ML17263A547

Insp Rept 50-244/94-01 on 940101-0207.No Violations Noted. Major Areas Inspected:Plant Operations,Maint,Engineering, Safety Assessment/Quality Verification & Plant Support

ML17263A547
Person / Time
Site:	Ginna
Issue date:	03/03/1994
From:	Lazarus W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML17263A548	List: IR 05000244/1994001 ML17263A547
References
50-244-94-01, 50-244-94-1, NUDOCS 9403150008
Download: ML17263A547 (19)

See also: IR 05000244/1994001

Text

U. S. NUCLEAR REGULATORYCOMMISSION

REGION I

Inspection Report 50-244/94-01

License: DPR-1S

Facility:

R. E. Ginna Nuclear Power Plant

Rochester Gas and Electric Corporation (RG&E)

Inspection:

Inspectors:

January

1 through February 7, 1994

T. A. Moslak, Senior Resident Inspector, Ginna

E. C. Knutson, Resident Inspector, Ginna

Approved by:

hief, Reactor Projects Section 3B

INSPECTION SCOPE

Date

I

Plant operations,

maintenance,

engineering,

safety assessment/quality

verification, and plant

support,

9403i50008

9'40304

FDR

ADOCV. 0S000aee

8

PDR

Operations

EXECUTIVE SUMVIARY

Lake water intake structure icing twice forced 50 percent power reductions during a two day

period in January.

In both cases, prompt action to secure a circulating water pump prevented

reduced screenhouse

water level from affecting service water pump operability. The apparent

cause was reduced intake structure heater efficiency due to zebra mussel infestation, coupled

with record-low temperatures.

Corrective action to double the heater supply voltage has been

effective. Throughout this event, the operations staff demonstrated strong attention-to-detail and

strict adherence to procedures.

Strong management involvement, site and corporate engineering

support, quality assurance

oversight, and trade support were evident.

However, the control of

emergency maintenance, particularly requirements for PORC review, could be better delineated

in the governing procedure.

Maintenance

Two containment pressure instruments were discovered to have been inoperable since June 1992

due to blockage of the common sensing line that connects the associated

pressure transmitters

with containment.

Licensee review of this event is in progress.

Trial-basis

implementation of voluntary entry into limiting condition for operation

action

statements for the purpose of conducting preventive maintenance was examined.

The need for

such

maintenance

was

carefully

evaluated

by

the

licensee,

with justification

based

on

probabilistic risk analysis results.

The licensee implemented effective operational controls over

such maintenance.

During work on the "B" motor driven auxiliary feedwater pump, the large

number of maintenance

tasks to be accomplished,

along with the limited space at the work site,

resulted in some inefficiency due to congestion.

1

Plant Support

No deficiencies were noted in review of the licensee's

implementation of revised

10 CFR 20

requirements.

Safety Assessment/Quality

Verification

During this period, the licensee submitted Licensee Event Report (LER) Nos.93-006 and 93-

007.

These LERs were accurate,

met regulatory requirements,

and appropriately identified the

root cause.

TABLEOF CONTFWTS

EXECUTIVESQtlMARY

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1.0

OPERATIONS (71707)

1.1

Operational Experiences

1.2

Control of

Operations................................'.3

Power Reductions Required Due To Lake Water Intake Structure Icing

1.4

Licensee Action on Previous Inspection Findings ...............

1.4.1

(Closed)

Inspector

Follow

Item

(50-244/93-17-01)

Modify

Emergency Operating Procedure E-0 to Direct Manual Actuation

of Safety In~ection

1.4.2

(Closed)

Inspection

Follow Item

(50-244/93-17-02)

Enhance

Emergency Contingency Actions (ECA) Procedure ECA-0.0

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2.0

MAINTENANCE(62703, 61726)... ~...................

2.1

Preventive/Corrective Maintenance........ ~.....

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Routine Observations............,........

2.1.2

Containment

Pressure

Transmitters

Found Inoperable

Plugged Sensing Line

2.1.3

Voluntary

Entry

into LCO Action

Statements

to

Preventive Maintenance ...................

2.2

Surveillance Observations

2.2.1

Routine Observations..............

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3.0

PLANT SUPPORT (71707)

3.1

Radiological Controls...... ~.............

