ML20245F547

Insp Rept 50-416/89-14 on 890415-0519.Violations Noted.Major Areas Inspected:Operational Safety Verification,Maint Observation,Surveillance Observation,Esf Sys Walkdown,Test Piping Support & Restraint Sys & Startup from Refueling

ML20245F547
Person / Time
Site:	Grand Gulf
Issue date:	06/05/1989
From:	Cantrell F, Christensen H, Mathis J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20245F533	List: ML20245F529 ML20245F538 ML20245F547
References
50-416-89-14, NUDOCS 8906280167
Download: ML20245F547 (17)

See also: IR 05000416/1989014

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UNITED STATES

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NUCLEAR REGULATORY COMMISSION

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REGION 11

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101 MARIETTA ST., N.W.

ATLANTA, GEORGIA 30323

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Report No.: 50-416/89-14

Licensee:

System Energy Resources, Inc.

Jackson, MS 39205

-Docket No.: 50-416

License No.: NPF-29

Facility Name: Grand Gulf Nuclear Station

Inspection Conducted: April 15 through May 19, 1989

Inspectors:

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H. O. Christensens

ipVResidentInspector

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J. LT Mathis, Residentlyegtor

Date Signed

Approved by:

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F.1.'Cantrell Secti6 /4hief.

D' ate / Signed

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Division of Reactor Frojects

SUMMAP,Y

Scope:

The resident inspectors conducted a routine inspection in the areas of

operational safety verification; maintenance observation, surveillance

. observation, engineering safety features (ESF) system walkdown, test piping

support and restraint system, startup from refueling, action on previous

inspection findings, and reportable occurrences.

The inspectors conducted

backshift inspections on April 28, 29 and May 6, 11, 1989.

Results:

Within the areas inspected two violations were identified involving failure to

follow a radiation protection procedure and the RWP during the removal of a

contamination boundary (paragraph 3.d.), and for an inadequate procedure which

contributed to a loss of feedwater control and a reactor scram (paragraph 3.e.).

One non-cited violation was identified for failure to take adequate corrective

action to prevent thermal binding of a safety related feedwater isolation valve

(paragraph 3.d.).

These violations do not appear programmatic in nature.

8906280167 890613

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-The plant completed a 43 day refueling outage which was w' ell planned,- scheduled

and managed. However, weaknesses were noted in the control of contractors in the

~ health physics area.

During the power ascension phase the plant _ experienced

several equipment problems that required a reduction in power and two shut-

downs.

During one of the plant shut downs, the' plant scrammed on low water

level. The major contributor to the reactor scram was personnel error.

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REPORT DETAILS

1.

Persons Contacted

Licensee Employees

J.G. Cesare, Director, Nuclear Licensing

W.T. Cottle, Vice President of Nuclear Operations

• D.G. Cupstid, Superintendent, Technical Support

• L.F. Daughtery, Compliance Supervisor

.

• J.P. Dimmette, Manager, Plant Maintenance

S.M. Feith, Director, Quality Programs

• C.R. Hutchinson, GGNS General Manager

R.H. McAnulty, Electrical Superintendent

A.S. McCurdy, Technical Asst., Plant Operations Manager

• L.B. Moulder, Operations Superintendent

J.H. Mueller, Mechanical Superintendent

J.V. Parrish, Chemistry / Radiation Control Superintendent

J.L. Robertson, Superintendent, Plant Licensing

• S.F. Tanner, Manager, Quality Services

L.G. Temple, I & C Superintendent

F.W. Titus, Director, Nuclear Plant Engineering

• M.J. Wright, Manager, Plant Support

• J.W. Yelverton, Manager, Plant Operations

Other licensee employees contacted included technicians, operators,

security force members, and office personnel.

• Attended exit interview

NRC' Personnel

L. Trocine, Project Engineer

2.

Plant Status

Unit 1 began the inspection period in refueling outage number three and

completed the outage in 43 days.

The unit started up on April 28, 1989,

and synchronized to the grid on April 29, 1989.

During power ascension

the plant experienced several operational problems which included one

power reduction, one reactor scram and two planned unit shutdowns. At the

end of the inspection period the unit was in cold shutdown due to

vibration problems on recirculation pump B.

3.

Operational Safety, (71707)

The inspectors were cognizant of the overall plant status, and of any

significant safety matters related to plant operations.

Daily discussions

were held with plant management and variocs members of the plant operating

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staff.

The inspectors made frequent visits to the centrol room.

