ML16342C651

level

during the performance of an instrumentation

and control

(18tC)

surveillance

where all affected instruments

were not taken out of

service prior to commencing testing.

Operator attentiveness

identified

9408220084

9408l5

PDR

ADOCK 05000275

8

PDR

the improper performance of a procedural

step during the calibration of

a steam flow channel

and initiated action to secure

from testing

(Section 5.1).

Maintenance:

Weakness:

The failure to perform

a step in

a procedure,

and failure to properly

resolve the resulting procedural

ambiguity during the calibration of a

steam flow channel,

resulted

in a test signal

being improperly inserted

into control circuitry,.resulting in an undesired

change

in steam

generator

level

(Section

5. 1).

This was a'oncited violation.

Inadequate

consideration

was given to the potential

impact of the change

in charcoal

sample analysis

on charcoal

adsorber

bed operability and

a

ventilation damper design

change

on charcoal

adsorber

bed in-service

hours.

The design

change

involved the replacement

and testing of

auxiliary building ventilation damper position switches.

During the

installation of the design

change,

the auxiliary building ventilation

charcoal

adsorber

bed remained

in service.

As

a result of delays during

the modification and associated

testing,

the Technical

Specifications

(TS) required

number of hours of service

between

samples

was exceeded

(Section 5.2).

'This was

a noncited violation.

Strength

I'uring

two separate

activities,

the guality Assurance

organization

identified deficiencies

in a procedure

which prevented

four residual

heat

removal

(RHR) check valves

from being full-stroke exercised

during

the last Unit 2 cold shutdown

(Section 3.2)

and identified

nonconservative

throttling of component cooling water

(CCW) flow to

centrifugal

charging

(CC)

pump coolers

(Section

6. I).

Weakness:

ASME Section

XI inservice testing requirements

were not properly

implemented

in

a surveillance test procedure,

which resulted

in failure

to accomplish required full-stroke testing of foUl

RHR system

check

valves during the last Unit 2 cold shutdown period (Section 3.2).

This

was

a Level

IV violation.

Nonconservative

errors

in an engineering calculation resulted

in

unacceptably

low CCW flow to the

CC pump coolers.

This low flow rate

was caused

by improper, positioning of cooling water throttle valves.

The reduced

CCW flow would have resulted

in exceeding

the maximum

allowable

pump bearing oil temperatures

during design basis

accident

conditions.

Concern over the throttling of

CCW flow had

been raised

by

the li.censee guality Assurance

organization

in 1990;

however,

the issue

was inadequately

resolved

at that time (Section

6. 1).

Strength:

Overall, plant support

performance

was

good during the inspection period

and

remained

unchanged

from the last period.

Inspectors

observed that

housekeeping

practices

in contaminated

areas

were generally

adequate,

and

could

be improved.

Summar

of Ins ection Findin s:

~

Violation 323/94-18-01

was identified (Section 3.2).

.

Noncited Violation 323/94-18-02

was identified (Section

5. 1).

Noncited Violation 323/94-18-03

was identified (Section 5.2).

Inspection

Followup Item 323/93-30-01

was closed

(Section 8. 1).

Violation 323/94-11-01

was closed

(Section 9.1).

LERs 275/94-14,

275/94-10,

and 275/93-12,

Revisions

0,

1,

and

2 were

closed

(Section

10).

Attachments:

~

Attachment

1

Persons

Contacted

and Exit Meeting

~

Attachment

2

Acronyms

0'

DETAILS

1

PLANT STATUS

(71707)

1.1

Unit

1

Unit

1 operated

at

100 percent

power during the entire report period.

1.2

Unit 2

Unit 2 operated

at

100 percent

power for the entire report period,

except

on

July 9 when power was curtailed to 90 percent for the performance of turbine

valve testing.

2

ONSITE RESPONSE

TO EVENTS

(92701

and

93702)

2. 1

Brush Fire Outside of the Protected

Area

On June

22,

1994,

the licensee

declared

an Unusual

Event

(UE) at 2:40 a.m.

(PDT) due to

a grass fire approximately

100 yards outside of the protected

area.

The fire was located

on the hillside east of the plant

and

came within

approximately

100 yards of the

500

KV transmission

lines.

The fire burned

several

acres of grassland

to the south of the

500

KV transmission

lines

and

to the 'northeast of the Nuclear

Power Generation

warehouse.

The fire was

caused

by an electrical

arc at connections

on

a

12

KV power line, independent

of plant related

loads.

The operations

department

isolated the power to the

line in the process of fighting the fire.

Permanent

removal of power to the

12

KV line was planned

as

a corrective action for a previous grass fire but

had not been completed.

The licensee notified the California Department of

Forestry

who responded

to fight the fire with the licensee's fire response

team.

The fire was reported to be out and the unusual

event terminated

at

5:15 a.m.

