ML16342D306

Leaka

e . Unit

1

II

a.

Ins ection

Sco

e

71707

The inspector

reviewed the licensee's

actions regarding

elevated

Updated Final Safety Analysis Report

leakage identified in Unit

1 on March 4.

b.

Observations

and Findin

s

On March 4, at 6:07 a.m., Unit

1 operators

observed

level decreasing

in

the volume control tank.

The leakage

was estimated

to be between

5-7

gpm.

The licensee

promptly investigated

and determined that the leakage

was from the packing gland of the centrifugal charging

Pumps

1-1

and

1-2

flow control Valve

(FCV) CVCS-1-FCV-128.

Operators

opened

valves in the

bypass line and closed

Valve CVCS-1-FCV-128.

At 8: 14 a.m.,

operators

isolated

the

FCV.

They then performed

a

RCS leak rate calculation

and

confirmed that the leak had

been isolated.

As

a compensatory

action,

an

operator

was stationed

near the centrifugal charging

pump in order to

restore recirculation flow in the event it had

become

necessary

to start

the second

pump.

The licensee initiated Action Request

(AR) A0394938 to document

the

event

and the licensee's

prompt operability assessment

(POA)

and to

initiate corrective maintenance.

The inspectors

reviewed the

POA and

determined that it appropriately

addressed

the relevant

TS requirements.

The inspectors

determined

that

TS requirements

were met while the

FCV

was isolated

and the bypass line was in service.

Conclusions

Operations

appropriately identified and stopped

the leakage within the

time allowed in the TS.

The

POA was thorough

in addressing

all relevant

operability issues.

Startu

Observations

Unit

1

Ins ection

Sco

e

71707

The inspectors

observed

startup activities in the Unit

1 control

room on

March

17 and

18.

The inspectors

observed

the

use of portions of the

following procedures:

OP L-3, Revision

15,

"Secondary

Plant Startup"

OP L-4, Revision 33,

"Normal Operation

at Power"

OP L-O, Pevision

34,

"Mode Transition Checklists"

OP C-3: II, Revision

17,

"Hain Unit Turbine Startup"

Observations

and Findin

s

The secondary

plant startup

observed

on March

17 was well controlled by

the Senior Control Operator.

Communications

were clear

and the

evolution proceeded

with caution.

Operators

questioned

indications

and

were observed

to use self-verification techniques.

During the secondary

plant startup,

the operators

noted several

weaknesses

with the procedures.

Although these

problems did not appear

to have

any safety consequence,

several

procedural

steps

were written to

require

an exact value rather than

a range of acceptable

values.

Following the evolution operators

submitted

several

pages of comments

which identified areas

where procedural

improvements

could

be made.

Procedure

OP L-3 provides instructions for raising reactor

power from

0 to 20 percent

(approximately

220 HWe).

Procedure

OP L-4 provides

instructions for power changes

between

20 percent

and

100 percent

power.

OP'-3,

Step 6.37 required operators

to proceed

to

OP L-4 after all of

the steps of OP L-3 were complete.

The inspectors

noted that the

operators

had raised

power to 29 percent

the morning of March

18 without

completing the required

steps

in

OP L-3.

The steps that

had not been

completed

were for the alignment of the feedwater

and condensate

system

for operation at power levels of greater

than

50 percent.

Although

there

was

no safety

consequence

for not performing the steps

at that

point in time, the inspectors

were concerned

that operators

did not note

their actions

were contrary to procedures.

Additionally, the

prerequisites

of Procedure

OP L-4 had not been

completed prior to

beginning

some of the steps.

c.

Conclusions

The secondary

plant startup

was well controlled

and operators

provided

numerous

comments for procedural

improvements.

Operators failed to

follow procedures

for raising reactor

power.

Oversight

and direction of

the evolution by the shift foreman did not prevent this from occurring.

The failure to complete all of the requirements

for transition from

Procedure

OP L-3 to

OP L-4 is

a violation of TS 6.8. 1

(VIO 50-323/96006-01).

01.4

Axial Flux Distribution

AFD

Limits Curve

a.

Ins ection

Sco

e

71707

On April 1, the inspectors

conducted

a walkdown of the Unit

1 control

panel to verify operation

in accordance

with TS requirements

and

licensee

procedures.

b.

Observations

and Findin

s

The

AFD Limits Figure posted

on the control

panel

was noted to have

exceeded

the issued-for-use

period of 30 days without having been,

reverified.

Administrative Procedure

AD2. ID1, "Procedure

Use

and

Adherence,"

Step

5. 1. I.b specifies

a maximum in-use period for

procedures

of 30 days

and requires that procedures

in use for longer

than

30 days

be verified to be the current revision

and remarked.

After the inspectors

noted the problem the figure was verified to be

up

to date.

Normally this matter would be considered

a minor issue of low

safety significance

and therefore

would not be discussed

in an

inspection report;

however, this was

a recurring problem which the

inspectors

had raised

in the previous inspection period.

c.

Conclusions

The failure to verify the in-use

AFD Limits Figure posted at the Unit

1

control

panel

every 30 days

as required

by Administrative Procedure

AD2. IDl was identified as

a noncited violation of TS 6.8. 1.

This

failure constitutes

a violation of minor significance

and is being

treated

as

a noncited violation, consistent with Section

IV of the

NRC

Enforcement Polic

(NCV 50-275/96006-02).