3.1.1

Routine Observations.......,........

3.1.2

Implementation of the Revisions to 10 CFR 20

3 ~2

Security

'3.2.1

Routine Observations..........,.....

3.3

Fire Protection ........................

3.3.1

Routine Observations .;..............

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4.0

SAFETY ASSESSMENT/QUALITY VERIFICATION

4.1

Periodic Reports .......;...........

4.2

. Licensee Event Reports...............

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5.0

ADMINISTRATIVE(71707, 30702, 94600)

5.1

Deep Backshift Inspection

5.2

Exit Meetings...... ~..............

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DETAILS

1.0

OPERATIONS (71707)

1.1

Operational Experiences

During normal power operations on the early morning ofJanuary 20, 1994, a decreasing

screen

house water level was identified. This condition indicated that the flow through the intake, canal

was not sufficient to support the service and circulating water flowdemand.

Actions were taken

to reduce this demand by reducing plant power and securing one of the two main condenser

circulating water pumps.

Additionally, the intake structure heater bar voltage supply w'as

increased

from 240 to 480 volts to-Muce frazil ice formation on the intake grating.

Subsequently,

normal screenhouse

water level was restored.

During the early morning hours

of the following day, the icing condition reappeared

and actions were successfully

taken to

restore water level by reducing power and again temporarily securing a circulating water pump.

Power was then escalated

and remained at 98 percent through the remainder of the inspection

period.

1.2

Control of Operations

Overall, the inspectors

found the R. E. Ginna Nuclear Power plant to be operated

safely.

Control room staffing was as required.

Operators exercised control over access to the'control

room.

Shift supervisors

maintained authority over activities and provided detailed turnover

briefings to relief crews.

Operators adhered to approved procedures

and were knowledgeable

of off-normal plant conditions.

The inspectors reviewed control room log books for activities

and trends,

observed

recorder

traces for abnormalities,

assessed

compliance with technical

specifications,

and verified equipment availability was consistent with the requirements

for

existing plant conditions.

During normal work hours and on backshifts, accessible

areas of the

plant were toured.

No operational inadequacies or concerns were identified.

1.3

Power Reductions Required Due To Lake Water Intake Structure Icing

Lake Ontario is the normal source of cooling water for the Ginna plant.

Cooling for operation

of the turbines that drive the main generator is provided by the circulating water system, while

the reactor plant and auxiliary systems are cooled by the service water system.

Both of these

cooling water systems draw suction from a common inlet bay in the screenhouse.

Lake water

is supplied to the inlet bay through an underground pipe that opens to a shielded intake structure,

located 3100 feet off shore;

On January 20, 1994, at 2:35 a.m., operators were alerted to slowly lowering water level in the

screenhouse

lake water inlet bay when level instrument channel LI-3007 alarmed on low level

(240 inches, or 20 feet; normal screenhouse

level is about 28 feet). The traveling screens {four

sets of vertically mounted, segmented

screen tracks that provide coarse filtration between the

inlet bay and the pump suctions) were inspected and found to be clean and free of ice.

Power

to the four groups of intake

structure

heaters

was

checked

and

found

to be normal

(approximately 40 amps per group). In light ofthe existing record low temperatures,

operators

suspected

that ice was forming on the lake intake structure bars and thus restricting fiow.

2

At 4: 14 a.m., in response to main control board alarm I-1, "Screen House Lo Level 17 Feet,"

operators commenced

a plant power reduction in accordance with site contingency procedure

(SC)-4.1, "Low Screenhouse.Water

Level."

In parallel with the power reduction,

plant

management

authorized alteration of the intake'heater

power supplies to increase

the supply

voltage from 240 volts to 480 volts; this action would increase the amperage of these heaters by

a factor of four.

The work was performed as emergency

maintenance,

as provided for by

administrative procedure (A)-1603, "Work Order Initiation." Three of the four intake heaters

were converted to 480 volts; the "C" intake heater was left connected to the 240 volt source

because

resistance

readings

were found to be lower than the other heaters,

indicating that

operation at higher voltage may'result in premature failure.

During the power reduction, a problem was noted with the screenhouse

water level indications.

Two independent instruments provide indication of screenhouse

water level; LI-3006 provides

- indication and annunciators on the main control board (MCB), and LI-3007 provides indication

via the primary plant computer system (PPCS).