Conclusion

The fire did not at any time pose

a significant threat to the safe

operation of the facility.

Licensee

response

and declaration of a

UE appeared

appropriate

and well coordinated.

However, the licensee's

corrective actions

for a previous similar event

had not been aggressive

enough to preclude

recurrence.

2.2

Potential to Over ressurize

the

RHR

S stem

~Back round

During the Unit

1 outage

on Hay 1,

1994, while

RHR flow was

throttled at the

pump discharge

due to low core decay heat loads,

the licensee

inadvertently pressurized

the

RHR system to 605 psig, while the reactor

coolant system

(RCS)

was solid.

The licensee

determined that

no design

margins

had

been

exceeded

by that event.

However,

since the potential to

reach

RHR system pressure

over 600 psig

had not been anticipated,

the licensee

initiated further analysis of the vulnerabilities of the

RHR system during

throttled flow operations.

As

a result of further analysis,

the licensee

determined that, within the

operational

controls of the

RHR and

RCS, it would have

been possible

to have

pressurized

the

RHR heat exchanger

to 675 psig

a pressure

greater

than the

design

pressure

of 600 psig

and greater

than the

ASNE code allowable of

110 percent of design

pressure

(660 psig).

The concern is isolated to the

RHR

heat

exchanger,

since the piping, instrument 'tubing,

and components

such

as

valves all have design

pressures

or ASNE code allowables

above the

675 psig

limits.

The licensee

determined that the

RHR heat

exchanger

was never subjected

to

pressure

above that allowed by ASNE code.

Also, the licensee

determined that

the vulnerability to overpressurize

the

RHR system

was brought about

by

a

failure to properly consider

the combined effects of the

pump discharge

head

and suction pressure,

while discharge

flow was throttled

and while the

RCS was

above

atmospheric

pressure.

The licensee

has initiated

a nonconformance

report

and plans to correct the

vulnerability by operationally restricting the

use of throttled

RHR flow to

those

cases

in Node

6 where the

RCS is vented

and, therefore,

not able to

transfer excessive

pressure

to the

RHR system.

Conclusion

The licensee

had not properly understood

the potential effects of

RHR pump discharge

pressure

under throttled

RHR flow conditions with the

RCS

not vented.

There were

no negative effects

on plant equipment,

and corrective

action appeared

appropriate.

Because

the worst-case

effects of this event

were within ASNE code allowable limits, this issue

was considered

of minor

importance,

3

OPERATIONAL SAFETV VERIFICATION

(71707)

3. 1

Failure to Remove Caution

Ta

On June

27,

1994, during

a walkdown of the Unit

1 pipe rack area,

~ the

inspector noted

a caution tag which was

hung for- a surveillance

in April 1994

during the Unit

1 refueling outage.

The inspector

questioned

the purpose of

the caution tag.

The caution tag was attached

to Valve Air-I-1-4351 for the

performance of Surveillance

Test Procedure

(STP)

I-4-PCV-20,

"10% Steam

Dump

Valve PCV-20 Calibration," which was completed

on April 22,

1994.

STP I-4-PCV-20, Step 8.5. l.c contains,

instructions for hanging the caution

tag,

and Step 8.5.3.c directs the technician to close vent Valve AIR-I-1-4351,

restore

the vent valve test

cap,

and

remove the caution tag.

The step

had

been initialed as being complete

and verified and initialed by

a separate

individual.

Following identification of the inspector's

concern,

the vent

valve, AIR-I-1-4351, was verified to be

open with the test

cap restored.

Investigation revealed that there

was

an additional

clearance

hung

on valves

within the boundaries

of this procedure

at the time the surveillance

was

performed,

and that the additional

tags

were

a potential

source of confusion

during the system restoration portion of the surveillance.

The licensee

has

initiated

an Action Request

to document, this problem,

which appeared

appropriate.

0

Conclusion

The failure to remove the tag

appeared

to have

been

an

administrative error with no safety significance

in this instance,

since plant

configuration control

appears

to have

been maintained.

However, this does

not

lessen

the significance of two people

improperly initialing the completion

and

verification of the procedural

step without completing all of the required

actions.

The

NRC will review the licensee's

response

to the Action Request

and the resolution of this problem.

3.2

RHR Check Valve Inservice Testin

Backcaround

During

a licensee

quality organization

review of STP V-4B,

"Functional Test of the

ECCS Check Valves at Cold Shutdown," it was noted that

the recorded

data did not verify the required

2200

gpm flow through

RHR heat

exchanger

discharge

check Valves

2-8742A and 2-8742B.

During the

surveillance,

a bypass

flow path allowed

an unmeasured

amount of the flow to

be diverted

around the Valves 2-8742A and 2-8742B.

Further investigation of

.

the testing requirements

revealed

the specified flow rate of 2200

gpm was less

than the system design flow rate

and, therefore,

would not accomplish

the

required full-stroke testing of the valves.