' Observations included the verification of instrument readings, setpoints

and rec'ordings, status of operating systems, tags and clearances on

equipment controls and switches, annunciator alarms, adherence to limiting-

conditions for operation, temporary alterations in effect, daily journals

-and data sheet entries, control room manning, anc: access controls. This

inspection activity included numerous informal discussions with operators

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and their supervisors.

On a weekly bases selected engineered safety feature (ESF) :;ystems were

cor> firmed operable.

The confirmation was made by verifying that

accessible valve flow path alignment was correct, power supply breaker and

fuse status was correct, and instrumentation was operational.

The

following systems were verified operable:

ADS, LPCS, LPCI A, and SSW A.

Additionally, the inspectors conducted a modified system walkdown on the

emergency electric power system using the Grand Gulf probabilistic Risk

Assessment Based Inspection Plan as a guide.

General plant tours were conducted on a weekly basis. Portions of the

control building, turbine building, auxiliary building and outside areas

were visited.

The observations included safety related tagout verifica-

tions, shift turnovers, sampling programs, housekeeping and general plant

conditions, the status of fire protection equipment, control of activities

in progress, problem identification systems, containment isolation, and

the readiness of the onsite emergency response facilities.

The inspectors observed health physics management involvement and awareness

of significant plant activities, and observed plant radiation controls.

Periodically the inspectors verified the adequacy of physical security

controls.

The inspectors reviewed safety related tacouts, 892561 (SBLC)

and 892585 (ADHR) to ensure that the tagouts were properly prepared, and

performed.

During a routine tour of the 166' elevation of the turbine building on

April 24,1989, the inspectors noticed two contract carpenters removing a

fence on the southeast side of the turbine generator.

This fence

constituted a boundary for a contaminated area.

When informed by the

inspectors, a HP technician stopped work and had the the area surveyed.

The area

was used for contaminated equipment and tools storage.

The

removal of the contaminated area boundary was not coordinated with HP

prior to the work being done.

Neither worker wore PC's as required by

RWP.

Radiological Deficiency Report 89-04-017 was written to document

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this incident.

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Technical Specification (TS) 6.8.1 requires that written procedures be

established, implemented and maintained covering the activities

recommended in Regulatory Guide (R.G) 1.33, Revision 2, February 1978.

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R.G. 1.33 recommends procedures for Control of Radioactivity.

Section

6.1.1 of Radiation Protection Procedure 08-S-01-21, Radiological Practices

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for Controlled Areas,' requires that all- radiological postings', signs and'

barriers will be strictly. complied with and will not be moved or bypassed'

unless.specifically authorized by HP and requires that RWP's be followed.

Contrary to above, contractors removed a ' contaminated area boundary

without receiving HP authorization and.without following the protective-

clothing requirements.of the RWP.

This will be documented as violation

89-14-01.

.The ' inspectors verified that the following ECCS manual injection valves.

were in their locked open position; HPCS, LPCS, LPCI B and LPCI C.

Tne inspectors have noted that senior plant managers make routine tours

to the plant and the control room.

The inspectors reviewed the activities associated with the below listed

events.

a.

On April 17, 1989 at 2:15 p.m..a control room operator found the LPCI A

injection valve, E12-F042A, open.

RHR A system was in operation, in the

shut down cooling (SDC) mode. The.open valve had no adverse effect on

shutdown cooling and the valve was immediately closed.

A review of

surveillance and interviews with technicians and operators'~ failed to

identify'a probable cause. The shift turnover walkdown of the 1H13-P601

panel during the morning confirmed that the valve was closed.

The

licensee suspects the cause of the mispositioned valve to be operator

error.

An operator may have manipulated the wrong handswitch while

throttling valves on. the SDC loop A for temperature control.

The

operations management issued a memorandum to the' shift operators

concerning attention to detail,

b.

On April 20,1989,-with the plant in mode 5, the control room operator

discovered that RHR A pump had tripped while operating. in the shut .

down ' cooling mode.

A review of the event indicated. that the pump

tripped during the reinsta11ation of a DC power fuse to an optical

isolator circuit.

The reinsta11ation of the-fuse caused a voltage

spike, which energized the optical isolator and tripped the RHR pump.

.The. pump trip was reset and restarted at 5:51 p.m.

The reactor core

wm without flow for approximately 20 minutes, there was no core;

temperature increase during this period.

The licensee has in place

procedures to address inadequate decay heat removal and the operators

were aware of the need to maintain a shutdown cooling mode.

c.