Operators noted that the levels indicated by

these two instruments were diverging as screenhouse

water level was lowering.

To provide

reliable data, opeiations management

directed that screenhouse

water level be determined by

direct measurement,

using a weighted tape measure.

0

When power had been reduced to 50 percent, one of the two main circulating water pumps was

secured.

The resultant reduction in flow out of the water inlet bay had the prompt effect of

increasing level by approximately five feet. The increased voltage to the intake structure heaters

was also proving effective, with ice and zebra mussels being observed collecting in the traveling

screens.

By 8:40 a.m.,

normal screenhouse

water level had been

restored.

To resolve

discrepancies between PPCS and MCB level indications, calibration checks were performed, and

both instruments were found to be within acceptable

tolerances,

The instrument sensing lines

were blown down with air to eliminate any possible sources of blockage.

Following this action,

the level instruments indicated in close agreement.

The Plant Operations

Review Committee (PORC) subsequently

reviewed the divergent level

indications with respect to the requirements of emergency plan implementing procedure (EPIP)

1-0, "Ginna Station Event Evaluation and Classification."

EPIP 1-0 stipulates that a site area

emergency be declared if, "Screenhouse Intake Water Level is less than or equal to the 15'o

Level Alarm (1-9)." The lowest screenhouse

water level reached'prior to securing the circulating

water pump was approximately 15.5 feet; the fact that MCB annunciator I-9, "Screen House Lo-

Lo Level, 15 Feet," never alarmed indicates that the LI-3006 level never fell below 15 feet.

PORC concluded that EPIP 1-0 was overly conservative in declaring a site area emergency based

solely on low screenhouse

water level. This conclusion was based on recent industry guidance

on emergency

action level (EAL) determinations,

as well as on technical evaluation of the

minimum water level required for service water pump operability.

As written, the technical.

basis for declaring a site area emergency

at a screenhouse

water level of 15 feet was the

potential for loss of heat sink due to lowering lake level.

Preceding EAL determinations

(unusual event and alert) in EPIP 1-0 were based on progressively lower lake levels; however,

the criteria changed

from lake level to screenhouse

level for determination of a site area

emergency.

Consequently,

the procedure did not accurately account for low screenhouse

water

level, when it was not the result of correspondingly low lake level (as in the case of intake

structure icing).

At 12:02 p.m. on January 20, 1994, the plant commenced power escalation, and by 6:10 p.m.,

had returned to fullpower operation.

However, at 10:51 p.m., operators noted that screenhouse

water level was again slowly trending downward.

Plant power was again reduced to just below

50 percent and, at 9:27 a.m. on January 21, 1994, a main circulating water pump was secured.

This action was successful in restoring and stabilizing screenhouse water level. Again, quantities

of'ice and zebra mussels

were noted in the traveling screens

following the pump shutdown.

Later that day, full power operation was again restored,

with no subsequent

difficulties in

maintaining screenhouse

level.

From these observations,

the inspector concluded that the cause of these two instances of low

screenhouse water level was frazil ice formation on the intake structure bars. This ice formation

was the result of extreme winter conditions, along with reduced heater bar efficiency due to

zebra mussel infestation.

Higher intake structure temperature due to operation of the heaters at

480 volts appeared

to reduce the zebra

mussel infestation; this, along with more moderate

weather, restored the capability of the intake structure heater bars to retard ice formation.

The inspector assessed

the licensee's overall response to this event to have been good.

Strong

management involvement, site and corporate engineering support, quality assurance

oversight,

and trade support were evident throughout the event.

The inspector considered that control of

emergency maintenance, particularly requirements for PORC review, could be better delineated

in the governing procedure.

Additionally, the inspector considered that the licensee should have

recognized and expeditiously resolved the apparent disparity in EPIP 1-0 (that is, entry into a

site area emergency without having transitioned through an unusual event and alert), given the

relatively slow development of the event.

Throughout this event,

the operations staff demonstrated

strong attention-to-detail and strict

adherence

to procedures,

from the initial indications of decreasing

screenhouse

water level,

through responding to challenging operational concerns of electrical grid stability, condensate

depression,

elevated

circulating water discharge

temperatures,

and plant power reductions/

escalations.