This procedural

deficiency

affected

both

RHR heat exchanger

discharge

check Valves 2-8742A and 2-8742B

and the

RHR pump discharge

check Valves 2-8730A and 2-87308.

Following the

discovery of the inadequate

testing

on June

23,

1994,

the licensee

entered

into TS 4.0.3 for Unit 2.

In this situation,

T.S. 4.0.3 allowed the action

requirements

of TS 3,0.3 for both

RHR trains inoperable to be extended for up

to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

Full-stroke testing through the four aforementioned

RHR check valves is

required

by TS 4.0.5.a.

TS 4.0.5.a.

specifies

the inservice surveillance

requirements

of ASME Code Class

1, 2,

and

3 components

shall

be in accordance

with Section

XI of the

ASME Boiler and Pressure

Vessel

Code requirements.

Unit

1 valves

were not affected since all cold shutdown periods

were within

3 months of refueling outage full-stroke exercising.

Section

XI of the

ASME

Code Subsection

IWV-3522 requires full-stroke check valve exercising

where the

interval since previous

shutdown testing

has

been

3 months or greater.

During refueling outages,

the full-stroke testing of the check valves is

accomplished

by STP V-4A, "Functional Test of RHR Check Valves."

STP V-4A

accomplishes

the full-stroke tests

by passing full RHR design flow through

RHR

heat

exchanger

discharge

check Valves 8742A and 8742B and

RHR pump discharge

check Valves 8730A and 8730B.

Effect of Condition on Safet

Function

The licensee

requested

NRC enforcement

discretion

be exercised for the performance of cold shutdown full-stoke tests

of Unit 2

RHR pump discharge

check valves

and Unit 2

RHR heat exchanger

check

valves until the next Unit

2 cold shutdown,

and

no later than the next

refueling outage

(2R6).

The licensee

evaluated

RHR system

response

during the

cold shutdown period

and previous test results to provide the

NRC with

justification for continued operation.

The

NRC exercised

enforcement

discretion,

to not enforce

compliance with TS 4.0.3 until

a temporary relief

request

was processed

by the

NRC, verbally at 6:35 p.m.

EDT on June

24,

1994,

0

followed by letter

on June

28,

1994 (Notice of Enforcement Discretion 94-6-

011).

The temporary relief from ASME Section

XI cold shutdown full-stroke

requirements

for the four Unit 2

RHR check valves

was

approved

by the

NRC

letter dated July 11,

1994.

Conclusion

Failure to properly implement inservice testing requirements

in

STP

V-4B=- resulted

in failure to full-stroke test Unit 2

RHR heat

exchanger

discharge

check Valves 2-8742A and 2-8742B

and

RHR pump discharge

check

Valves 2-8730A and 2-8730B during the most recent cold shutdown period.

Failure to full-stroke these

RHR check valves during cold shutdown periods

was

a violation of TS 4.0.5.a,

which requires

inservice testing to be performed in

accordance

with Section

XI of the

ASME Boiler and Pressure

Vessel

Code for

ASME Code Class

1,

2 and

3 pumps

and valves

(323'/94-18-01).

This is

a

Severity

Level

IV violation.

4

PLANT MAINTENANCE

(62703)

During the inspection period,

the inspector

observed

and reviewed selected

documentation

associated

with maintenance

and problem investigation activities

listed below to verify compliance with regulatory requirements,

compliance

with administrative

and maintenance

procedures,

required quality assurance

and

quality .control department

involvement,

proper

use of safety tags,

proper

equipment

alignment

and

use of jumpers,

personnel

qualifications,

and proper

retesting.

Specifically, the inspector witnessed

portions of the following maintenance

activities:

Unit

1

~

Diesel

Generator

1-1 Fuel Oil Level Control Valve (LCV-88) Maintenance

~

Eagle

21

Loop Processor

Board Replacement

~

Diesel

Generator

1-1 Overcrank Alarm Troubleshooting

Unit

2

~

Spent

Fuel

Pool

Swing Gate

Seal

Replacement

~

Spent

Fuel

Pool

Pump 2-2 Maintenance

Conclusion

The inspected

maintenance

activities appeared

to have

been

performed properly.

Administrative and maintenance

procedures

appeared

adequate

and were followed.

There

was appropriate quality assurance/quality

control department

involvement.

Technician

knowledge

and understanding

of the

activities appeared

appropriate

during discussions

involving the various

activities.

Radiation protection practices

appeared

appropriate.

0

5

SURVEILLANCE OBSERVATIONS

(61726)

Selected

surveillance tests

required to,be performed

by the Technical

Specifications

were reviewed

on

a sampling basis to verify that:

(1) the

surveillance tests

were correctly included

on the facility schedule;

(2)

a

technically adequate

procedure

existed for performance of the surveillance

tests;

(3) the surveillance tests

had

been

performed at

a frequency specified

in the

TS;

and

(4) test results satisfied

acceptance

criteria or were properly

dispositioned.

