC at 150 psig reactor pressure. The RCIC turbine tripped on high exhaust pressure. A subsequent investigation revealed that the RCIC turbine exhaust manual stop check ~ valve (8" Anchor - Rising Handwheel), RCIC F001, was in the locked-closed position.

The HPCI turbine exhaust manual stop-check valve (20" Anchor - Rising Stem),

HPCI F021, was also checked and found to be in the closed position without a lock. Eoth valves, RCIC F001 and HPCI F021, are required to be in the 1ccked open position for normal operation. These valves are containment isolation valves on turbine exhaust lines which penetrate the torus.

Cause Description:

An investigation was initiated following the event to determine the cause of the valves being in the wrong position. The apparent cause is personnel The following~ is a chronology of events related to both valves:

error.

1.

Unit No. 2 reactor was shut down to begin the refueling / maintenance outage on March 1, 1980.

2.

Equipment Clearance No. 2-429 was placed in effect for the torus modification on March 4, which aligned valves RCIC F001 and HPCI F021 in the shut position.

3.

A leak rate test was performed on HPCI F021 in accordance with PT 20.3 on April 7.

Test data sheet shows that the valve was returned to the open position after the test.

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Cause Description:

(Cont'd) 4.

The torus clearance was removed on June 14.

Valve alignmant sheets, which require double initials, indicate both valves were restored to the locked opea position.

5.

A leak rate test was performed on valve RCIC F001 in accordance with PT 20.3 on June 26.

Equipment Clearance No. 2-528 hung for this test was cancelled on June 27 and indicated the valve was restored to the shut position.

6.

The RCIC System lincup was co=pleted on July 13.

This lineup indicates that valve RCIC F001 was locked open. The HPCI lineup was apparently mfsplaced and could not be-located.

It was verified as having been accomplished.

7.

Locked valve PT 46.1 was completed on August 28.

Valves RCIC F001 and HPCI F021 were indicated as locked open.

8.

The Unit No. 2 reactor startup occurred on September 3.

An investigation of the known events which involved repositioning or verifying valve position revealed the following:

1.

No instruction exists in PT 20.3 for positioning a valve uhan it cust be Icft in a position other than the normal position.

2.

Certain auxiliary operators performing valve lincups and clearance removals had not completed their qualifications on cicarances or on the systems where these clearances applied.

3.

The auxiliary operators involved in these clearances (which require t

doubic initials) did not independently verify cach valve.

4.

Evidence indicates that some individuals involved did not personally verify valve position.

5.

There was insufficient procedural guidance on how to handle and document unusual situations encountered in valve 11ncups such as interference by cicarances.

6.

Required review of the valve lineups was conducted in insufficient detail to detect these problems.

Corrcetive Actions:

In=cdiate Corrective Action:

1.

Both calves were immediately reponitioned to open and locked.

2.

A complete HPCI lineup was performed with no additional lineup discrepancies found.

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Followup Corrective Action:

l.

Instructions were placed in the Daily Instruction to remind all shif ts to use only operators qualified to hang and cancel clearances.

2.

Locked valve PT 46.1 was performed twice on each unit. Valve RCIC-F002 (2" Velan Globe), vacuum pump discharge to the suppression pool, was found locked closed on Unit No. 2.

The valve was repositioned to open and locked. This valve did not render RCIC inoperative.

3.

Based on three valves being found out-of-position, an analysis was performed on Unit No. 2 to determine the necessity for repeating system lineups for Technical Specification systems. The analysis considered the following:

a.

Demonstrated operability.

b.

Remote position indication.

c.

Teclinical Specificatio.n required surveillance tests.

d.

Current lock-valve pts.

Repeat valve lineups on systems where items a-d were not sufficient c.

to positively conclude that system operability was assured.

The following lineups were repeated:

a.

Standby Liquid Control.

b.

Service Water in the Diesel and Reactor Buildings.

Nuclear Boiler - Outside the Drywell.

c.

d.

Reactor Protection.

No discrepancies were found during these lineup checks.

Unit No. 1 lineups were nct repeated based on:

Completion of the last startup program including startup pts and a.

testing o,f ECCS systems.

b.

Demonstrated operability of syste=s.

c.

Remote position indication on RTGB.

d.

Double verification of the locked-valve PT on September 8,19S0.

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Followup Corrective Action:

(Cont'd) 4.

A meeting was held between Operations management personnel (Manager-Operations, Shif t Operating Supervisors, and Shif t Foremen), the Manager-Plant Operations, the plant General Manager, and the Vice President-Nuclear Operations on September 18', 1980. The seriousness of this event and the absolute need to prevent any future occurrences of this type were stressed. Causes and corrective actions were covered.

Management philosophy regarding what is expected of operators and what should be demanded f rom them was discussed.

It was also discussed that absolute integrity is required from cach operator and that deviations from that will result in disciplinary action. Methods for better utilization of management time and training of auxiliary operators were also discussed.

5.

As a followup to Item 4, special off-shift meetings are being held with all shif t personnel to ensure tbnir full understanding of this event and its seriousness.

Permanent Corrective Action:

1.

The clearance procedure will be revised to require that auxiliary operators be qualified on the safety-related systems before hanging or removing clearances on those systems.

For restoring the systems to normal, the person verifying the valve position will also be qualified.

2.

A procedure will be developed on the methods for performing system lineups (including removing clearances and restoring the system lineup). The procedure will include the following:

7' Proper method of checking valve position.

a.

b.

Procedure to be followed in the event exceptions, such as clearance tags, are encountered.

c.

Method of performing double verification.

d.

How to verify position of locked valves.

Who can and cannot perform valve lineups.

c.

3.

Training Instruction, TI-104, will be revised to indicate on-the-job training requirements for:

a.

Hanging and removing clearances.

b.

Valvo lineups.

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Permanent Corrective Action:

l 4.

Operating procedures will be revised to require that valve lineups for safety systems include verification of cach valve position by a second individual.

5.

General Operating Procedure, CP-1, will be revised to require verifi-cation that valve lineup sheets have been completed.

6.

This LER will be reviewed with all shif t personnel by Shif t Operating Supervisors with emphasis on:

• a.

The seriousness of this event and what it can lead to.

b.

Disciplinary action or dismissal will result f rom poor perfor-mance in this area.

7.

PT 20.3 will be revised to accomplish the following:

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n.

Double verification of restored lincups, b.

. Require signature of persons who actually verified the lineup.

c.

Provide guidance on valves which cannot be restored to normal operating position at the time.

8.

Appropriate corrective or disciplinary actions for individuals and supervisors involved in this event are being taken.

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