The operators

demonstrated

an excellent understanding of their procedures

and

further enhanced

these procedures by capturing information gained through experiences during

this infrequent occurrence of water intake structure icing.

To gain additional insight on icing events,

the RG&E engineering

staff has

invited a

representative from the James A. Fitzpatrick Plant to discuss the lessons learned from the three

icing incidents that occurred there in 1993.

e

1.4

Licensee Action on Previous Inspection Findings

1.4.1

(Closed) Inspector Follow Item'(50-244/93-17-01) Modify Emergency

Operating

Procedure E-0 to Direct. Manual Actuation of Safety Injection

On January

26,

1994,

the PORC

approved

procedure

change

notice (PCN) 93-3757

to

emergency

operating

procedure

E-O,

"Reactor Trip or Safety Injection," that modified

procedural step 4 by directing the operator to manually actuate safety injection (SI) ifrequired

by an annunciated alarm.

Although this procedure previously accomplished the desired system

alignment, PORC concluded that manually actuating SI was more expeditious and reliable than

having the operator initiallyperform individual component manipulations.

Through attendance at the PORC meeting, review of supporting documentation,

and discussion

with licensee representatives,

the inspector determined that the licensee appropriately responded

to the finding and had no additional questions on this matter.

1.4.2

(Closed) Inspection Follow Item (50-244/93-17-02) Enhance Emergency Contingency

Actions (ECA) Procedure ECA-0.0

On January 26, 1994, PORC approved PCN 93-3756 and PCN 93-3837, to ECA 0.0, "Loss of

AllAC Power," and emergency restoration (ER) procedure ER-D/G.2, "Alternate Cooling for

Emergency Diesel Generators,"

respectively.

These changes

enhance

operator guidance for

energizing buses

17 and 18 and starting service water pumps to provide EDG cooling following

a complete loss of offsite power.

Should use of normal service water be precluded, operators

are directed to ER-D/G.2 for alternative measures.

Through attendance at the PORC meeting, review of supporting documentation, and discussion

with licensee representatives,

the inspector determined that the licensee appropriately responded

to the finding and had no additional questions on this matter.

2.0

MAINTENANCE(62703, 61726)

2.1

Preventive/Corrective Maintenance

2.1.1

Routine Observations

The inspector observed portions of maintenance activities to verify that correct parts and tools

were utilized, applicable industry code and technical specification requirements were satisfied,

adequate

measures

were in place to ensure

personnel

safety and prevent damage

to plant

structures, systems, and components, and to ensure that equipment operability was verified upon

completion.

The following maintenance activities were observed:

e

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Work Order 19440590,

"Perform CPI-FLO-2002," performed

in accordance

with

calibration procedure

(CPI)-FLO-2002, "Calibration of 1B Motor Driven Auxiliary

Feedwater Pump Discharge Flow Loop 2002," revision 5, effective date April2, 1993,

observed January

10, 1994

The inspector observed electrical calibration checks at the instrument rack; as-

found calibration was satisfactory, no adjustments were required.

The inspector

observed excellent procedural adherence

and good coordination between the two

technicians involved:

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Work Order 19369324, "Perform CPI-PRESS-2030," performed in accordance with CPI-

PRESS-2030,

"Calibration of Motor Driven Auxiliary Feedwater

Pump B Discharge

Pressure Loop 2030," revision 6, effective date November 18, 1993, observed January

'0, 1994

The inspector observed calibration testing of pressure gauge PI-2190A; as-found

calibration

was

satisfactory,

no adjustments

were required.

The inspector

observed excellent procedural adherence

and good coordination between the two

'echnicians involved.

Work Order 19440277, "CV-4010 - Major Inspection," performed in accordance with

maintenance

procedure (M)-37.16H, "Inspection and Maintenance of Chapman-Crane

Tilting Disc Check Valve," revision 19, effective date November 15, 1992, observed

January

10, 1994

The inspector observed valve disassembly;

the valve was in good condition and

required no refurbishment beyond minor cleaning.

Work Order 9301531,

"MOV-4008 Limitorque Operator - Adjust Tripper Fingers,"

performed in accordance

with M-64.2, "Limitorque SMB-000 and SMB-00 Motor

Actuator Maintenance Procedure," revision 17, effective date February 3, 1993, observed

January

10, 1994

Limitorque motor actuators

can be operated

either by an installed motor or

manually, using a handwheel.