On May 3, 1989, when the operator tried to open the FCV A recircula-

tion pump valve (FCV F060A), the position indicator did not respond

properly when the recirculation pumps were in fast speed.

This

problem did not exist when the pumps were in slow speed. On May 4,

1989, power was reduced from approximately 50% to 5% to allow entry

into the drywell for rework on FCV F060A, and the turbine generator

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was taken off line.

MWO 193001 was written for troubleshooting

and monitor the work on the recirculation flow control valve A Rotary

Variable Differential Transformer (RVDT) N026A. The RVDT is used to

provide a feedback signal for determining the position of the FCV.

An inspection indicated that the flexible coupling of the RVDT was

completely compressed which caused binding around the flenible

coupling.

The yoke assembly and RVDT were removed, new ones were

installed and calibrated.

When the work was completed the plant

proceeded to increase power.

The retest plan was to increase power

enough to shift to fast speed on the recirculation pump and monitor

FCV indications.

While in slow speed the recirculation pump did.not

experience indication problems.

d.

The plant power was increased to approximately 22%, and the turbine

generator was synchronized to the grid.

The A feedwater isolation

valve, (Q1821F065A) would not open.

The motor operator initially

tripped on thermal overload.

Operation personnel entered the steam

tunnel to manually open the valve. The handwheel was turned approxi-

mately 20 turns which was enough to free the stem.

When the valve

was subsequently stroked, with the motor operator, the stem would

rotate to the open position, but flow indication did not exist. The

plant was returned to cold shutdown to disassemble the valve. MNCR

214-89 was initiated for evaluation of Q1821F065A valve for thermal

binding.

The valve was reworked under MWO M93291.

Upon disassembly

of the va've, the stem was found separated from the disc, and the

" ears" at the bottom of the valve stem were found broken. The root

cause tvaluation determined that the component failure was a result

of cracks which originated on the bottom of the valve stem ears.

These cracks resulted from excessive closing force caused by thermal

growth of the valve and stem.

The cracks weakened the ears on the

stem such that the forces used during attempts to manually open the

valve separated the stem from the disc. The valve vendor representa-

tive stated that this type of failure could not have resulted from

over-torquing by the motor operator.

The representative also

stated, that the unique conditions associated with the operation of

this valve creates very high forces due to heating of the valve stem

after the valve has been closed.

During shutdown operation, the RWCU

flow through the A feedwater line causes heating of the valve disc

and stem.

Because the stem is rigidly bound when closed, subsequent

heating of the stem creates very high stresses due to the restrained

thermal expansion.

These stresses are typically much higher than

those capable of being developed by the motor operator.

The valve

stem was replaced and a LLRT and MOVAT were performed. Actions to

prevent recurrence has been outlined in MNCR 214-89, which include

rewriting the operating procedure to preclude the thermal conditions.

On September 12, 1988, a similar problem occurred to the same valve

Q1821F065A.

The valve would not open electrically nor mechanically.

It was believed that the valve stuck in the seat due to thermal

condition.

During attempts to open the valve mechanically, the

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key on tthelinside - gear box of the handwheel shaft sheared.

The

following components were replaced due 'to the shearing of-'the key;

clutch housing assembly, handwheel shaft, hand wheel gear, handwheel

~ key,: motor Edriven 1 gear and declutching spring. .

The licensee

conducted discussions with : the valve manufacturer and ruled out '

thermal binding..

They felt the problem was attributed to. the-

actuator torque switch being set'too high.

During RF03 a MWO was-

written to reduce the torqueL switch setting and to M0 VAT the valve.

However, the Eroot cause of the valve' failure on May 5,1989 was

determined'to be. thermal binding.

Failure to ensure the cause of the condition, thermal binding, is a-

violation of 10 CFR 50, Appendix B, Criterion XVI. The licensee has

.taken action to preclude repetition. The violation is.not being cited-

because the criteria specified .in Section V.A of.the enforcement

policy were satisfied, NCV 89-14-02.

f.

On May 4,1989, at approximately 10:40 a.m. the Division 3 Diesel

Generator auto started when a voltage fluctuation occurred as a

result of adverse weather conditions.' The operators ran Division 3

DG loaded for one hour before returning to offsite power.

e.

On May'5, 1989,.during the power reduction to cold shutdown to allow

investigation' of the feedwater isolation valve problem, the plant

scram on' low reactor vessel water level (level 3).