Specifically, portions of the following surveillances

were observed

by the

inspector

during this inspection period:

Unit

1

~

TP TB-9423;

Centrifugal

Charging

Pump

1-2

CCW Flow Measurements

Unit

2

STP M-4;

Routine Surveillance

Test of the Auxiliary Building Safeguards

Air Filtration System

STP I-12B;

Channel

Calibration

Feed

Flow, Steam

Flow

and

Steam

Pressure

Channels

5. 1

STP I-12B

Channel

Calibration

Feed

Flow

Steam

Flow and

Steam

Pressure

Channels

On July 13,

1994, during surveillance testing which calibrates

pressure

and steam flow analog

channels,

and associated

circuitry, two steam

flow channels

were not removed

from service prior to inserting simulated

inputs to obtain "as-found" readings.

As

a result,

2-2

experienced

changes

in level

and feed flow.

A control

room operator,

aware of

the ongoing testing,

noted the changes

in parameters

associated

with Steam

Generator

2-2 testing

and initiated action to secure

from the testing

and

restore

system parameters.

To accomplish the surveillance testing,

several

procedures

were utilized

including:

~

STP I-12B1;

Removal

From Service

Feedflow,

Steamflow

and

Pressure

Channels'TP

I-12B3; Calibration Analog Electronics

Pressure

(Flow Compensating)

STP I-12B4; Calibration Analog Electronics

Feedflow

0

STP I-12B6; Calibration - Comparators

Feedflow,

Steamflow

and Pressure

Channels

STP I-12B1 provides procedural

guidance for removal of a steamflow or feedflow

channel

from service.

The technician misunderstood

the applicability of the

step concerning

the steamflow instrument,

since the instruments

which were

being calibrated

were

pressure

and feedflo'w.

Therefore,

the

technician omitted removing the steamflow channels

from service.

When

preparing to take the "as-found". readings,

the technician

questioned

the

need

to take data for the steamflow instrument since this instrument

was not being

calibrated.

The technician

stopped

the procedure

and discussed

this with his

foreman.

The foreman did not see

a problem with obtaining the data.

It was

not communicated

that the steamflow instrument

had not previously been

removed

from service..

During the performance of the "as found" trip and reset

values

for a high steam flow comparator,

simulated

steam flow inputs were inserted.

The response

of the Digital Feedwater

Control

System

and the resultant

change

in steam generator

parameters

was noted

by the con-.rol

room operator,

who

stopped

the surveillance.

Conclusion

The procedural

step which removes

the steam flow instrument

from

service

was read

and reviewed,

but the incorrect decision

was

made.

The

licensee

is revising the surveillance

procedure

requirements

for removal of

these

instruments

from service for maintenance

and testing.

Prompt operator

response

to changing

parameters

prevented

an improperly

performed surveillance

from impacting plant operation.

Plant equipment

was

not negatively affected.

The failure to adequately

plan

and perform the

surveillance is

a violation of TS 6.8. 1, which states,

in part, that written

procedures

shall

be established,

implemented,

and maintained

covering

applicable .procedures

recommended

in Appendix A of Regulatory

Guide 1.33,

Revision 2, dated

February

1978.

Appendix

A of Regulatory

Guide 1.33,

Revision

2 recommends

procedures

covering surveillance testing;

preventative

maintenance;

and startup,

operation,

and shutdown of safety-related

systems.

Contrary to this requirement,

on July 12,

1994;

steam flow instruments

were

not removed

form service prior to testing

as required

by Step 6.2 of

,

STP I-12BI.

Since this violation was identified by the licensee,

and other

criteria of Section VII.B(2) of the Enforcement Policy were satisfied, this

.

violation was not cited (323/94-18-02).

5.2

STP M-4

Routine Surveillance Test of the Auxiliar Buildin

Safe uards

Air Filtration

S stem

~Back round

Ventilation system charcoal

adsorber

beds

are required to be

periodically sampled

to verify that carbon allows only a small percentage

of

methyl iodide penetration.

had

been

analyzed

in accordance

with ASTM D-3803-79,

"Standard

Test Method for Nuclear Grade Activated

Carbon."

NRC Information Notice

( IN) 87-32 identified 'problems with the test

methodology in ASTM D-3803-79.

ASTM D-3803-89 is recognized

by industry

as

being

a more accurate

analysis of methyl iodide penetration.

The licensee,

after performing

a review of ASTM D-3803-89,

adopted

the revised

standard for

0

'

-10-

the analysis of charcoal

bed samples.