A manually operated

declutch lever is used to

switch from the motor operated

mode to the manual mode.

Once the declutch

lever has been depressed,

the actuator is designed to remain in the manual mode

without further operation of the declutch lever. This feature is performed by two

tripper fingers, which latch against an adjustment arm when the declutch lever is

depressed

and hold the clutch in the manual position.

Subsequently, ifthe motor

is operated,

cams that rotate only when the motor is running push the tripper

fingers offof the adjustment arm, and the clutch shifts back to the motor operated

position. This maintenance was initiated because continuous downward pressure

on the declutch lever was required to prevent the actuator from slipping into the

motor operated

mode

during

manual

valve operation,

indicating probable

misadjustment

of the

tripper

fingers.

This

aberrant

condition

does

not

compromise valve operability.

The procedure for setting the height of the tripper finger adjustment arm was not

in accordance

with the vendor's

current

guidance;

as

a result,

the initial

adjustment did not correct the problem.

The procedure was corrected by a PCN,

and proper alignment of the tripper finger adjustment arm was subsequently

obtained.

Acceptance testing, as specified in the original work package, did not specifically

test operation of the declutch lever; as a result, the fact that the initialadjustment

had been unsuccessful was not promptly identified. The specified acceptance

test

(the quarterly pump performance test) was not scheduled to be performed until

completion of all "B" train AFW system maintenance.

Through discussions with

personnel

who manually operated

the valve as a part of restoration from the

tripper finger adjustment, the inspector determined that the adjustment arm'ad

not been properly set.

The inspector informed the licensee of this finding while

the maintenance isolation was still in effect. As a result of rework to correct this

problem, the duration of the system outage exceeded

the planned duration by

several

hours;

had

the problem,

instead,

been

identified during the pump

performance

test, additional time would have been required to reestablish

the

maintenance isolation, reestablish system operational alignment after the rework,

and reperform the test.

The original job scope did not include motor removal.

Since a generic procedure

was used to perform the maintenance,

non-applicable portions were so annotated

as a part of the work package preparation.

During the course of the maintenance,

motor removal became necessary;

however, the work package was not reviewed

to ensure

that procedural items applicable to motor removal were reinvoked.

This deficiency was also noted by licensee QA during review of the completed

work package (Quality Assurance Observation Report 94-001:CEC).

Work Order 19001246,

"Replace Valves 8675A and 8675B and Piping," performed in

accordance

with M-37.134,

'-'Repairs

and Replacements

of QA Welds, Welded and

Threaded

Piping Components,"

revision 8, effective date May 13,

1993,

observed

January 25, 1994

Valves and piping make up the sample point for the "B" spent fuel pit cooling

system,

located at the pump discharge.

No deficiencies were noted; good QC

involvement was observed.

2.1.2

Containment Pressure Transmitters Found Inoperable Due To Plugged Sensing Line

The engineered safety features (ESF) system uses containment pressure as an initiating parameter

for several functions. A total of six pressure detectors (three 10-200 psia wide range and three

0-60 psig narrow range) provide input to the ESF system actuating logic, with two out of three

coincidence required to actuate the associated

ESF functions.

Detectors are connected

to the

containment atmosphere in pairs (one wide and one narrow range) through three separate sensing

lines. Allsix instruments provide indications in the control room; in addition, outputs from the

three narrow range detectors are monitored and archived by the PPCS.

On January 19, 1994, a control room operator observed that containment pressure narrow range

indicator PI-947 was indicating slightly lower than the other narrow range containment pressure

instruments.

Although the amount of deviation was within the tolerance specified for channel

comparison,

the operator

pursued

investigation.

A review of data archived by the plant

computer over the previous

18 days revealed

that PI-947 was not tracking with redundant

containment pressure indicators PI-945 and PI-949. A trouble report was submitted to initiate

corrective action.

On January 21, 1994, a calibration of the PI-947 pressure transmitter (PT-947) and associated

instrument loop was performed.

No equipment deficiencies were noted and no adjustment was

necessary.