Feedwater flow

was'through the startup. level control valve N21-F513. The plant was

experiencing difficulty in maintaining reactor vessel water level. in

its normal . band.

The startup level control valve was closed and the

isolation valve N21-F001 was closed in. preparation for directing flow

through the startup level control bypass valve N21-F040.

With both

valves closed, the reactor water level continued to rise._ Operators

attempted to align RWCU blow down flow to the condenser to aid in

establishing level control.

The A reactor feed pump turbine (RFPT)

tripped on level 8 (+53.5").

When the high water level cleared an

operator attempted to reset the A RFPT.

No increase in feed pump

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discharge pressure was observed by the operator. An attempt was made

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to start the. B RFPT, but failed because the steam supply valves

(N11-F012B and N11-F014B) were closed.

When reactor vessel water

level decrease to 20", RCIC was manually initiated and CRD flow

manually increased to 100 gpm. The RCIC flow provided approximately

0.45 mlb/hr feed flow.

The steam flow rate was 1.4 mlb/hr therefore

reactor water level continued to decrease to the scram setpoint of

11.4".

Reactor vessel water level decreased to approximately 2" and

then recovered.

The MSIVs were closed to limit the cool down rate

and RWCU blowdown and CRD flow was used to maintain reactor water

level control. The post trip investigations by the licensee revealed

the following:

The initial increase in the vessel level was caused by either

one or both of the high pressure feedwater heater string outlet

valves (N21F009A/B) being slightly cracked off their seat. This

partially bypassed the startup level cuntrol function.

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During'the feedwater/ level transient the operators were reducing

. reactor power by insertion of control rods. This. power reduction

caustd a feedwater. flow / steam flow mismatch causing a more rapid

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rise in reactor level. Control rod -insertion did not'stop until

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approximately three minutes'after'the.RFPT trip. -This evolution

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contributed to rate of increase and - the erratic behavior of~

vessel level prior to the level 8. trip.

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Once the .RFPT A trip' on leve1L 8 was cleared, the turbine was

. reset, but would not come up in speed. -The turbine may-be reset

once all trips are cleared, but the' governor valve .cannot be

re-opened until the manual speed changer (MSC) is run completely

'to the low speed stop.-'In this' case,.the. turbine was. reset, but'

the MSC had not been run completely to the low speed stop. The.

simulator does .not allow the turbine to be reset until the MSC

has been run completely to the low speed stop.

.The B RFPT could not be brought on line because it was manually.

valved out. The B pump had been run the night before, but it had

been secured per the SOI rather than being restored to a standby

status.

The shift superintendent changed reactor operators in the middle

of the event, which may have contributed to the inability to

reset the RFPT.

Technical Specification 6.8.1.a states written. procedures shall be

-established, implemented and maintained covering applicable' procedures

recommended in Appendix A of Regulatory. Guide 1.33, Revision 2,

February 1978.

Regulatory. Guide 1.33 Revision 2, Appendix A states

that. instructions for energizing, filling, venting, draining, startup,

shutdown, ' and changing ~ modes of operation should be- prepared, as

appropriate, for the.feedwater system.

501 04-1-01-N21-1, Feedwater

System,'provides direction for the operation of.the-feedwater system;

however, the 50I did not adequately address how to reset the RFPT.

The inadequate procedure for resetting the RFPT contributed to. a

reactor scram.

This will be identified as violation 89-14-03 for an

inadequate procedure.

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On May 8,1989 at approximately 9:19 a.m., RWCU system isolation

occurred after operators shifted from "prepump" to "postpump" mode of

RWCU lineup.

The reactor was in hot shutdown with pressure approxi-

mately 27 psig.

The operators attempted to stabilize delta

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flow by securing the RWCU pump and closing the filter demineralized

bypass valve (G33F044).

This should have stopped all RWCU flow;

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however, the inlet flow still indicated 150-200 gpm. When the delta

flow 45 second bypass timer timed out, all Group 8 containment

isolation valves closed.

Alternate leak detection methods such as

room temperature and drain sump levels showed no actual leak had

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. occurred.

The RWCU system was restored to serviceLin'the "prepump"

mode at 9:40 a.m.. in order to reestablish blowdown to the condenser.

A number of. RWCU isolations occurred at the Grand Gulf Nuclear

Station in 1987 and 1988.

Inspector Followup Item 88-19-03.was

identified in September 1988 as a- result of ai RWCU isolation. to

followup- the corrective action associated with the. event

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(LER 88-04-01)'.

