Text

Insp Rept 50-302/89-17 on 890619-20.Violations Noted.Major Areas Inspected:Followup to Events Surrounding 890616 Loss of off-site Power transient-review of Plant & Operator Response to Transient,Root Cause & Corrective Actions
	ML20245K296
Person / Time
Site:	Crystal River
Issue date:	08/10/1989
From:	Casto C, Conlon T, Ruff A; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:	;
Shared Package
ML20245K282	List: ML20245K279; ML20245K289; ML20245K296;
References
	50-302-89-17, NUDOCS 8908180390
	Download: ML20245K296 (16)
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ATLANTA, GEORGI A 30323

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Report No.:

50-302/89-17

' Licensee:

Florida Power' Corporation

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3201 34th Street, South

St., Petersburg, FL 33733

Docket No.:

50-302

License No.:

DPR-72

Facility Name:

Crystal River 3

Inspection Conducted:

une'19-20, 1989

Inspectors:

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Date Signed

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Approved by:

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T. Conlon

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Date Signed

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SUMMARY

Scope:

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This routine announced inspection was conducted as a follow-up to the events-

surrounding the loss of off-site power transient experienced on June 16, 1989.

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The scope of this inspection included review of the plant and operator response-

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to the transient, the root cause, and corrective actions taken by_the licensee

to prevent future occurences of this nature.

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Results:

Increased management attention to control the interface between the Units 1

and 2, switchyard and the Unit 3 Start-up transformer is' needed.

The current

plant design relies solely on the Unit 3 Start-up transformer as the primary

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source of power to the Emergency System and Unit buses. An additional source .

of off-site power would enhance the response to a single failure of the Unit 3

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transformer. Additionally, during the event of June 16, 1989, the Emergency

Feedwater Pump-1 failed to automatically start after the Emergency Diesel

Generator powered the Emergency Buses.

This failure may have been prevented

had proper testing of the logic string for this sequence been tested. The

inadequate testing was not identified during the root cause analysis completed

by the licensee.

8908180390 890811

FDR

ADOCK 05000302

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REPORT DETAILS

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1.

Persons Contracted

Licensee employees

D.' Beach, Supervisor, Technical Engineering Services

M. Fitzgerald,- Supervisor, Electrical Engineering

R. Fuller, Senior Nuclear Licensing Engineer

E. Gallion, Shift Supervisor

S. Johnson,. Manager, Site Nuclear Services

B. Marckese, Electrical Engineer

P. Mckee, Director, Nuclear Plant Operations

L. Moffatt, Supervisor, Nuclear Safety

R. Murgatroyd, Superintendent, Maintenance

B. Muzzi, Senior I&C: Engineer

V. Roppel, Manager, Nuclear Plant Maintenance

W. Rossfeld, Manager, Nuclear Compliance

H.-Tillman, System Protection and Control Technician (CR-1 and 2)

E. Welch, Manager Nuclear Electrical /I&C Engineering Services

R. Widell, Director, Nuclear Operations Site Support

M. Williams, Nuclear Regulatory Specialist

A list of acronyms and initialisms used herein is provided at the end of

this report. Figures I and 2 outline the Crystal River off-site power

supplies.

2.

Overview and Background Information

An alert was called by the licensee on June 16, 1989, when a LOSP occurred

during the ascension of power for Crystal River Unit 3.

CR-3's ES buses

were being sepplied with power from CR-3 Start-up transformer.

The LOSP

was the result of a personnel error and a failure of a Fault Detector

Relay.

The FSAR states that the preferred off-site power source for CR-3's ES

buses is the Unit 3' Start up transformer and the alternate and independent

source is the Units 1 and 2 (Fossil Units) Start-up transformer via a

direct cable connection.

Transfer to the alternate source is by manual

operations. The on site Emergency Diesel Generators assume the ES bus

loads in the following manner:

a.

Manually if the ES bus voltage has not failed.

b.

Automatically if the ES bus voltage fails to approximately 55 percent

of nominal ES bus voltage or degrades to approximately 90 percent of

nominal ES bus voltage. The former involves a relay scheme were two

out of three relays are activated and the later involves a relay scheme

were three relays out of 3 relays are activated.