Although this maintenance indicated that there was not a problem with PI-947, the

maintenance planner maintained the trouble report open, pending evaluation of new trending

data.

On February

1, 1994, the planner reviewed plant computer data archived subsequent

to

the calibration, and determined that PI-947 was still not tracking properly.

The planner then

brought this problem to the attention of the system engineer.

Prior to a routine equalization of containment pressure with atmosphere

on February 2, 1994,

test equipment was installed to monitor the outputs of PT-947 and the associated

narrow range

detector,

PT-948.

Test equipment

was also installed on one of the pressure

transmitters

connected

to each of the remaining two penetrations

that are used to measure

containment

pressure.

The outputs from these two detectors (PT-946 and PT-949) decreased

as expected in

response

to the pressure

decrease;

however, PT-947 and PT-948 outputs remained constant

throughout the pressure change, indicating that they were both inoperable.

In accordance with

technical specification table 3.5-2, the associated

ESF relays were tripped; in this condition,

continued power operation would be allowed until the next scheduled calibration of the affected

containment pressure instruments.

Troubleshooting revealed the problem to be a blockage in the common sensing line between

containment and the two pressure

detectors.

A temporary valve was installed at the open end

of the sensing line in containment.

This temporary boundary was demonstrated to be leak tight

using 120 psig air. The sensing line was then disassembled

at the containment penetration and

the obstruction, located in the portion of the sensing line within the containment penetration, was

dislodged using a metal rod.

The sensing line was then reassembled

and blown down with air

through the temporary valve. The obstruction consisted ofa black powder, which was collected

and retained for analysis.

Since the reassembled

sensing line had not been leak tested at the

point when the temporary valve was opened,

the. licensee entered a four hour action statement

per technical specification,3.6.3.1.a

for an inoperable containment isolation boundary.

The

sensing

line was

leak

tested

in accordance

with periodic

test procedure

(FIT)-23.17B,

"Containment Isolation Valve Leak Rate Testing, Pressure

Transmitters PT-947 and PT-948,

Penetration 203A," and returned to service approximately one hour later.

PT-947 was also

returned 'to service,

having been calibrated

as part of the troubleshooting effort and with

continued satisfactory operation having been verified during the penetration leak test,

Since no

quantitative testing had been performed on PT-948 during the troubleshooting, and since it was

nearly due for annual calibration gast performed March 1993), the decision

was made to

calibrate the instrument prior to returning it to service.

This was completed and PT-948 was

declared operational on May 4, 1993.

Through interviews with the personnel involved, observation of maintenance,

and review of

applicable documentation,

the inspector assessed

this to have been an excellent maintenance

effort. The inspector considered that the original identification of the problem was particularly

noteworthy.

The questioning attitude of an operator pursuing an indication that did not appear

correct resulted in identifying a degradation of the ESF actuating circuitry that was undetectable

within the existing scope of maintenance

and testing.

Site engineering was directly involved,

from identification of the problem through restoration of operability. Efforts of instrument and

control, health physics, and quality assurance

organizations were well coordinated.

Review of long-term historic data archived by PPCS revealed that the PT-947 tracking problem

had developed in May or June of 1992.

The inspector was concerned that this condition could

have gone undetected for so long a period of time. As of the close of the inspection period, the

licensee had initiated an investigation ofthis incident and was generating a licensee event report.

The inspector willcontinue to monitor the licensee's review, evaluation, and corrective actions

regarding this incident, through the licensee's

corrective action report (CAR) system (CAR

2087) and through review of the licensee event report.

2.1.3

Voluntary Entry into LCO Action Statements to Perform Preventive Maintenance

In anticipation of converting the plant to an extended (18 month) operating cycle in 1996, the

licensee is phasing in a program to enter into limiting conditions for operation (LCO) action

statements

to perform preventive maintenance

(PM) on a selective basis.

This change

in

maintenance

philosophy is a departure from the past scheduling practice in which PM was

accomplished at a time when safety equipment was not needed; e.g., during refueling outages.

An extended

operating

cycle would necessitate

scheduling

certain PM 'activities before

a

regularly scheduled plant shutdown.