LER 88-04-01 supplemental .' corrective ' action stated

that SERI.would install la' separate keylock bypass switch to bypass-

the n delta flow isolation signal during anticipated RWCU system

operating transients to avoid spurious isolations.

Installation of

the bypass' switch was scheduled during the third refueling outage;

however, additional problems were identified with the proposed design

and installation' was ' put ~ on hold.

The licensee is continuing to

. pursue:a means to preclude unplanned RWCU isolation.

h..

On May -11, -1989 at 1:30 p.m., the B recirculation pump experienced

high vibrations.

The licensee continued to monitor the pump over a-

three hour period and noted that the vibration amplitude increased

from 17 mils to 31 ~ mils at the pump coupling and from 5 mils to 11

mils at the motor. A normal vibration amplitude is less than 5 mils.

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Reactor, power was reduced and the recirculation pump shifted to slow

speed.

The shaft. vibration decreased to 11 mils at the pump coupling

and 5 mils at the motor. On May 13,1989, at 7:55 p.m. the plant was

shutdown to investigate the recirculation pump vibration problem.

The planned outage is for 24 days if both pumps are opened to inspect

and repair.

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Maintenance.0bservation(62703)

During the report period, the inspectors observed portions of the

maintenance activities listed below.

The observations included a review

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~of the MW0s and. other related documents .for adequacy;- adherence to

procedure, proper tagouts, technical specifications,. quality controls, and.

radiological controls; observation of work and/or retesting; and specified

retest requirements.

MWO

. DESCRIPTION

E84706

Capacity discharge test on B0P battery

EL2693

Lube RPS motor generator set

EL2694

MEGGER RPS motor generator set

F90376

SSW basin siphon pipe flange

193001

' Troubleshoot FCV F060A/RVDT unit

'I93371-

Troubleshoot RFP B speed control

M85443

Disassemble valve P71F300 and actuator

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M92499

Adjust the RCIC overspeed trip mechanism

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M93291

Investigate feedwater isolation valve F065A

193585

Temperature indication and switch for SBLC

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No violations or deviations were identified.

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5.

SurveillanceOb'servation'(61726)

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The inspectors observed the performance'of' portions of.the surveillance

-listed below.

The observation included a review of the procedure for

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technical adequacy, . conformance to ' technical specifications and LCOs, .

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_ verification of test instrument calibration, observation of all or part of

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.the actual surveillance, removal and return to service of the system or-

component, . and review; of - the data for _ acceptability based 'upon the

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acceptance criteria.

06-0P-1E12-Q-0006.. Revision 20, LPCI/RHR Subsystem B MOV Functional Test

06-0P-1E12-R-0022, Revision 21, RHR Containment Spray Initiation. Logic

Functional Test

06-RE-SC11-V-0402, _ Revision 26, Control Rod Scram Testing

06-IC-1C51-W-0006, Revision 25, APRM Calibration

06-IC-1E30-M-0003, Revision 22, Suppression Pool Level Wide Range

Functional Test for Channel B.

No violations or deviations were identified.

6.-

En','neered Safety Features System Walkdown (71710)

._The inspectors. conducted a complete walkdown on the accessible portions of

.the ADS.

The walkdown consisted of the following:

confirm that the

system lineup procedure matches the ' plant drawing and the as-built

. configuration;

identify equipment condition,and items that might degrade-

plant- performance; verify that valves in the flow path are in correct

positions.' as required by procedure and that local and remote position

indications are. functional; veri.fy the proper breaker position at local

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electrical boards- and indications on control boards; and verify that

instrument calibration dates are current.

The inspectors walked down the system using system operating instruction

'04-1-01-B21-1, Revision 28. Nuclear Boiler System and P&ID M-1077C,

Revision 28.

The operating instruction electrical lineup checksheet,

attachment III, component description differed from the actual equipment

label'for the following breakers:

. Breaker No.

Component Description

Breaker Label

72-11A23

125 Vdc ADS Logic

PGCC PNL

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Div. I

1H13-P628

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72-11B34

125 Vdc ADS Logic

PGCC PNL

Div 2

1H13 -P631

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52-1P66102

ADS STATUS LIGHT

Control Room PGCC Panel

Power, Div. 1

1H13-P601 Automatic

Depressurization Sys+em.

52-1P56101

ADS STATUS LIGHT

Control Room PGCC

Power, Div. 1

Panel 1H13-P601 Automatic

Depressurization System.