02

Operational

Status of Facilities

and Equipment

02. 1

En ineered

Safet

Feature

S stem Walkdowns

Ins ection

Sco

e

71707

tJ

The inspectors

used

Inspection

Procedure

71707 to perform

a detailed

walkdown of accessible

portions of the control

room ventilation system

(CRVS).

The inspectors

also reviewed the applicable portions of the

b.

licensee's

(UFSAR) associated

with

the

CRVS and design criteria memorandum

(DCH) S-23F,

Revision 0,

Change

11, "Control

Room Heating, Ventilation,

and Air Conditjoning

System."

Observations

and Findin

s

The inspectors

noted

on April 8 that the material condition of system

components

and area

housekeeping

of the accessible

portions of the

CRVS

were generally

good.

A detailed

walkdown of the system configuration

and its components

found no discrepancies

with the current as-built

mechanical

drawings.

The inspectors

reviewed the applicable portions of the licensee's

and the system

DCH and found several

discrepancies

where the documents

did not reflect current design

and operation.

Table 9.4-1 of the

describes

the design

parameters

of the

CRVS filter train including

an

85 percent

removal efficiency by the charcoal filter beds for methyl

iodine,

an organic form of iodine.

This appears

to be

a typographical

error.

The 85 percent

value is inconsistent

with the listing in fable

9.4-2 for removal efficiency, the licensee's

analysis for determining

postaccident

doses

to control

room personnel,

and the acceptance

criteria in the associated

surveillance

procedure.

Additionally,

Table 9.4-2 referenced

information contained

in Table 9.4-3;

however,

Table 9.4-3

had

been deleted

from the

Review of the

DCM for the system revealed that it had not been

updated

'o

refl,ect the impact of the installation of the third emergency diesel

generator

(EDG)

on Unit 2.

In addition,

11 interim design criteria

memorandum

changes

had

been

made to the

DCH since its original issuance

, in 1992.

However,

these

interim design criteria memorandums

had not

been

incorporated

into the

body of the

DCH and only existed

as

pen-and-ink

attachments,

making it difficult to'xtract technical

information'he licensee

has identified problems with maintenance

of

the

DCHs through its

own self-assessment

program.

Conclusions

The configuration of the

CRVS was in accordance

with the licensee's

UFSAR and the as-built mechanical

drawings'.

Material condition of the i

system

was generally good.

The discrepancies

identified in the

and

DCM were considered

to be of low safety consequence;

however,

they

were indicative of a less-than-effective

pr'ogram to review and update

these

documents.

These failures to update

the

UFSAR are considered

additional

examples of the problem described

in Section

E7. 1 and will be

included in the Unres'olved

Item (URI 50-275/96006-06).

k

08

miscellaneous

Operations

Issues

(92700)

08.1

'

en

Violation 50-275 9428-01:

Failure to follow EDB test procedure.

Following the inadvertent

loss of residual

heat

remover during

IR6

testing,

the

NRC issued

a violation.

In order to track and develop

corrective actions

in the response

to the violation the licensee

issued

a nonconformance

report

(NCR).

The licensee's

response

to the violation

dated

December

9,

1994, detailed corrective actions

which included:

1.

Review and revisi'on of programs that place tags

on main control

boards

to prevent information from being obscured

on in-service

equipment.

2. Revision of Administrative Procedure

OPI.DC12,

"Conduct of Routine

Operations" to:

a.

require that, during refueling outages

where significant

outage activities are in progress,

a dedicated

licensed operator

will be in the control

room with no assigned

duties other than

monitoring overall plant conditions;

b.

define the threshold of operating evolutions

where it is

expected

that the shift foreman

be in. the control

room directly

supervising

the evolution;

and,

c.

chan'ge

the attachment

that describes

tailboard briefings to

place

more emphasis

on the "big picture" discussion.

The licensee

had indicated that the first corrective action review would

be complete

by April 1,

1995,

and

OP1.DC12 would be revised

by

February

1,

1995.

The inspectors

reviewed the changes

to the procedures

discussed

in the

response

to the violation.

Discussions

with the Operations Director

revealed that the corrective actions

associated

with the first action

had not been

completed,

The programs that place tags

on main control

boards

had not been revised

and there

was

no ongoing effort to do so.

The

NCR had

been closed without completing all of the actions

discussed

in the licensee's

response

to the violation.

'he

remaining actions, were subsequently

completed;

however,

they had not

been

completed within the time frame indicated

by the licensee.

The

last revision to OPI.DC12

was completed

in October

1995,

over 8 months

after the date indicated

by the licensee.

The inspectors

concluded that the licensee

had failed to take all of the

actions described

in the response

to the Notice of Violation.

The

failure to complete

these corrective actions is of particular concern

since they were initiated in response

to an incident that involved the

inadvertent

loss of core cooling.

Violation 50-275/9428-01

remains

open

pending further review,of"corrective actions

taken

by the licensee.

r

08.2

Closed

VIO 50-275 95016-01:

(A) failure to follow procedure

during

reactor

vessel

draindown to half-loop operation;

(B) failure to follow

procedure

during operational

checks of the source

range nuclear

instruments.

The,inspector's

reviewed the licensee's

response

to the Notice of

Violation, dated

February

15,

1996,

and discussed

with the licensee

the

corrective actions

taken in response

to Part

A of the violation.

The

inspectors

also verified that the licensee

had completed

the long-term

corrective actions

as stated

in its response.

Associated with this violation, the inspectors

noted in

NRC Inspection

~

Report 50-275/95016 that

a potential

root cause of the violation was

an

ineffective'reevolution tailboard.