The revised version .was considered

acceptable

since it provided

more conservative

results

than existing

ASTM D-3803-79 requirements,

The

new analysis,

performed at

a lower

temperature,

reduces

the reaction rate

between

the charcoal

and the iodine

and,

as

a result,

increases

the organic iodine penetration

and provides

a more

representative

indication of charcoal

performance

during

an accident.

The

licensee

adopted this updated

method of analysis for the first time for the

Unit

1 charcoal

samples

taken during Refueling Outage

1R6.

R'esults of Unit

1

charcoal

analysis

indicated

a much higher percentage

of methyl iodide

penetration

than the previous

samples.

The licensee's

decision to implement

the revised

standard test method for nuclear grade activated

carbon is viewed

by the

NRC as proactive

and positive.

Charcoal

Bed Service

TS 4.7.6. I.c requires

the licensee

to obtain

a charcoal

sample after each

720 hours0.00833 days 0.2 hours 0.00119 weeks 2.7396e-4 months of ventilation flow through the auxiliary building

ventilation system

(ABVS) charcoal

bed.

In the past,

the licensee

has

normally performed

these

samples

during outages.

During the current- Unit 2

'perating

cycle,

an unexpectedly

high number of in-service

hours

accumulated

on the charcoal

adsorber

bed during the installation of a damper position

switch design

change.

To support the design

change installation, it was

necessary

to operate

the Unit 2 auxiliary building ventilation in safeguards

mode,

exhausting

through the charcoal

adsorber

bed.

Accumulation of in-

service

hours during the previous refueling outage,

combined with delays

in.

the accomplishment of the design

change,

resulted in the charcoal

adsorber

bank remaining in service for longer than anticipated.

Charcoal

Bed Surveillance

During the routine surveillance test of the

auxiliary building safeguards

air filtration system,

performed

on June

11,

1994,

the licensee identified that the charcoal

adsorber

bed

had

been in

service for over 780 hours0.00903 days 0.217 hours 0.00129 weeks 2.9679e-4 months .

If the

ASTM D-3803-89

sample results

indicated

unacceptably

high methyl iodide penetration,

such results

would require

declaring the charcoal

adsorber

bank inoperable

and replacing the charcoal

within a 24-hour period.

Part of the scope of STP M-4, "Routine Surveillance

Test of the Auxiliary

Building Safeguards

Air Filtration System," is to verify that operation of the

charcoal

adsorber

bank

has not exceeded

720 hours0.00833 days 0.2 hours 0.00119 weeks 2.7396e-4 months since the last laboratory

analysis of a representative

carbon

sample.

The

NRC identified that the

procedure

is deficient in that it does

not preclude

exceeding

the

720 service

hours

between

samples.

TS 4.7.6. l,c requires that the laboratory

sample results

be verified within 31

days after sampling.

The licensee

determined that it would be possible to

comply with the sample results

time requirements,

in this particular

situation,

by calculating the date at which the charcoal

adsorber

bed exceeded

720 hours0.00833 days 0.2 hours 0.00119 weeks 2.7396e-4 months of service

and

assuming that the 31-day period for obtaining the

results

started

on that date.

Evaluation of Charcoal

Sam le Results

After obtaining the initial sample

results for the Unit 2 auxiliary building charcoal

adsorber

bed,

which

0

revealed

an increase

in the methyl iodide penetration,

evaluations

of the

operability of other charcoal

adsorber

beds

were not immediately performed.

Following receipt of confirmatory sample results,

the licensee

concluded that

it was likely that the Unit 2 Fuel Handling Building (FHB) E-5 charcoal

bed

was inoperable

and declared it as such.

In the interim period,

between

obtaining the first and

second

sample results,

spent fuel

was

moved in the

Unit 2 spent fuel pool with the

FHB E-5 charcoal

bed in service.

The licensee

has

scheduled

replacement

of the

FHB E-5 charcoal

in the near future, although

analysis of the charcoal

sample

has not been completed.

Licensee

Nana

ement

Involvement

After the discovery that the Unit 2 auxiliary

building charcoal

adsorber

bed exceeded its sample periodicity, thus requiring

a charcoal

sample

and analysis, it was evident that licensee

management

suspected

that sample results

would be

above the allowed limit for methyl

iodide penetration.

Nore timely evaluation of the initial Unit

1 charcoal

sample results

could have alerted

the licensee of the significance of those

results

regarding

the performance of other charcoal

beds.

The licensee

has

completed

a review of the operational

status of all remaining safety related

ventilation charcoal

beds.

The

FHB E-5 charcoal

bed

has

been declared

inoperable

and the licensee

has preliminarily evaluated all others

as

operable.

This evaluation

was

based either

upon the time the

bed

has

been in

service

since charcoal

replacement

and previous

ASTN D-3803-79

sample

analyses

or sample

analyses

using the

ASTN 0-3803-89

method.