The ADS annunciator panels were reviewed using the system operating

instruction, Attachment IV, System Alarm Index.

The following alarm was

not on the alarm index.

Alarm Name

Panel

GRID

SRV/ ADS VLV

1H13-P601-19A

A5

OPEN/DISCH LINE

PRESS HI

The following deficiencies were identified during the system walkdown:

Relief Valves for AIR Accumulators A-003D and A-004D were not labeled.

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The material condition of the system appeared good.

All valves were

aligned in accordance with the 501.

The inspectors conducted a walkdown of the accessible portions of the

standby liquid control system by using system operating instruction

04-1-01-C41-1, Revision 24, Standby Liquid Control System, and P&ID

M-1082, Revision 21, Standby liquid Control System Unit 1.

The component description on the operating instruction electrical lineup

check sheet, Attachment III of the system operating instruction, differed

from the actual equipment label for numerous breakers as follows:

Breaker No.

Component Description

Actual Breaker Label

52-1P56107

120 Vac to 1H13-P601

Control Room PGCC Panel

1H13-P601 Standby Liquid Control

System.

52-1P56120

SLC Tank Level Alarms

Control Room PGCC Panel

1H13-P632 Leak Detection System.

52-1P66105

120 Vac to 1H13-P601

Control Room PGCC Panel

1H13-P601 Standby Liquid Control

System,

52-163135

SLC Storage Tank Outlet 52-163135 Storage Tank Outlet

Valve (Q1C41F001B-B).

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, 52-1P63121

SLC Pump.B Space Heater- MTR Space Heater for Standby.

R

Liquid Control System Q1C41C001B-B.

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52-1P52121

SLC Pump A Space Heater Motor Space Heater for Standby

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Liquid Control System Q1C410001A-A.

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52-152115

SLC Storage Tank Outlet 52-152115 Storage Tank Outlet.

Valve Q1C41F001A-A.

52-111316-

SLC' Heat' Tracing

Heat Tracing FDR for Panel

1H22-P110A.

-52-125134

F001A Heat Tracing

Heat Tracing FDR for Panel

1H22-P110B.

4

-The following discrepancies were identified during the Standby Liquid

Control System walkdown.

Labels were missing from F003A, XJ G514 A, and XJ G513 B.

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PP N400 B was not capped. A loose cap was noted.on the floor in the

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same vicinity.

The licensee has implemented a labelling program that will address the-

above discrepancies.

No violations or deviations were identified.

7.

Testing Piping'Supporo and Restraint System (70370)

. The inspectors reviewed the . licensee's ' RF03-- snubber test program for

compliance with.'TS 3/4.7.4,. snubbers.

The licensee functionally tested-

-37 mechanical, eight hydraulic. and five snubbers that failed previous

test.

Additionally, 'the ' licensee conducted. visual inspections on

634-mechanical, 76-hydraulic and three high temperature snubbers.

All

snubbers successfully passed the TS acceptance requirements. However, two

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of the 37 mechanical snubbers failed the ~11censee's administrative

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requirements and were replaced.

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No violations or deviations'were identified.

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8.

Startup From Refueling (72700)

On April 21

1989, Unit 1 entered mode 4 at approximately 4:22 p.m. when

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the reactor vessel head was tensioned.

The inspectors verified that the

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precritical testing was conducted 'in accordance with approved test

procedures, that the test results had been reviewed and were acceptable.

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The control rod scram testing was witnessed by the inspector.

All 193

control rods were tested and successfully met the TS acceptance criteria.

The licensee used the Individual Rod Scram Test-Transient Recorder Auto

Analysis Method. All rods fell within the fast rod criteria.

On April 28, 1989, the inspector witnessed startup for cycle 4.

The

controlling procedure for startup, 03-1-01-1, provided directions for

taking the reactor from a cold shutdown, depressurized condition to a

fully pressurized condition with the main generator synchronized to the

grid carrying a minimum load.

Specified rod withdrawal ' sequence was

performed in accordance with S0I 04-1-01-C11-2.

For each control rod

withdrawn to the full out position, a rod coupling check was performed and

independently verified.

Criticality for cycle 4 was achieved at 9:51 a.m. on group 2, position 18.

The average reactor period was 127.8 seconds with a recirculation loop

temperatures of 149 F for both A and B loop.