The licensee justified the

shortened

tailboard observed

by the inspectors

based

upon discussions

held between

the operators prior to the tailboard.

The licensee

concluded that the prerequisites,

precautions

and limitations had

been

reviewed in these discussions.

However, discussions

of this type did

not meet the licensee's

expectations

for conduct of a tailboard.

The

operations director agreed that informal discussions

are appropriate for

augmenting

operator

knowledge,

but should not be relied

upon in lieu of

conducting

a tailboard.

The inspectors

concluded that the actions

taken

by the licensee

to

prevent recurrence

of the violation appeared

adequate

to address

the

root causes.

Ml

Conduct of Maintenance

Ml. 1

Maintenance

Observations

II. Maintenance

a.

Ins ection

Sco

e

62703

The inspectors

observed all or portions of the following work

activities:

C0142927

Radiography of CVCS-1-RV-8116 Inlet Piping

C0142601

Install/Remove

Ground

Buggy 8 52HF13

C0142875

Radiography of RCP 1-2 diffuser

TP TD-9607

Providing Vital 125-Vdc Power

From SD21, to SD22 Vital

Loads

C0143460

Replace

Eagle

21 Analog Input Board

-7-

b.

Observations

and Findin

s

The inspectors

found the work performed

under these activities to be

professional

and thorough.

All work observed

was performed with the

work package

present

and in active use.

Technicians

were experienced

and knowledgeable of their assigned

tasks.

The inspectors

frequently

observed

supervisors

and

system engineers

monitoring job progress,

and

quality control personnel

were present

whenever required

by the

procedure.

When applicable,

appropriate radiation control

measures

were

in place.

In addition, selected

maintenance

observations

are discussed

below.

H1.1.1

Re ackin

of FCV CVCS-1-FCV-128

Unit

1

a.

Ins ection

Sco

e

62703

The inspectors

observed

portions of the performance of Work Order

(WO) C0142940,

which directed

unpacking

and repacking the

above valve

per Mechanical

Maintenance

Procedure

(MP) M-51.23, Revision

3A.

This

work was required

due to valve packing failure that resulted

in

significant system

leakage

(see Section 01.1).

b.

Observations

and Findin

s

The

WO directed careful

examination of the packing

upon removal to

attempt to determine

the cause of the failure.

The

WO also directed

engineering

personnel

to be present

during the unpacking

and repacking.

The licensee

determined that the lower rings of packing material

were

substantially missing,

but that the upper rings were intact.

The sequence

of steps

in Procedure

MP H-51.23

was to first install all

the packing rings

and then consolidate

the packing.

However,

maintenance

and engineering

personnel

performed consolidation after

installation of the lower two rings.

Procedure

HP H-51.23 allowed the

engineer

to alter the

sequence

based

on job requirements.

During the maintenance activity, the licensee identified

a small bolt in

the drain line for Valve CVCS-I-FCV-128,

and documented

the condition

in

AR A039468039468

The licensee initiated

an investigation of the potential

origin of the bolt.

c.

Conclusions

There

was good engineering

involvement during unpacking,

inspection,

and

repacking of the valve

and procedures

were followed.

Hl. 2

Surveillance

Observations

k

a. 'ns ection

Sco

e

61726

Selected

surveillance tests

required to be performed

by the

TS 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 the 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.

The inspectors

observed all or portions of the following surveillances:

STP R-18, Revision

15,

"Rod Drop Measurement"

STP l-36-S3TTD, Revision

1, "Protection

Set

Time Delay"

STP

P-AFW-11, Revision

1A, "Routine Surveillance

Test of

Turbine-Driven Auxiliary Feedwater

(AFW)

Pump

1-1

STP V-3PI, Revision

13, "Exercising Hain Feedwater

Regulating

Valves

and Bypass

Valves"

STP V-3P2, Revision 7, "Exercising Main Feedwater

Isolation Valves

FCV-438,

439,

440 and 441"

b.

Observations

and Findin

s

The surveillances

reviewed and/or observed

by the inspectors

were

scheduled

and performed at the required

frequency.

The surveillance

test procedures

were technically adequate

and personnel

were

knowledgeable.

The inspectors

also noted that test results

were

appropriately dispositioned.

In addition,

see specific discussion of other surveillances

observed

by

the inspectors

under Sections

H1.2.1, Hl.2,2, H1.2.3,

and H1.2.4.

H1.2.1

Nuclear

Power

Ran

e Incore Excore Calibration

a.

Ins ection

Sco

e

61726

The inspectors

observed partial

performance of Surveillance

Test

Procedure

(STP)

STP I-2D, Revision 39, "Nuclear Power

Range

Incore/Excore Calibration,"

on Channel

D in Unit 1.

The inspectors

reviewed qualification records for the test performer,

and discussed

the

procedural

guidance with maintenance

supervision.

b..

Observations

and Findin

s

The test performer conducted on-the-job training with two less

experienced

technicians.

The test performer

appeared

to be very

knowledgeable of the nuclear instrumentation

.system

and test procedure.

In preparation for taking data for Table SC-I-2D-AI, Attachment 4.4

(T4), the test performer advised

the trainees

to first set the coarse

adjustment for the highest test point so that the fine adjustment

potentiometer

would be near the middle of its range to allow for maximum

flexibility for subsequent

instrument adjustments.

This guidance

was

not specified

in the surveillance

procedure

and the highest test point

was listed in the middle of the data table.

The inspectors

discussed

this with the test performer

and with a

maintenance

general

foreman.