The NRC's 1974, SER states the CR-3 off-site power is from two separate

feeders emanating from' different breaker-and-a-half configuration bays

in the 230KW switchyard.

These power source are connected to two separate

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Start-up transformers of which one is assigned to CR-3 and the other is

shared between CR-1, 2, and 3.

The shared Start-up transformer, feeder

lines, and associated breakers have sufficient capacity to handle all

required load demands from the 'three units. .The TS for CR-3 states that-

these' two physically independent circuits between the off-site transmis-

sion network and'the.on-site ES bus are to be available for CR-3, when in-

operating Modes 1, 2, 3, and 4 (as defined in the TS). The TS also gives

requirements that must be fulfilled when the conditions are not met.

The licensee issued a Licensee Event Report dated May 9,1989, that'

described an event on April 9,1989, -where it was. determined ' that the

alternate power source could not supply power to CR-1, 2, and 3 for all

operating configurations. _ The event happened when CR-3 was .in a safe shut

down condition with minimal decay heat and with all three. units being

supplied power from the alternate power source. A 3500 HP pump was started

in Unit I and a voltage drop occurred on the ES buses (degraded voltage

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on ES buses). The Emergency Diesels Generators started on degraded voltage-

signals. None of the safeguards' equipment was lost in this event. As a

result of this event administrative controls were implemented to assure

that the loads on CR-3's alternate off-site power source were regulated

to satisfy the TS requirements for Crystal River 3 when it was in modes 1,

2, 3, or 4.

In addition, a plant modification was made to annunciate any

overloading conditions of this alternate power source. The annunciation

is made in CR-3's control room so that operators can take the appropriate

TS actions,

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3.

Response to the Event

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a.

Description of the Sequence of Events, June 16, 1989

0255

Could not receive control rod 100% Out Limit or Group Out

Limit for Control Rod 5-3, complied with the actions of

TS 3.1.3.3.

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0315

Inserted all Regulating Rods back into the core and ensured

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a 1 percent Shutdown margin. Entered Mode II and initiated

maintenance on Axial Position Indication for Rod 5-3.

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Exited the actions of TS 3.1.3.3.

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0800

Completed surveillance testing for Control' Rod 5-3.

0915

Unit 2 Start-up in progress, loading of the Units 1 and 2

Start-up Transformer exceeds 1500 KW; therefore, that

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source of offsite power is inoperable enter TS 3.8.1.1

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(72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> LCO).

0945

Units 1 and 2 Start-up Transformer loading is reduced to

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<1500 KW, exit actions of TS 3.8.1.1.

1110

Enter Mode II

1203

Enter Mode I

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1325

Breaker 1691 opens due.to an inadvertent test of the fault

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protection on the Brookridge'230 KV line. A fault detector

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relay sensed a failure of breaker 1691 to'open (the breaker

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- did operate successfully), causing. breaker 1692 to open.

This action de-energized the Unit 3 Start-up Transformer

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causing a ' loss of power to all . AC. buses. . A reactor trip

occurred and the EFW pumps started to supp.ly feed to the

Steam' Generators.

EFP-1 : tripped on ES bus undervoltage,

the Emergency-Diesel Generators started and supplied power

to the ES busses. EFP-1 did not sequence back on the bus;

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however, thel operators wert able to manually start the

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A

pump. An unexplained RPS trip was received on one channel-

for the flux / delta flux / flow trip and the vital inverters

did not indicate an alternate source was available.

1330

When the emergency classification of the " Alert" was

declared, the proper notifications were_ made and the TSC

was manned. The conduct of business in the TSC was profes-

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sional and timely.

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1431

Breaker 1692 reclosed; Unit 3 Start-up Transformer

re-energized.

1432

Breaker 1691 reclosed.

1445

"A" ES Bus paralleled to the Units 1 and 2 Start-up Trans-

former.

1447

"B" ES Bus paralleled to the Unit 3 Start-up Transformer.