Immediately after the

reactor went critical, the SDM was determined to be 1.42% delta J/K. SDM

was performed using procedure 06-RE-SB13-V-0410. Criticality was achieved

in a controlled manner.

.9.

Reportable Occurrences (90712 & 92700)

The below listed event reports were reviewed to determine if the informa-

tion provided met the NRC reporting requirements.

The determination

included adequacy of event description and corrective action taken or

planned, existence of potential generic problems and the relative safety

significance of each event.

Additional inplant reviews and discussions

with plant personnel as appropriate were conducted for the reports

indicated by an asterisk. The event reports were reviewed using the

91 dance of the general policy and procedure for NRC enforcement actions,

regarding licensee identified violations.

a.

On April 18, 1989, the licensee reported to the NRC the failure of

RHR B heat exchanger outlet valve, E12-F003B. The valve failure was

documented in NRC inspection report 89-12.

To determine if the

failure was a common mode failure, the licensee opened, inspected and

replaced the E12-F003A valve disk and stem. The inspection determined

that the RHR A valve wcs in good condition and that the B valve

failure was not ger3ric.

b.

Da April 20, 1989, the licensee reported that a three hour rated fire

barrier, an eight inch concrete block wall between the control

buildings lower cable room and HVAC chase room, was degraded. During

a fire barrier walkdown the licensee noted a notch in the block wall,

not a through penetration, that reduces the wall thickness but does

constitute a deviation to the fire tested configuration.

The

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licensee found that the notch was documented during the construction

phase, prior to 1981, for structural integrity but was not evaluated

for fire barrier rating. The licensee is conducting the evaluation.

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.During L the development of. system design crite' ria document 'for the

c.

L suppression pool. makeup- (SPMU) . system, the licensee identified a

discrepancy. regarding the SPMU system initiation setpoint.

The-

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. suppression pool water level-low trip (16 Lfeet 4 inches): and

allowable value (15 > feet 6.5 inches) were non-conservative with

respect to . the GE analytical limit .ofa16 feet 10 inches.. An

. evaluation of the 15 feet-6.5 inches level ' conclude. that there was

sufficient- suppression pool level to provide a minimum drywell vent

submergence of two feet 'above the top row of vents which was the

original acceptance criteria.

The ' licensee stated the following -

corrective actions have been initiated.

Submitted a TS change to address this discrepancy and administrative 1y

.

established 16' feet 10 inches.as the low level setpoint.

Reduced reliance on outside contractors for engineering support.

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Nuclear plant engineering now has control and custody of the design

--

calculation and has the technical depth to perform these type

calculations without outside assistance.

.In late 1984, the licensee implemented a certification program

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requiring additional second reviews and line management sign off of

-licensing _submittals'. The licensee stated that this process alone

would have caught the SPMU system setpoint error.

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, Developed a' computerized setpoint control program that will' redevelop .

safety related TS setpoint calculations. The TS setpoint calculation

redevelopment program is scheduled to be completed by the' spring of

1990.

Will issue .a quality engineering training bulletin .on the.

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lessons learned.

The ' inspectors reviewed the completed surveillance

06-IC-1E30-M-0001,

Suppression Pool Level Wide Range Channel Functional Test, that readjusted

the instrument trip'setpoints to the new setpoint level.

d.

On April 29, 1989 at approximately 5:00 p.m., during the performance

of surveillance procedure 06-0P-1B21-R-0002, ADS /SRV Valve Operability

Test, a RCIC Division 1 isolation occurred as a result of a steam

line differential pressure high signal.

The plant was in "Startup"

at approximately 9% power with reactor pressure at 945 psig bypassing

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steam to the condenser..

The isolation was cleared at 5:10 p.m. and-

RCIC was ' estored to service.

During the surveillance test, SRV

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B21-F051C did not opened on Division 2 handswitch but did open from

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the Division 1 side controls.

A MWO was written to replace the

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Division 2 transmitter.

After transmitter replacement the F051C SRV

was retested satisfactorily.

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e.

On May 6,1989 at approximately 2:00 a.m., 'a' portion of the' Alert

Notification System sirens in Claiborne . County inadvertently

activated.

The siren was deactivated and -investigated.

This

incident is documented in incident report 89-5-4. .

The public

information officer was notified. so that a news release can- be-

<

generated.

f..

On May 8, 1989 at approximately 6:43 p.m., during attempts to relatch.

the main turbine stop valve, the stop valves -tripped closed and

caused a Division 1 RCIC Hi Delta Flow isolation. The reactor was in

mode 2 at a reactor power of 3%. The isolation was cleared immediately

and a MWO was written to investigate.