The discussion

revealed that the test

procedure

would work as written, but may not be efficient and

may not

leave the fine adjustment

in the middle of its range.

However,

operators

only need approximately

20 percent of the range for their use

during operations.

The nuclear instrumentation

channel

was

removed

from service for this

test.

The qualification records of the test performer were appropriate

for surveillances

on the nuclear instrumentation

system.

c.

Conclusions

The test performer

was appropriately qualified.

The test procedure

was

acceptable.

H1.2.2

TS Nonthl

Surveillances

a.

Ins ection

Sco

e

61726

The inspectors

observed

operators

perform portions of Procedure

STP I-10, Revision 26,

"Routine Monthly Checks

Required

by Licenses."

Procedure

STP I-1D is utilized by the licensee

to satisfy various

surveillances

required

by plant TS, including system alignment

verifications

and instrument

channel

checks.

The inspectors

also

reviewed previous records of the performance of Procedure

STP I-lD.

b.

Observations

and Findin

s

The inspectors

reviewed the licensee's

documentation

of the performance

of Procedure

STP I-1D for Unit 2 in January

1996.

Channel

checks of the

Loop

1 hot leg and cold leg temperature

indications at the dedicated

shutdown

panel

were not performed.

A design

change

had

been

implemented

which changed

the temperature

elements

(TE) for RCS

Loop

1 from those

specified

by Procedure

STP I-10.

The operator

noted this discrepancy

in

the remarks section of the procedure checklist without performing

a

channel

check

on the

Loop

1 hot leg and cold leg temperatures

(from

TE-414C

and TE-411B respectively).

Several

levels of review failed to

identify this

as

a missed surveillance.

Following the

inspectors'dentification

of this missed surveillance,

the licensee

reviewed

additional

documentation

and found that these

channel

checks

were

successfully

performed in December

1995

and February

1996.

As

a result

-10-

of the inspectors'indings,

the licensee

revised

Procedure

STP I-D to

reflect the appropriate

sensor

inputs to be checked for RCS

Loop

1 hot

and cold leg temperatures.

The inspectors

noted that the design

change

had

been

implemented

in July 1995.

Steps 3.e.

and 3.h. of Attachment

11. 1 to Procedure

STP I-1D directed

the operator to verify the status of Valves

FCV-360 and 366,

the

component cooling water

(CCW) header

B and header

A return valves

from

the containment

fan cooler units

(CFCUs).

However,

the valves

were

identified in the control

room to be abandoned

in place.

The

CO

explained that

a design

change

had

been

implemented

rendering

them

inoperable

and leaving the valves fully open.

Surveillance

Engineering

personnel

explained that these

valves were

abandoned

in place with air

isolated to the valve actuator

in September

1992 (air inlet valves

closed

and sealed)

and that it was unnecessary

to periodically verify

their position.

The licensee

indicated that the procedure

would be

revised to delete

the requirement

to verify the position of these

valves.

During the CO's channel

check of the

RCS subcooled

margin monitor

(SCMM), the

Loop

1 hot leg temperature

input to the

SCMM indicated

approximately 25'F less

than the hot leg temperature

inputs from Loops

2, 3,

and 4.

The problem was not documented

and the inspectors

questioned

the

CO on its acceptabil'ity.

The

CO rechecked

the parameter

reading

and concurred with the inspectors'bservation.

The

CO

subsequently

initiated

an

AR to investigate

the discrepancy

with the

Loop

1 temperature

input.

The low Loop

1 hot leg temperature

input did

not impact the operability of the

SCMM.

Valid temperatures

from several

core exit thermocouples

and from the other three

loops provided adequate

inputs to the instrument for determining

subcooled

margin.

The inspectors

also observed

an

NO perform those portions of

Procedure

STP I-1D associated

with comparisons

of control

room

instrument readings with the indications at the dedicated

shutdown

panel.

The

NO did not have

a control

room reading for cold-calibrated

pressurizer

level (not

a

TS required instrument).

The inspectors

inquired about

how a channel

check

was accomplished

The inspectors

discussed

that

an alternate

indication of this parameter

was available

in the control

room of which the

NO was unaware.

The inspectors

raised

a concern for the channel

check of the instrument to the shift foreman

(SFM)

and the shift technical

advisor.

The

SFM and shift technical

"advisor concurred with the inspectors'onclusion

and

a valid channel

check was subsequently

performed.

Conclusions

Both an inadequate

procedure

and

an ineffective review of the

surveillance,

resulted

in an improperly performed surveillance of the

RCS hot leg

and cold leg temperature

indications at the dedicated

-11-

shutdown

panel

in January

1996.

This is

a violation of TS 6.8. 1

(VIO 50-323/96006-03).

Hl.2.3

AFW Pum

Full Flow Test

a.

Ins ection

Sco

e

61726

The inspectors

observed

routine full flow testing of the turbine-driven

AFW pump

on March 18.

The inspectors

observed

the use of portions of

the following procedures:

STP P-AFW-ll, Rev.

1A, "Routine Surveillance

Test of

Turbine-Driven

AFW Pump 1-1"

AD13.DC2, Rev.

OA, "Dealing With Gauge Oscillations During the

Performance

of Tests

on Safety Related

Pumps"

b.

Observations

and Findin

s

The

AFW pump testing

was accomplished

in accordance

with the licensee's

requirement

to perform full flow testing following each

Mode

3 entry.

The inspectors

observe'd

the pretest tailboard

and portions of the

pretest

system alignment verification.

During the

AFW pump test,

the" inspectors

noted

a steam leak on the

turbine cross-over line.