To assess

the impact of such activities and identify the potential problem areas,

the licensee,

using probabilistic risk analysis (PRA) data, selected the "B" motor driven auxiliary feedwater

pump (MDAFP) and the "C" standby auxiliary feedwater pump (SAFP) to be removed from

service the weeks of January

10 and January

17, respectively, for the purpose of performing

various PM tasks.

To support these activities, PORC reviewed changes

to administrative (A)

procedures A-52.4, "Control of LimitingConditions for Operation For Operating Equipment,"

and A-1603, "Overview of the Ginna Station Work Control System," and relevant evaluations

that stipulated

additional controls to be imposed.

Constraints

to be applied during such

equipment outages included:

~ 'riticalpath activities would involve two shift coverage, alternating between the various

shops to avoid area congestion;

~

Spare parts would be verified to be in-stock prior to starting work;

Components that provide redundant safety function would be verified to be operable;

"C

The expected outage time for the affected safety-related equipment should be less than

50 percent of the allowed outage time stated in the technical specifications.

Prior to

commencing work, the shift supervisor would authorize any maintenance

activities;

however, ifthe planned work scope was projected to be greater than 50 percent of the

allowed outage time, approval by the Plant Superintendent would be required.

In developing additional controls, the licensee used the technical guidance contained in various

NRC documents

addressing

voluntary entry into LCO action statements

for maintenance

to

assure

that appropriate

safety principles were applied.

Additionally, PRA data was used in

making system selections to minimize risk probabilities.

The inspector reviewed the licensee's

relevant procedures,

evaluations,

and schedules,

and

observed

related

maintenance

activities in-progress.

Through

this review,

the inspector

concluded that the licensee has methodically evaluated performing PM on selected safety-related

equipment when operating at power.

Through observations of work in-progress on the "B" MDAFP and review of supporting work

packages,

the inspector determined that the tasks were expeditiously carried out, with the pump

being out-of-service for 37.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> of a 7-day action statement.

The inspector confirmed that

redundant safety equipment was available during this period, including the "A" MDAFP, the

turbine driven auxiliary feedwater pump, and the "A" emergency

diesel generator.

With the

exception ofMOV-4008 (as discussed in section 2.1.1 ofthis report), work packages were found

to be appropriately detailed and identified the specific work scope.

Although a schedule was

developed to preclude work area congestion, the inspector did observe a significant number of

craft technicians (1&C, mechanics,

and electricians) working at the same time in the small area

of the "B" MDAFP. This condition did challenge the workers in carrying out their assignments.

The licensee

acknowledged

the inspector's

observation

and indicated that they planned

to

improve coordination of craft activities in future maintenance activities.

The inspector had no

further questions in this area.

2.2

Surveillance Observations

2.2.1

Routine Observations

Inspectors observed portions of surveillances to verify proper calibration of test instrumentation,

~

~

~

~

use of approved

procedures,

performance of work by qualified personnel,

conformance

to

limitingconditions for operation (LCOs), and correct system restoration following testing.

The

following surveillances were observed:

10

Performance Test (PT)-2.8M, "Component Cooling Water Pump MonthlyTest," revision

9, dated April2, 1993, observed January 6, 1994

PT-47. 10, "Spent Fuel Pit Charcoal Filtration System Efficiency Test," revision 6, PCN

94T-030, dated February 25, 1993, observed January 25, 1994-

~

PT-9.1.17, "Undervoltage Protection - 480 Volt Safeguard Bus 17," revision 9, dated

January

13, 1994, observed February 2, 1994

~

PT-2.2M, "Residual Heat Removal System - Monthly," revision 3, PCN 94T-0038,

effective date February 5, 1993, observed February 3, 1994

The inspector determined

through observing this testing that operations

and test personnel

adhered to procedures,

test results and equipment operating parameters

met acceptance criteria,

and redundant equipment was available for emergency operation.

3.0

PLANT SUPPORT (71707)

~

~

~

~

~

3.1

Radiological Controls

3.1.1

Routine Observations

1

The inspectors periodically confirmed that radiation work permits were effectively implemented,

dosimetry was 'correctly wor'n in controlled areas,and

dosimeter

readings

were accurately

recorded, access to high radiation areas was adequately controlled, survey information was kept

current, and postings and labeling were in compliance with regulatory requirements.

Through

observations ofongoing activities and discussions with plant personnel, the inspectors concluded

that the licensee's radiological controls were generally effective.