In. addition, the licensee

has initiated procedures

to closely track charcoal

bed inservice

hours to

prevent exceeding

required

sampling intervals in the future,

Safet

Si nificance

The licensee's

analysis of the as-found condition

concluded that the Unit 2 auxiliary building charcoal

bed iodine penetration

was outside of the design basis.

This was reported to the

NRC in a 4-hour

nonemergency

report

made

on July 7,

1994.

The licensee

has since corrected

the condition by replacement

of the charcoal

bed.

Conclusion

The licensee's

procedures

for verification of charcoal

adsorber

bed operability did not ensure that charcoal

samples

were obtained at the

specified periodicity.

The failure to implement

a procedure

which ensures

that the charcoal

adsorber

bed is sampled

at the required periodicity is

a

violation of 10 CFR Part 50, Appendix 8, Criterion V, which requires that

activities affecting quality be prescribed

by procedures

appropriate

to the

circumstances

and shall

be accomplished

in accordance

with established

procedures.

Since this violation was identified by the licensee,

and other

criteria of Section VII.B(2) of the Enforcement Policy were satisfied, this

violation was not cited (323/94-18-02).

6

ONSITE ENGINEERING (37551)

6. 1

Insufficient

CCW Flow to

Pum

Coolers

~Back round

The

pump includes five component

coolers

wi>> ch are cooled

by

CCW:

a gear oil cooler,

lube oil cooler,

two seal

coolers,

and

a seal

plate

cooler.

Each cooler

has

an upstream

CCW isolation valve.

The lube oil

-12-

cooler,

gear oil cooler,

and seal

plate cooler have

a

common discharge

header

throttle valve which, until recently,

was throttled to control the flow to the

coolers.

In 1990,

a licensee

Safety

System Functional Audit and

Review

(SSFAR) questioned throttled

CCW flow to the

CC pumps.

The audit

raised

the concern that throttled

CCW flow may not provide design

basis flow

rates

to the individual components

during accident conditions

and heat loads.

The resolution of this audit finding accepted

the throttled

CCW condition

and

.

was based,

in part,

on

an engineering calculation which contained

two

nonconservative

assumptions.

The licensee

now considers

the resolution of the

audit finding,

and acceptance

of throttled

CCW flow, to be in error.

On June

29,

1994,

a I-hour nonemergency

report was

made to the

NRC regarding

past operability of the

CC pumps.

The report stated that, previously,

CCW

flow to the

CC pump coolers

had

been throttled during normal operation.

This

would not have'rovided

adequate

cooling to the

CCW gear oil cooler during

a

design

basis accident.

CCW was throttled to maintain lube oil temperatures

within the vendor

recommended

temperature

band

and, therefore,

maintain proper

viscosity during normal

CC pump operation.

Recent licensee

investigation of

pump lube oil characteristics

revealed that there is very little change

in

viscosity, for the type of oil used,

over the entire range of possible

CCW

temperatures.

Therefore, throttling

CCW flow to maintain lube oil

temperatures

was

no longer

a concern.

Pum

CCW Flow Testin

Prior to the I-hour nonemergency

report, preliminary

CCW system flow rate testing

had

been completed.

The tests

indicated

potentially insufficient

CCW cooling to the

CC pumps under design basis

conditions.

After the preliminary testing,

the

CCW throttle valve on the

common discharge

header of the

CC pump gear oil, bearing oil, and seal

plate

coolers

was fully opened.

A prompt operability assessment

was initiated to

document

the adequacy

of the existing cooling flow with the

common outlet

throttle valve fully open.

I

The licensee

is continuing testing

and calculations

to support proper

adjustment of flow to each of the coolers.

Flow is being measured

by an

acoustic

sensor

instrument,

since the system

does not have installed equipment

which measures

the flow rates.

The throttling of

CCW flow during testing is

accomplished

using the throttle valves to individual coolers.

The licensee

plans to use these test results to determine final valve throttle positions

for establishing

adequate

flow rates to the

CC pump components

cooled

by

CCW.

Conclusion

The licensee

resolution of issues

raised

in the

1990 safety

system

functional audit

and review regarding

the

CCW system incorrectly accepted

the

adequacy of the existing throttled cooling flow,

The initial decision" to

throttle. the

CCW supply to the

CC pumps

does not appear to have

been properly

reviewed prior to establishing

the throttled configuration procedure.

The

licensee's

interim actions,

which have

been

communicated

to the

CC pump

vendor,

appear to provide adequate

cooling to the

CC pumps.

Further

NRC

review of this issue will be concluded during the review of the Licensee

Event

Report

(LER).

0

-13-

7

PLANT SUPPORT ACTIVITIES

(71750)

The inspectors

evaluated

plant support activities

based

on observation of work

activities, review of records,

and facility tours.

The inspectors 'noted the

following during this evaluation.