The licensee

had previously identified the

leak and

had written an

AR to document

and evaluate

the impact of the

deficiency

on operability.

Although the steam leak did not appear to

impact current operability, it should

be monitored

and evaluated

during

periodic

pump surveillance testing.

Adjustment of the governor

was

needed

to achieve

the

AFW pump differential pressure

specified

by the

procedure.

c.

Conclusions

The testing verified that the turbine-driven

AFW pump was operable.

The

operators

demonstrated

adequate

system

knowledge during the performance

of the test.

Hl.2.4

Main Feedwater

Valve Testin

a.

Ins ection

Sco

e

61726

The inspectors

observed

the exercising of main feedwater regulating

and

bypass

and isolation valves performed in accordance

with the following

procedures:

~

STP V-3P1,

Rev.

13, "Exercising Hain Feedwater Regulating'alves

and

Bypass

Valves"

-12-

~

STP V-3P2,

Rev.

7, "Exercising Main Feedwater

Isolation Valves

FCV-438,

439,

440 and 441"

b.

Observations

and Findin

s

The inspectors

noted that the testing

was well controlled

and

coordinated.

Operators

involved with the testing

were knowledgeable of

the testing requirements.

The procedure

did not provide for restoration

of the monitor light test switch,

thus leaving the switch in the test

position at the

end of the surveillance.

The inspectors

questioned this

and the

SFM directed the operators

to document

the problem

so that the

procedure

could

be revised prior to future performance.

c.

Conclusions

Operators

were knowledgeable of test requirements

and performed the

testing in accordance

with TS requirements.

The

SFM appropriately

dispositioned

an error in the procedure,

III. En ineerin

El

Conduct of Engineering

fl.l

Rod Dro

Testin

Unit

1

a.

Ins ection

Sco

e

37551

8

71707

On March 16, during the Unit

1

178 outage,

the licensee

conducted

control rod drop testing'n

response

to

NRC Bulletin 96-01,

"Control

Rod

Insertion Problems."

The inspectors

reviewed

STP R-1B, Revision

15,

"Rod Drop Measurement,"

AR A0395504,

and

NRC Bulletin 96-01,

observed

portions of the test,

and reviewed the test results.

b.

Observations

and Findin

s

Interactions

between

the system engineer

and the

CO were both formal

and

clear.

During rod withdrawal, the

CO remained

focused

on power

indications.

During the test,

the control console startup rate

(SUR)

meter for source

range

instrument

NI-32 stuck

on its bottom peg

on

several

occasions.

This required the

CO to tap

on the meter face to

restore

free movement of the meter

and was

a distraction to the

CO.

The

CO appropriately

stopped

rod withdrawal

each

time to correct the

problem.

The operators

did not consider

the

SUR meter to be inoperable.

The inspectors

agreed with their assessment.

Following the rod drop testing,

an

AR (A0396189)

was initiated to

investigate

and repair the

SUR meter.

Historical

ARs revealed that

-13-

0

similar problems

were observed with this meter in November

1995

(A0386028).

The corrective action taken in response

to A0386028 was the

replacement

of the meter housing.

A similar problem was also noted in

NRC Inspection

Report 95-16 where

an intermediate

range meter

was found

to be sticking during

a reactor startup.

The licensee

has incorporated

the repair of the

SUR meter into the scope of the next Unit

1 refueling

outage

scheduled

for Hay 1997.

The nuclear instrumentation

system

engineer

pointed out that the

SUR meter received limited use

and that it

provides

no protective trip, permissive or interlock signals.

The review of the test data indicated that all control assemblies

fully

inserted

into the core within the 2.7 seconds

required

by TS.

Comparison with the data

and traces

obtained

from previous testing

indicated that there

were

no significant changes

in rod drop responses.

The average

rod drop time was 1.38 seconds

during the testing

performed

during the

1T8 outage

and 1.39 seconds

from the testing

performed during

the last Unit

1 refueling outage,

1R7.

c.

Conclusions

The rod drop testing

was well controlled

and in accordance

with the

licensee's

surveillance

procedure.

Test results

indicated that rod drop

times

had not significantly changed

since

1R7,

Although the control console

SUR meters

provide

no protective trip,

interlock or permissive signals,

they are relied

upon

by operators

to

provide accurate

indication of reactivity changes

in the nuclear

source

range.

Their continued reliability is essential

for the safe conduct of

evolutions involving positive reactivity .additions

such

as the approach

to criticality.

The licensee's

actions to correct the identified

problems with the

SUR meters will be tracked

as Inspection

Followup Item

(IFI 50-275/96006-04).

E2

Engineering

Support of Facilities

and

Equipment

E2. 1

Diesel

Generator

Lube Oil

Low Tem erature

Alarm

a.

Ins ection

Sco

e

37551

On April 10, the licensee

declared

EDG 2-1 inoperable

based

upon low

lube oil temperature.

The inspectors

reviewed the event with the

on-shift operators

and discussed

the lube oil temperature

requirements

with

EDG system engineer.

The inspectors

also reviewed the licensee's

corrective actions

in response

to

NRC Violation 50-275/95014-01.

b.

Observations

and Findin

s

On April 10, the licensee

was performing scheduled

maintenance

on

EDG 2-3 and its associated

4kV and

480V vital. buses.

The clearance

of

these

buses

resulted

in an expected

loss of power to the 'B'ontactor

panel for

EOG 2-1.

The '8'ontactor

panel

provides

power to the

EDG 2-1 lube oil heaters'.