3.1.2

Implementation of the Revisions to 10 CFR,20

All licensees were mandated to implement the broad changes that have been made to 10 CFR 20, "Standards for Protection Against Radiation," by January 1, 1994. In completing this effort,

licensee's were to revise radiological control procedures

and other associated

procedures,

such

as

emergency

preparedness,

administrative

and ALARA job planning;

upgrade

training

programs; and, post plant areas to comply with the new requirements.

k

The inspector reviewed

the status of RG&E actions

to implement these

changes,

through

procedure/record

reviews, plant tours, attendance

at general employee training sessions,

and

discussions with licensee representatives.

Based on this review, the inspector verified that about

140 radiation protection implementing and administrative procedures

have been upgraded and

were effective January 1, 1994; that NRC Form 4, "Radiation Exposure History," NRC Form 5,

11

"Monitoring Personnel Occupational Exposure," and NRC Form 439, "Report ofTermination,

Individual Occupational Exposure," reflect current requirements; and, that plant radiation areas,

based on the new criteria, were properly posted.

3.2

Security

3.2.1

Routine Observations

During this inspection period,

the inspectors

verified that x-ray machines

and metal and

explosive detectors were operable, protected area and vital area barriers were well maintained,

personnel were properly badged for unescorted or escorted access,

and compensatory

measures

were implemented when necessary.

No unacceptable conditions were identified.

3.3

Fire Protection

3.3.1

Routine Observations

The inspectors periodically verified the adequacy of combustible material controls and storage

in safety-related areas of the plant, monitored transient fire loads, verified the operability of fire

detection and suppression

systems,

assessed

the condition of fire barriers,

and verified the

adequacy of required compensatory

measures.

No discrepancies

were noted.

4.0

SAFETY ASSESSM~22tT/QUALITY VERIFICATION

4.1

Periodic Reports

Periodic reports

submitted by the licensee

pursuant

to Technical Specification 6.9.1 were

reviewed.

Inspectors verified that the reports contained information required by the NRC, that

test

results

and/or

supporting

information were

consistent

with design

predictions

and

performance specifications,

and that reported information was accurate.

The following report

was reviewed:

Monthly Operating Report for December

1993

No unacceptable conditions were identified.

4.2

Licensee Event Reports

Licensee Event Reports (LERs) submitted to the NRC were reviewed to determine whether

details were clearly reported,

causes

were properly identified, and corrective actions were

appropriate.

The inspectors also assessed

whether potential safety consequences

were properly

evaluated, generic implications were indicated, events warranted additional onsite follow-up, and

applicable requirements of 10 CFR 50.72 were met.

0

12

The following LERs were reviewed (Note:

date indicated is event date):

93-006, Feedwater Transient Results in a Lo-Lo Steam Generator Level and Subsequent

Reactor Trip. The cause was determined to be disconnection of the "A"-main feedwater

regulating valve positioner feedback linkage arm from the valve actuator linkage rod due

to disengagement of the screw from its nut.

(November 10, 1993)

I

93-007, High Source Range Flux Level During Reactor Startup Causes a Reactor Trip.

The cause was attributed to an operator inappropriately focusing his attention on P-6

status

lights (subsequently

found to be burned

out) rather

than

source

range

and

intermediate range indications.

(November 22, 1993)

The inspector

concluded

that the LERs were accurate,

met regulatory requirements,

and

appropriately identified the events root causes.

5.0

ADMINISTRATIVE(71707, 30702, 94600)

5.1

Deep Backshift Inspection

During this inspection period, a backshift inspection was conducted on February 7, 1994 and a

deep backshift inspection was conducted on January 20 and 22, 1994. The inspection on January

20 was in response

to the decreasing

screen house water level situation (See paragraph

1.3).

5.2

Exit Meetings

At periodic intervals and at the=conclusion of the inspection, meetings were'eld with senior

station management

to discuss

the scope and findings of inspections.

- The exit meeting for

inspection report 50-244/94-02 (engineering program inspection) was held on January 14, 1994,

by Mr. Harold Gregg.

The exit meeting for the current resident inspection report 50-244/94-01

was held on February

10, 1994, and was attended

by Mr. James Linville, Chief, Reactor

Projects Branch 3.