7. 1

Fire Protection

During inspection of fire barrier penetration

seals,

the .inspectors

observed

a

break in the sealed barrier in the floor of the Unit 2 cable spreading

room.

The inspectors

learned that the breach

was

a resul,t of work ongoing in

preparation of installing conduit for part of the

new Eagle

21 reactor

protection

system,

scheduled for completion during the upcoming Unit 2

refueling outage.

The licensee

was implementing the appropriate

hourly fire

watch compensatory

measures

for the breach,

7,2

Radiation Protection Controls

The inspectors

periodically observed

radiological protection practices

to

determine whether the licensee's

program was being implemented

in conformance

with facility policies

and procedures

and in compliance with regulatory

requirements.

The inspectors

also observed

compliance with radiation work

permits,

proper wearing of protective equipment

and personnel

monitoring

devices,

and personnel

frisking practices.

Radiation monitoring equipment

was

frequently monitored to verify operability and adherence

to calibration

frequency. 'everal

resident

inspector tours in the radiological control

area

revealed

minor cases

of deficient contamination control practices

in the

140-foot level of the

FHB surface

contaminated

areas

(SCAs).

On several

occasions,

an area

where work was being performed

on ventilation components

and ducting was poorly controlled.

At several different locations,

material

from inside the

SCA crossed

over the

SCA boundary.

Similar deficiencies

had

been previously noted in the

same

area

on several prior occasions.

These

deficiencies

and the past

poor performance

was point'ed out to

plant'anagement,

and action

was initiated to correct the deficiencies.

Conclusion

It was apparent

in each

instance that action

had

been initiated to

correct the deficiency,

but the corrective action

was not always

adequate

to

prevent recurrence.

Because prior corrective action did not result in

effective long-term resolution,

additional

management

involvement is needed.

7.3

Plant Housekee

in

The inspectors

observed

plant conditions

and material/equipment

storage

to

determine

the general

state of cleanliness

and housekeeping.

Housekeeping

in

the radiologically controlled area

was evaluated

with respect

to controlling

the spread of surface

and airborne contamination.

On one plant tour the inspectors

noted

a small puddle of liquid on the floor

near the Unit

1 Reciprocating

Charging

Pump 1-3.

The inspectors

informed

Health Physics

and noted

on their next tour that the puddle

was gone.

-14-

The inspectors

observed

a weakness

in general

plant cleanliness

in some areas.

'his

was of particular concern

in the radiologically controlled areas of the

plant.

Two examples

were

as follows:

~

Rubber gloves

and glove liners were left within the

SCA on the skid of

Pump 2-1.

~

A significant portion of the floor in the Unit 2 turbine-driven

auxi,liary feed

pump room was stained

due to

a previously leaking

component.

7.4

~Securit

,The inspectors

periodically 'observed

security practices

to ascertain

that the

licensee's

implementation of the security plan

was in accordance

with site

procedures,

that 'the search

equipment

at the access

control points

was

operational,

that the vital area portals

were kept locked

and alarmed,

and

that personnel

allowed access

to the protected

area

were

badged

and monitored

and that monitoring equipment

was functional.

The inspectors

noted

no

problems

in this area during this inspection period.

7.5

Conclusion

Overall, plant support

performance

was good during the inspection period

and

remained

unchanged

from the last period.

Inspectors

observed

that

housekeeping

practices

in contaminated

areas

were generally

adequate,

and

could

be improved.

8

FOLLOWUP ENG INEERING (92903)

8.1

Closed

Followu

Item 323 93-30-01: Definition of Safe

Shutdown

Earth

uake

SSE

During review of SSE requirements

for Diablo Canyon,

an inspector

noted that.

SSER 7, dated

Hay 1978,

and

SSER 31, dated

June

1991,

implied that the

NRC

considered

that the

SSE for Diablo Canyon

was the

maximum credible force of an

generated

from the Hosgri fault, with a peak ground

acceleration

(PGA) of 0.75g.

However,

the licensee's

Updated

Final Safety

Analysis Report

(UFSAR), Section

3, indicated that the

SSE for Diablo Canyon

was the

DDE, with a

PGA of 0.4g.

The inspector did not identify any failure

of the licensee

to comply with any

NRC seismic requirements.

The inspector

initiated

a followup item for further

NRC review of the definition of SSE at

Diablo Canyon.

Subsequent

to the initial inspection,

the

NRC staff reviewed the seismic

licensing basis for Diablo Canyon

and clarified that the

SSE for Diablo Canyon

was the double design

(DDE) as described

in the

UFSAR, Section 3.

The

NRC staff noted that all

new modifications required analysis for both the

DDE and Hosgri earthquakes.

The

NRC staff also noted that the

NRC had

0

-15-

required the licensee

to ensure

they could safely shutdown

both units

following either

a Hosgri or

DDE earthquake.

Based

on

NRC staff's

agreement

with the licensee's

definitions for the

SSE at Diablo Canyon,

the inspector

concluded that the followup item was resolved.