The lube oil heaters

are designed

to maintain

diesel

lube oil temperature

between

90-120'F.

The loss of power to the

heaters

caused

lube oil temperature

to fall below 90'F.

This condition

was identified by the turbine building auxiliary operator during shift

rounds.

The immediate corrective action taken

by the licensee

was to

operate

EDG 2-1 to raise

lube oil temperature.

The licensee

subsequently

installed

a temporary jumper to provide power to the lube

oil heaters

while maintenance

continued

on

EDG 2-3 and its associated

buses.

EDG 2-2 was operable

during this event; therefore,

operability

of

EOG 2-1

was not required

by TS.

The on-shift operators

staied that

a low lube oil temperature

alarm was

not received

in the control

room.

Further inquiry revealed that the

EDG

low lube oil temperature

alarm setpoint for each of the diesels

was less

than

90oF

NRC Inspection

Report 50-275/95014

documented

a violation For failure to

test the

EDGs at ambient conditions

as required

by TS.

In response

to

the violation, the licensee

revised

the governing

STP to require initial

jacket water

and lube oil temperatures

to be between

90-120

F.

Prior to

this, the operability threshold for lube oil temperature

was 70'F.

The

licensee's

reply to the Notice of Violation, dated

November 27,

1995,

and associated

NCR did not address

raising the lube oil low temperature

alarm setpoints.

Conclusions

Licensee

actions to restore operability of

EOG 2-1 were prompt

and

effective.

The failure to adjust the low temperature

setpoint for the

EDG lube oil low temperature

alarm when the lube oil temperature

for

operability was increased

from 70'F to 90'F was considered

to be

a

weakness.

Core Offload Practices

and

S ent Fuel

Pool Controls

Ins ection

Sco

e

92903

The inspectors

reviewed the licensee's

procedures

and past practices for

core offload during refueling outages.

The inspectors

reviewed the

following documents:

Diablo Canyon

NRC Information Notice 95-54:

Decay Heat Management

Practices

During Refueling Outages

NUREG-0800,

USNRC Standard

Review Plan,

Section

9. 1.3,

"Spent

Fuel

Pool Cooling and Cleanup

Systems"

Diablo Canyon

TS

-15-

~

Diablo Canyon License

Amendment

(LA) 22/21

(Expansion of Spent

Fuel

Pool Storage

Capacity Units

1

and 2)

and the associated

Safety Evaluation Report

(SER)

b.

Observations

and Findin

s

UFSAR, Section

9. 1.4.2.3,

describes

a one-third core offload.

However,

the licensee

has

conducted

a full-core offload during each refueling

outage

since the start of commercial

operation of the units.

Further,

a

safety evaluation

has not been

performed,

as required

by

10 CFR 50.59

prior to the licensee's

departure

from performing core offloads

as

described

in the

The

SER,

which approved

LA 22 and

21 for Units

1 and

2 respectively,

concluded,

in part, that the spent fuel pool temperature

would not

exceed

140

F for normal offload conditions (i.e., unloading of

76 assemblies)

and

212

F for abnormal offload conditions (i.e.,

full-core offload).

The licensee's

thermal-hydraulic analysis

supported

these

conclusions

and demonstrated

that the spent fuel pool temperature

would not exceed

140'F during

a one-third core offload and

175'F for a

full-core offload.

The inspectors

questioned

whether the 140'F temperature limit should

apply as the licensing basis for full-core offloads since they had

become

the routine, or normal

method of refueling.

The licensee

concluded that the

140

F temperature limit was applicable to full-core

offloads.

The licensee

had not previously implemented controls to

ensure

the spent fuel pool temperature

would not exceed

140'F following

full-core offloads.

Further investigation

by the licensee,

after being

questioned

by the inspectors,

revealed

other inconsistencies

with

temperatures

used in analyses

and associated

controls.

The

inconsistencies

are described

below:

~

The criticality analysis of record

assumed

a maximum normal

temperature

of the spent fuel pool of 150'F;

however,

the

Equipment Control Guideline allowed

up to 175'F.

The licensee

noted

on April 2,

1996, that the Unit 2 spent fuel

pool temperature

decreased

to 66

F which was below the 68

F

minimum temperature

assumed

in the criticality analysis.

The

licensee initiated actions to reduce

CCW flow which had little

impact on the spent fuel pool temperature.

Subsequently,

the

licensee

performed

a criticality analysis that demonstrated

that

the reactivity in the spent fuel pool would be below the

regulatory limit for a pool temperature

as low as 32'F.

Section

9. 1.3. 1 of the

UFSAR notes that the spent fuel pool cooling

analysis

is based

upon

a full-core offload completed

in no less

than

148 hours0.00171 days 0.0411 hours 2.44709e-4 weeks 5.6314e-5 months following shutdown.

During the

2R6 refueling outage

a

-16-

full-core offload had

been

completed

146 hours0.00169 days 0.0406 hours 2.414021e-4 weeks 5.5553e-5 months after shutdown.

The

licensee's

refueling procedures

did not incorporate controls to ensure

that core offload would not be completed

in less

than the

148 hours0.00171 days 0.0411 hours 2.44709e-4 weeks 5.6314e-5 months .

The licensee's

disposition of Information Notice

( IN) 95-54 by the

independent

safety evaluation

group

(ISEG) did not identify any problems

with the processes

or activities related to decay heat

management.

The

ISEG review noted that "core offload practices

and thermal

design

limitations are well documented

and conservative

such that actual

operating practices

are

bounded

and considered

adequate."