1449

4160V Unit Buses are energized providing power to the

secondary plant.

1500

All 4160V Buses have been- restored, crews are restoring

equipment and instrumentation as required. The Emergency

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Diesel Generators-are still running, an RCP would be' started

when all attendant instrumentation had been restored. The'

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cause of the loss of power-is _known to be a loss of the

Brookridge line and subsequent failure of a fault sensing

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relay.

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1620

Unit 2 tripped causing a loss of Units 1 and 2 Start-up

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Transformer,

"A" ES loads are transferred to the Unit 3-

Start-up Transformer,

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1709

"B" RCP is started returning the RCS to forced circulation.

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All RCS parameters indicate satisfactory after the pump

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start..

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1712

"C" RCP is started.

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1715

Based on the successful start of two RCPs the event is-

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downgraded from an Alert to a NOVE.

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1728

Verification Procedure VP-580 has been completed, all

parameters indicate normal.

Intent is to de-classify

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emergency.

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1732

Breaker 1691 has been closed back in restoring normal

breaker alignment to the Start-up Transformer.

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1735

Based upon successful completion of VP-580, NRC conference

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call and determination of the root-cause, the NOUE has

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been terminated.

b.

Operator / Plant' Response

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The reactor was at 12 percent power with the main turbine latched end

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rolling at 400 rpm. The reactor tripped and an automatic initiation

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of EFW and Emergency Diesel Generators occurred. The loss of all

RCPs placed the RCS in natural circulation. The operators responded

by performing the immediate operator actions of the Emergency

Operating Procedures (AP-580, 530, 450 and 770). Natural circulation

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was verified on "A" OTSG; However, due to an instrument malfunction,

natural circulation could not be immediately verified on the

"B"

0TSG.

Letdown was terminated due to the filter isolation valves

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closing (letdown would be re-established later in the transient).

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Due to the cool down from EFP-2, OTSG steam pressure dropped to ~450

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psi at 1400 hrs. Manual Pressurizer and Makeup Tank level control

were established. The plant was stabilized at ~1950 psi at a cool

down rate of ~30 degrees F/hr.

The plant was returning to service

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from an outage; therefore, the decay heat load was minimal.

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operators attempted to minimize the steam flow and subsequent cool

down by isolating non-essential equipment, e.g. , closing the Main

Steam Isolation Valves. During the event Hot Leg temperatures ranged

from 537 degrees F. at 1400 hrs. to 440 degrees F. at 1555 hrs,

Cold Leg temperatures ranged from 461 degrees F. at 1400 to 419

degrees F. at 1555 hrs.

The loss of the Unit 3 Start-up transformer was attributed to a relay

technician who had inadvertently depressed a fault test pushbutton

which cleared the Brookridge line, additionally, a fault sensing

relay failed to sense the opening of breaker 1691 causing the relay

to initiate the opening of breaker 1692.

Crews were dispatched to

determine the cause of the Unit 3 Start-up Transformer failure.

Also, the centrol room operators dispatched personnel to survey the

Diesel Generators and restore power when available.

The licensee

elected to stabilize the grid by waiting on Unit 2 to complete a

Start-up before restoring off-site power through the Units 1 and 2

Start-up transformer. After this source of power was restored, the

operators placed one division of ES on the Unit 3 transformer and one

division of ES on the Units 1 and 2 transformer.

Eventually, all

loads were transferred to the Unit 3 transformer, two RCPs were

started establishing forced circulation and the event terminated.

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Operator response to this event was satisfactory. The operators were

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aware of electrical sources which had failed, and those available to

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them.

The control room personnel dispatched personnel as necessary

to take local actions as appropriate.

Procedure actions appeared

adequate in providing guidance to the operators in responding to this

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event,

c.

Two weaknesses were noted during the recovery from this event:

(1) The root cause analysis of the start failure of the motor driven-

emergency feed pump was less than adequate. It was later, after

restart, shown by test that the failure of' an untested relay -

string prevented the automatic start of EFP-1.

The assumption

was that the malfunction of a time delay was the cause of the

start failure.