No violations or deviations were identified.

'10.

Action on Previous Inspection Findings (92701,92702)

(Closed) .88-01-01, Violation. Failure to follow procedure to properly

store N, bottles inside containment.

The auxiliary building round sheet

(which 1ncludes the containment) were changed to ' include a generic

walkdown to check specifically for proper storage of any compressed gas

bottles.

A memo was issued to all plant personnel to reemphasize' the

importance of proper compressed gas bottle storage inside the plant. This

item is closed.

(Closed) 88-17-01, Inspector Followup Item.

Investigation of B

recirculation-loop perturbations MWO 183422 was written to investigate why

the B FCV closed down partially causing power to decrease from 3833 mwt

to 3706'mwt.

I&C replaced DSR card B33-K6498-1.

No further problems have

occurred. This item is closed.

(Closed) 88-'26-01, Violation.

Failure to follow procedure for completing-

and distributing DOE /NRC Form 741. The licensee has verified 'that all SNM

transactions have been transmitted to DOE via Form 741 and that necessary

corrections have been made to previously transmitted forms.

PAP 01-S-06-15

- has been revised to include detailed instructions for completing DOE /NRC

Form 741.

Future SNR reports will be sent out by the General Manager.

.(Closed) 89-12-01,; Inspector Followup Item.

Improper labelling of MSIV

solenoid ammeters.

Correct labels have been installed per MNCR 0140-89

disposition. This item is closed.

.

11. ExitInterview(30703)

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The inspection scope and findings were summarized on May 19, 1989, with

those persons indicated in paragraph 1 above.

The licensee did not

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identify as proprietary any of the materials provided to or reviewed by

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the inspectors during this inspection. The licensee had no comment on the

following inspection findings:

Item Number

Description and Reference

89-14-01

VIO

Failure to follow procedure for removing a

radiological boundary.

89-14-02

NCV

Failure to take adequate corrective action

for thermal binding valve F065A.

89-14-03

VIO

Inadequate procedure for resetting RFPT

control.

12. Acronyms and Initialisms

ADHRS-

Alternate Decay Heat Removal System

ADS -

Automatic Depressurization System

,

APRM -

Average Power Range Monitor

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B0C -

Beginning of Cycle

Balance of Plant

80P

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BUV -

Bus Under Voltage

CRD

Control Rod Drive

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Design Change Package

DCP

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Diesel Generator

DG

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ECCS -

Emergency Core Cooling System

ESF -

Engineering Safety Feature

Flow Control Valve

FCV

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Health Physics

HP

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HPCS -

High Pressure Core Spray

HPV -

Hydraulic Power Unit

HVAC -

Heating Ventilation & Air Conditioning

Instrumentation and Control

I&C

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Inspector Followup Item

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IFI

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Limiting Condition for Operation

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LC0

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Licensee Event Report

LER

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LLRT -

Local Leak Rate Test

LPCI -

Low Pressure Core Injection

LPCS -

Low Pressure Core Spray

MESI -

Maintenance Engineering Special Instruction

MNCR -

Material Nonconformance Report

Motor Operated Valve

MOV

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M0 VATS-

Motor Operated Valve Analyst Test

MP&L -

Mississippi Power & Light

MS

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Mechanical Standard

MSIV -

Main Steam Isolation Valve

MWO

Maintenance Work Order

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NPE -

Nuclear Plant Engineering

Nuclear Regulatory Commission

NRC

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A

15

Pressure Differential Switch

PDS

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P&ID -

Piping and Instrument Diagram

PSA

Pacific Scientific Arrestor

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PSW -

Plant Service Water.

QDR -

Quality Deficiency Report

RCIC -

Reactor Core Isolation Cooling

RFPT -

Reactor Feed Pump Turbine

Regulatory Guide

RG

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RHR

Residual Heat Removal

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Revolution Per Minute

RPM

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Reactor Protection System

RPS

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RVDT -

Rotary Variable Differential Transformer

RWCU -

Reactor Water Cleanup

RWP --

Radiation Work Permit

SBLC -

Standby Liquid Control

Shutdown Cooling

SDC

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Shutdown Margin

SDM

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SERI -

System Energy Resource Incorporation

System Operating Instruction

501

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SPMU -

Suppression Pool Makeup

SSW

Standby Service Water

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Temporary Change Notice

TCN

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Technical Specification

TS

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