The failure

of ISEG to identify problems

associated

with the licensee's

decay heat

management

practices

during refueling outages

was

a missed opportunity

to identify and correct these

problems.

The licensee

implemented corrective actions for the

above deficiencies

prior to the Unit 2 refueling outage

(2R7).

The corrective actions

included:

performing

a

10 CFR 50.59 safety evaluation for the normal conduct

of a full-core offload,

establishing

administrative controls to ensure

spent fuel pool

temperature

is maintained within the licensing basis

and the

assumptions

of the supporting

analyses,

establishing

administrative controls to ensure that the core is

not offloaded at

a rate faster than that

assumed

in the supporting

thermal-hydraulic analysis,

and

revising the

UFSAR description of the refueling procedure.

c.

Conclusions

The licensee's

failure to perform

a safety evaluation prior to

performing full-core offload is an unresolved

item pending

NRC review

(URI 50-275,323/96006-05).

This caused

the licensee's

failure to

implement administrative controls for the reload process

(spent fuel

pool temperature

and time for full-core offload).

E4

Engineering Staff Knowledge

and Performance

E4.1

Review of Desi

n Chan

e Packa

e

DCP

J-050216

a.

Ins ection

Sco

e

37551

The inspectors

reviewed

DCP J-050216,

including the safety evaluation,

technical description

and drawings,

and the proposed

change

to the

This

DCP replaced

the input to Loop 2-1 reactor coolant

system

cold leg wide range

TE (TE-413B) with an alternate

available

sensor

(TE-411B) in order to provide the

TS required indication at the

dedicated

shutdown

panel

in Unit 2.

The inspectors

discussed

the

-17-

4

changes

with the licensee's

staff and walked

down the dedicated

shutdown

panels

in both units.

b.

Observations

and Findin

s

0

The change

was

implemented

in July 1995

as

an "install and remove"

change. 'he

DCP indicated that the configuration would be restored

during the "next suitable" Unit 2 outage.

The next Unit 2 refueling

outage

was scheduled

for April 1996.

The

DCP included

a proposed

UFSAR change

which was submitted to the

licensee's

licensing organization.

The proposed

UFSAR change

inappropriately included

a change to Table 9.5G-2,

page

10, which was

for Unit

1 only.

Some sections of the Fire Hazards Analysis (including some not affected

by the

UFSAR change for this

DCP) failed to identify with which unit the

various

components

were associated.

An example of an unclear section

was Fire Area TB-7, Fire Zone

19-A (beginning

on page 9.5A-561).

The

DCP included extensive

documentation

of the implications of the

change.

The inspectors

noted that the

DCP package

did not explicitly

state

in the first seve'ral

pages

whioh unit was affected

by the change.

However, consistent with licensee practice,

the

DCP had

an even

number,

which implied that the change

was for Unit 2.

c.

Conclusions

The

DCP was thorough in addressing

most aspects

of the change with some

minor discrepancies

noted.

Weaknesses

in the completeness

of

engineering

work were evident.

E7

equality Assurance

In Engineering Activities

f7. 1

Review of LAs and Their

Im act

on the

a.

Ins ection

Sco

e

37551

The inspectors

reviewed

a sample of 6 approved

LAs to determine their

impact, if any,

on the facility UFSAR.

Specifically, the inspectors

reviewed the applicable portions of the

UFSAR to evaluate

the

consistency

and accuracy of the

UFSAR with the approved

changes

in the

LAs.

b.

Observations

and Findin

s

The inspectors

reviewed

LAs 94 and

93 for Units

1

and 2, respectively.

These

amendments

revised

the

TS requirements

for remote

shutdown

instrumentation

to be consistent

with the Westinghouse

Standardized

TSs

(NUREG 1431).

The licensee

concluded that indication of the

RCS hot and

4

'I

C I ~

gl

~

-18-

cold leg temperatures

was required for remote

shutdown of the plant.

The licensee

also concl,uded that indication of emergency

boration flow

was not required for remote

shutdown.

Although the revised

TS reflected

these

conclusions,

the licensee's

UFSAR did not.

Specifically,

Section

7.4, 1. 1 of the

UFSAR listed emergency

boration flow as

a

required indication for shutdown of the plant outside the control

room

while it remained silent

on the requirement for RCS temperature

indication.

The inspectors

reviewed

LAs 89 and 88.

These

amendments

revised the

TS

to reduce

the minimum required

CCW flow to each of the

CFCUs from

2000

gpm to 1650

gpm during normal operation.

The licensee's

post-loss

of coolant accident

containment

performance

analysis

in the

assumes

a design basis

CCW flow of 2000

gpm to at least

two of the

CFCUs.

The licensee's

safety analysis

accompanying

the

LA request

justified the difference

between

the minimum

CCW flow in TS and the

design

basis

CCW flow in the

UFSAR analysis

based

upon the automatic

isolation of the nonvital

CCW header

in response

to

a loss of coolant

accident.

The isolation of the nonvital header

under accident

conditions

would redirect sufficient flow to the vital

CCW headers

to

provide

a minimum of 2000

gpm to the

CFCUs.

Although the

UFSAR had

been revised

by the licensee

to reflect these

LAs, the revisions

were incomplete

and,

as

'a result,

the

UFSAR was both

inconsistent with the

LA and internally inconsistent.

Specifically,

Section 9.2.2.2.7 of the

UFSAR states

that during normal operations,

flow through the fan coolers is throttled to pass

the design basis

accident

flows. It further states

that full flow is assured

through

each

CFCU under accident conditions without any automatic or operator

action.