(2) Lack of string testing of the start logics contributed to the

failure to recognize the failure of the AJ relay in addition to

the time delay relay. Also the lack of string testing of this

logic string contributed to the existence of a relay that was

not surveilled in the automatic start logic of a safety related

component.

4.

Specific Problems Discovered as result of LOSP on June 16, 1989,

a.

Loss of Start-up Transformer for CR-3

The non-nuclear switch yard personnel were checking the carrier

signals of the Brookridge transmission system from metering cabinets

in CR-1 and 2 (fossil units) control room areas.

This would

normally have no effect on the transformer configuration and switch

yard breaker line up that was supplying power to _ CR-3 Start-up

transformer. However, a relay technician inadvertently hit a test

circuit switch (a Push Button [PB) that is not normally used) that

simulates a fault on the system's transmission lines and two

switch yard breakers opened (1690,1691).

One of these breakers

(1691) is in parallel with another breaker (1692) that supplies

power to CR-3 Start-up Transformer.

The opening of (1690, 1691) two breakers would- not have caused the

loss of CR-3 Start-up transformer since breaker 1692 should have

remained closed. However, a fault detector relay, which should have

indicated that breaker 1691 was open, failed and indicated that

breaker 1691 was still closed. As a result the next breaker, 1692,

automatically opened to clear the non-existent fault. This isolated

CR-3 Start-up transformer and CR-3 had a LOSP event. The Emergency

Diesel Generators started and assumed the ES loads.

The relay that failed in the above event was last calibrated in 1986,

and was found to be satisfactory. The periodicity of calibration for

this relay is on a normal two year cycle. It was not calibrated when

its two year period became due because of more urgent work.

The relay

was removed after the event, checked out and re-cailibrated success-

fully and returned to service.

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These switchyard relays are scheduled for replacement by a solid

state system that is more reliable.

The replacement is anticipated

to occur during .the next CR-3 refueling.

Since the PB circuit is

only accessible by a hinged cover.that is fastened by screws opposite

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the hinced end (The cover also has to be removed to check the carrier

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signals), it is considered by the' licensee'that rio additional protec-

tion is needed for the PB.

In the : interim, before .the solid . state

system is installed, the r'elay department is considering the permanent-

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disabling of the PB. switch since they are not used. This event was

caused by personnel error and a faulty relay.

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b.

Emergency Feedwater Pump (EFP) One Failed to Start Automatically

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The event caused the. motor driven Emergency Feedwater Pump EFP-1 to

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receive an automatic start signal; it tripped :off of . the line

shortly after initiating and failed to restart automatically when

the Emergency Diesel Generator (3A) assumed the ES loads.

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After the Diesel Generator's ' output . breaker closes, one circuit is

activated that energizes a relay that has a contact in a string for

the automatic starting circuit - for EFP-1.

The contact in this

starting string should have closed in five seconds after the DG's

output breaker closed and EFP-1 should have started automatically..

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The operator noted this discrepancy and manually started the pump by

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positioning the switch in the control room.

The action taken after the event showed the following:

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(1) The relay with a five second time delay for. closing a contact was

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checked. This check showed that the contact did not-close. The

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relay was taken to the shop for further bench testing. In the

shop it worked as designed.

It was tested and cycled several

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times in the shop and was placed back in the' circuit. It was

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tested in the installed configuration and worked as designed.

It was cycled several times in its installed configuration and

worked each time. - It was considered that a poor electrical

connection may have cause the relay to fail during the LOSP

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event.

(2) The relay had been satisfactorily tested on October 19, 1988.

The test at that time was in accordance with Crystal River's

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SP 137, Engineered Safeguards Actuation System Time Delay Relay

Calibration.

The installed tests, mentioned in 1. above, were

the same, or similar, to this test.

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(3) As a result of NRC inquiries concerning the testing of the

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er. tire string for an automatic starting circuit for EFP-1, NRC

was notified on June 23, 1989, that the AJ relay, which also

provides a close contact in the EFP-l's string for automatic

starting, has not been tested. The AJ relay was subsequently

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tested and found to be defective.