9

FOLLOWUP

ON CORRECTIVE ACTIONS FOR VIOLATIONS

(92702)

9.1

Closed

Violation 50-323 94-11-01:

Failure to Plan

and Perform

Maintenance

in Accordance with Written Procedures

The

NRC identified

an instance

where the licensee failed to establish

a

clearance

during

a repair of the Unit 2 reactor coolant

system safety

injection inlet to

RCS

Loop 2-3, which was the subject of a citation with NRC

Inspection

Report 50-323/94-11.

In

a letter dated

June

20,

1994,

the licensee

acknowledged

the violation and stated that corrective action

had

been

completed for the specific instance cited

and that further action to prevent

recurrence

had

been initiated by revision of the licensee

procedure

AP C-4S1,

"Temporary Modification Control - Plant

Jumpers

and

METE."

The inspector

reviewed

and verified these actions.

The licensee's

actions

appeared

to be

appropriate

and properly implemented.

10

IN-OFFICE REVIEW OF

LERS

(90712)

The following LERs were closed

based

on in-office review:

~

275/94-14,

Revision

0

Unplanned

DG Start

(ESF Actuation)

Due to

Shorting Indicating Lights

275/94-10,

Revision

0

Main Bank Phase

"C" Transformer

Degraded

Condition

275/93-012,

Revision

0

ASW System Potentially Outside

Design Basis

275/93-012,

Revision

1

ASW System Potentially Outside Design Basis

275/93-012,

Revision

2

ASW System Potentially Outside

Design Basis

1

PERSONS

CONTACTED

ATTACHMENT 1

Licensee

Personnel

G.

N

W

R.

T.

J.

G

S.

W.

S.

B

J

C

C

J.

R.

J.

K

'.

M.

J.

D

M.

p.

S.

B.

J

D.

D

M. Rueger,

Senior Vice Pres, ident

and General

Manager,

uclear

Power Generation

8'usiness

Unit

H. Fujimoto, Vice President

and Plant Manager,

Diablo Canyon Operations

P.

Powers,

Manager,

Nuclear equality Services

L. Grebel,

Supervisor,

Regulatory

Compliance

S.

Bard, Director, Mechanical

Maintenance

M. Burgess,

Director,

Systems

Engineering

G. Chesnut,

Reactor

Engineer Supervisor

G. Crockett,

Manager,

Technical

and Support Services

R. Fridley, Director, Operations

W. Giffin, Manager,

Maintenance

Services

D.

Grammer,

Engineer,

Systems

Engineering

'R. Groff, Director, Plant Engineering

D. Harbor,

Engineer,

Systems

Engineering

A. Hays, Director, Onsite equality Control

W. Hess, Assistant Director, Onsite Nuclear Engineering

Services

R. Hinds, Director, Nuclear Safety Engineering

A. Hubbard,

Engineer,

Regulatory Compliance

C. Kelly, Mechanical

Group Leader,

Nuclear Engineering

Services

E.

Leppke, Assistant

Manager,

Technical

Services

J.

McCann,

General

Foreman,

Instrument Maintenance

B. Miklush, Manager,

Operations

Services

D. Nowlen, Director, Instrumentation

and Controls

T. Nugent,

Engineer,

Regulatory

Compliance

R. Ortore, Director, Electrical Maintenance

H. Patton,

Director, Technical

and Support Services

A. Shoulders,

Director, Onsite Nuclear Engineering

Services

P. Sisk, Senior Engineer,

Regulatory

Compliance

W. Spencer,

Power Production

Engineer,

Plant Engineering

R. Stermer,

Engineer,

Systems

Engineering

A. Taggart, Director, Onsite equality Assurance

1.2

NRC Personnel

M.

M. Miller, Senior Resident

Inspector

Tschiltz, Resident

Inspector

Denotes those attending

the exit meeting July 27,

1994.

In addition to the personnel

listed above,

the inspectors

contacted

other

personnel

during this inspection period.

2

EXIT MEETING

An exit meeting

was conducted

on July 27,

1994.

Ouring this meeting,

the

inspectors

reviewed the scope

and Findings of the report.

The licensee

acknowledged

the inspection findings documented

in this report.

The licensee

did not identify as proprietary

any information provided to, or reviewed by,

the inspectors.

ATTACHMENT 2

ACRONYHS

. ASNE

FHB

IN

KV

LER

SCA

SSER

SSFAR

STP

TS

UE

UFSAR

auxiliary building ventilation system

American Society of Hechanical

Engineers

centrifugal

charging

(high head injection)

component

cooling water

double design

fuel handling building

instrumentation

and controls

Information Notice

kilovolts

licensee

event report

peak ground acceleration

reactor coolant

system

residual

heat

removal

surface

contamination

area

safe

shutdown