This contradicts

the

LA safety analysis

which assumed

normal

flow rates

less

than the

2000

gpm design basis

and required the

automatic isolation of the nonvital

CCW header

to achieve full flow

through the

CFCUs,

In addition,

both Section

9.2 '.2.7

and Table 6.2-26

of the

UFSAR define normal

CCW flow through the

CFCUs

as

2000

gpm while

Table 9.2-5 defines

normal

CCW flofv to all of the

CFCUs

as 8,250

gpm

(1650

gpm per unit).

The table incorporated

into Section 9.2.2.2.7 of the

UFSAR stated that

the design

CCW inlet temperature

for the

CFCUs during normal operati ;

was 95'F.

In contrast,

Table 6.2-26 of the

UFSAR lists the design inlet

temperature

during normal operation

as 90'F.

The licensee failed to revise Section 8.3.1.1.9 of the

UFSAR from 3.6kV

to 3.8kV when implementing the increase

in setpoint of the secondary

undervoltage

relay to 3785

VAC authorized

by LA 85/86.

In addition, the

licensee failed to revise the

4kV bus nominal voltages listed in

Appendix 8.3A after raising the secondary

undervoltage

relay setting.

The inspectors

determined

that. the licensee

had also recently noted

these deficiencies

during

a

UFSAR review.

-19-

The licensee

has

issued

an

NCR to address

the

UFSAR inaccuracies

'and,

as

a part of the corrective actions,

the licensee initiated

a review by

system engineers

of the entire

The initial review efforts were

done to gain

a quick assessment

of the

UFSAR's accuracy.

I.

Conclusions

The deficiencies identified in the

UFSAR are continuing to be evaluated.

However,

the number of deficiencies

in the relatively small

sample is

indicative of weaknesses

in this program to review and update

the

in response

to LAs and therefore

is of regulatory concern.

These

deficiencies,

the examples

discussed

in Section 02. 1,

and those

being

identified by the licensee

in their

UFSAR review process

are being

tracked

as

an unresolved

item (URI 50-275/96006-06)

pending further

NRC

review.

f8

Miscellaneous

Engineering

Issues

E8. 1

Review of UFSAR Commitments

A recent discovery of a licensee

operating their facility in

a manner

contrary to the

UFSAR description highlighted the need for a special

focused

review that compares

plant practices,

procedures,

and/or

parameters

to the

UFSAR description.

During the inspection period, the

inspectors

reviewed the applicable sections of the

UFSAR related to the

inspection

areas

discussed

in this report.

The following

inconsistencies

were noted

between

the wording of the

UFSAR and the

plant practices,

procedures,

and/or parameters

observed

by the

inspectors.

The deficiencies

are discussed

in the sections

in the

report that are referenced

below:

02. 1

UFSAR inconsistency with referenced

charcoal

bed methyl

iodide removal efficiency

E2.2

Core offload practices

did not coincide with actual

licensee

practice

E4. I

Inaccuracies

in UFSAR revision written for DCP J-050216

E7. 1

incomplete

UFSAR revisions written for LAs (several

examples

noted)

I

V. Hang ement Neetin

s

Xl

Exit meeting

Summary

The inspectors, presented

the inspection results to members of the licensee

management

at the conclusion of the inspection

on April 18,

1996.

The

licensee

acknowledged

the findings presented.

0

-20-

The inspectors

asked

the licensee

whether

any materials

examined during the

inspection

should

be considered

proprietary.

No proprietary information was

identified.

-21-

PARTIAL LIST OF

PERSONS

CONTACTED

Licensee

J.

R.

D.

H.

E.

S.

G.

T. L.

C.

D.

R.

L.

D.

B.

R.

P.

NRC

Becker, Director, Operations

Behnke,

Senior Engineer,

Regulatory Services

Chaloupka,

Engineer,

Surveillance

Engineering

Chestnut,

Senior Engineer,

Primary Systems

Engineering

Grebel, Director, Regulatory Services

Harbor,

Engineer,

Regulatory Services

Johnson,

Supervisor,'egulatory

Services

Miklush, Manager,

Enineering Services

Powers,

Manager,

Operations

M.

D. Tschiltz, Senior Resident

Inspector

S.

AD Boynton,

Resident

Inspector

J.

A. Sloan,

Senior Resident

Inspector,

San Onofre Nuclear Generating

Station

-22-

IP 37551:

IP 61726:

IP 62703:

IP 71707:

IP 71750:

IP 92700:

IP 92903:

INSPECTION

PROCEDURES

USED

Onsite Engineering

Surveillance

Observations

Maintenance

Observations

Plant Operations

Plant Support Activities

Followup - Operations

Followup

Engineering

ITEMS OPENED,

CLOSED,

AND DISCUSSED

~0en ed

50-275/96006-01

failure to follow Operations

Procedures

OP L-3 and L-4

50-275/96006-02

NCV

failure to follow Administrative Procedure

AD2. ID1

50-275/96006-03

failure to perform channel

check of remote

shutdown

instrument

50-275/96006-04

IFI

50-323/96006-05

URI

licensee

long-term corrective actions to improve

source

range

instrument reliability

failure to perform

a

10 CFR 50.59 evaluation for full-

core offload

50-275/96006-06

50-323/96006-06

URI

failure to adequately

review and update

the

Closed

50-275/95016-01

Discussed

failure to follow procedure

during vessel

draindown;

failure to follow procedure for source

range

operational

checks

50-275/94028-01