Therefore, even if the five

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second-time-delay relay had worked properly, the EFP-1 would

not have started because of an open contact up stream of the

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time-delay

relay.

This

is

considered to

be a violation

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identified as

50-302/89-17-01,

Inadequate Testing to Prove

Operability of a String for the Automatic Starting of EFP-1.

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c.

Synchronizing Lights for Inverters A, B, and C were noted to be off

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after the LOSP Event

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On Wednesday (June 14, 1989), prior to the event, the licensee was

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performing the SP-417 and transfer switch VB-XS-1A transferred to

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alternate supply which was- not energized.

VA-XS-1A remained in the

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correct position.

The transfer switch changes positions when it

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senses an under voltage or over current condition.

Extensive checks

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were performed to determine why this anomaly occurred and no circuit

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discrepancies or erroneous set points could be found. As a result of

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the LOSP event 'on Friday (June 16, 1989), and the anomaly indicated

above, the inverter panels were checked shortly after the LOSP event.

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The transfer switches functioned as designed, however, it was

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observed that the synchronizing lights for inverters A, B, and C were

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not on.

The D inverter was on. The lights should indicate that

power is available on the vital bus.

In that the vital bus was

energized by the DG assuming the ES bus loads, the lights should

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have been on.

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It was observed that the lights did come on when the DG speed was

increased during the paralleling and synchronizing operations to put

the ES bus back on switch yard power.

The inverter lights are set

for a frequency of 59.3 to 60.7 cycles per second.

They were

re-adjusted to as close to the mid-band setting as possible. SP 417

in this area was repeated and the inverter circuitry functioned as

designed. The DG high speed limit was set at the high end of the

specification (900 RPM) and a MAR is being considered to increase this

high speed limit to 905 RPM.

5.

Acronyms and Initilism

CR

Crystal River

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DG

Diesel Generator

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EFW

Emergency Feedwater

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EFP

Emergency Feedwater Pump

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ES

Engineered Safeguard

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HP

Horsepower

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KV

Kilo-Volt

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KW

Kilowatt

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LCO

Limiting Condition for Operation

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LOSP -

Loss of Off-Site Power

MAR

Modification Approval Record

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NOUE -

Notification of Unusual Event

OTSG -

Once Through Steam Generator

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PB

Push Button

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RCP

Reactor Coolant Pump

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RCS

Reactor. Coolant System

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RPM

Revolutions per minute

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SER

Safety Evaluation Report

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Surveillance Procedure

SP

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TS

Technical Specifications

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TSC

Technical Support Center

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ROI 2210 REY. 1, ENCLOSURE 4

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INSPECTION RESULTS AND SALP INPUT

Sumary of Inspection Results

Facility

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AREAS INSPECTED

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NEW VIOLATIONS (SL), DEVIATIONS (DEV), OR OTHER NEW ITEMS (UNR & IFI)

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STATUS OF PREVIOUS ENFORCEMENT MATTERS AND OTHER ITEMS

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MODULES INSPECTED, PERCENT FOR EACH UNIT (IF NOT 1001, LIST NUMBER OF LINE

ITEMSCOMPLETED)

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INSPECTOR OBSERVATIONS AND AREAS OF CONCERN

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SALP EVALUATION

Complete one SALP evaluation for each functional area inspected.

Complete.

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during inspection if time permits.

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Key: 0 - Not ins;Neted; 1 - Above average; 2 - Average; 3 - Below average

..

. EVALUATION CRITERIA

ASSESSMENT

1.

Management involvement in assuring quality

0 1@3

2.

Resolution of technical issues from a safety standpoint

0 1 @3

,

3.

Responsiveness to NRC initiatives

j 1 2 3

4.

Enforcement history

$1 2 3

5.

Reporting and analysis of reportable events

@1 2 3

j

6.

Staffing (including management)

@1 2 3

7.

Training and qualification effectiveness

@1 2 3

AREA INSPECTED

OVERALL ASSESSMENT

0 1 2 3

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