ML18012A842

a few hours earlier in the shift because it had not passed

a

channel

check (its indication deviated

more than five percent

from the

other three NI channels).

As a result of its inoperability, operators

performed procedure

OWP-RP,

Reactor

Protection,

Revision 7, Section

OWP-

RP-23,

which directed personnel

to lift cet tain electrical

leads in the

back of the

N41 cabinet.

This action satisfied the Technical Specification 3.3.1(a)

requirement for placing the power range neutron

flux high setpoint,

low setpoint,

high flux rate,

and overtemperature

differential temperature trips for N41 in the tripped condition.

The

'

associated

bistable lights in Trip Status Light Box 4 and the associated

NI annunciators

in Annunciator Light Box 13 on the Hain Control Board

(HCB) were illuminated as expected.

The operator s had placed colored

indicators

on these annunciators

as

an aid to help them identify

expected

alarms.

Licensee

personnel

decided to wait, until after the calorimetric and flux

map at the planned

30 percent

power plateau to correct

N41.

This was

based

on

a low power calorimetric being relatively inaccurate

which

would probably mean additional

adjustments

at the 30'lateau.

After

the secondary

heat balance

was completed using surveil)ance test

rocedure

OST-1004,

Power Range

Heat Balance,

Revision

13 (about

an hour

efore the reactor trip), the shift crew determined that three of the

four NIs (N41,

N42,

and N43) required adjustments to match their

indications with the calculated reactor thermal

power of 27.5 percent.

OST-1004 directs operators to use operating procedure

OP-105,

Excore

Nuclear

Instrumentation,

Revision 8, Attachment 2, to make the NI

channel amplifier gain adjustment.

The control

room operator selected

N41 first.

The channel's pre-existing tripped status did not affect

indication and adjustment capability.

The operator

found that there

was

insufficient gain adjustment capacity in the fine gain potentiometer for

the

N41 channel.

The procedure

then directed the operator to use the

coarse

gain potentiometer

located inside the NI cabinet drawer.

During

the coarse

adjustment,

the operator received

a neutron flux high

positive rate trip light indication at the N41 panel.

The light at the

NI drawer was extinguished

by the operator

resetting the neutron flux

high rate trip locally (with 18C verification).

However, the lifted

leads in the back of the panel

cabinet

(per OWP-RP-23) prevented the

operator 's action from clearing the tripped status in Solid State

Protection

System.

The operator did not observe that the tripped

bistables

were still illuminated for N41 channel

on the main control

panel.

With the neutron flux rate trip lights cleared locally on the front of

the N41 panel,

the operator

proceeded to adjust

N42.

Again, adjustment

capacity was limited using the fine gain potentiometer,

and the operator

used the coarse

gain potentiometer.

As soon

as the operator

took the

coarse gain potentiometer

out of the locked position,

a neutron flux

high positive rate trip was received for N42 coincident with the

associated

tripped condition for N41 ~

The reactor tripped as designed

on two-out-of-four logic.

Safet

Si nificance

An automatic fast bus transfer failure resulted

from Breaker

108, Unit

Auxiliary Transformer feeder to Unit Auxiliary Bus 1A (UAB 1A), not

tripping as Breaker 107, Station Star tup Transformer

(SUT) feeder to UAB

1A, closed onto the bus.

Having both breakers paralleled to the bus

effectively motorized the main generator

as it coasted

down from the

reactor

and turbine/generator trip.

This reduced

bus voltage until all

of its load breakers

opened,

including those for the "A" reactor coolant

pump

(RCP)

and the "A" main feedwater

pump.

The loss of the only

operating

main feedwater

pump caused'n

ESF actuation of both motor-

driven auxiliary feedwater

(AFW) pumps.

In addition, the "C" RCP

(powered through

UAB 1C which was then tied to UAB 1A) also tripped on

'ndervoltage.

This left only the "B" RCP in operation.

.Ap'proximately

30 seconds later,

SUT Breaker

107 tripped on overcurrent while still

attempting to motorize the main generator.

Operators stabilized the plant with one

RCP and restarted

the other

two

when

UAB 1C and

UAB 1A were reenergized.

Steam generator levels were

maintained

by the

AFW system

and reactor coolant system temperature

was

maintained

by using the steam generator

power operated relief valves

(PORVs).

There was little residual

heat since the reactor

had only been

critical for

a few days

and had tripped from only 28 percent

power.

The

ESF busses

remained energized

throughout the transient

and no emergency

diesel

generator

actuation occurred.

A pressurizer

spray valve

indicated dual position following attempts to close it after the "A" RCP

was lost.

Plant personnel

later verified that the valve was closed

and

that the problem was

a misadjusted limit switch, which was subsequently

corrected.

The automatic fast bus transfer failure was later attributed

to a failed trip coil in breaker

108, although the licensee's

investigation into the coil failure was still continuing at the end of

the inspection period.

The overall safety consequences

of the reactor

trip and failure of the automatic fast transfer

function wer e minimal.

The control

room Shift Superintendent

notified the

NRC of this event at

8:59 a.m.

on June 8, 1997,

as required by 10 CFR 50.72.

Re ulator

Si nificance

Although the safety consequences

were mitigated by prompt operator

actions to stabilize the plant, the control

room activities which lead

to the event contained regulatory significance.

The shift's pre-job

plan for adjusting the NI channels following the calorimetric did not

include

a discussion of specific actions required to .restore

N41 to

operable status

before adjusting the other channels.

The operator

performing the NI adjustments

failed to observe all of the diverse

indications of tripped status for N41 prior to adjusting

a second

channel.

Additionally, the control

room crew members

were all aware

that the adjustments

were being made,

but no one thought about the

consequences

of adjusting

N42 with another

channel in a tripped

'ondition.

Procedure

OP-105 contained cautions

about receiving rate

-: trips while adjusting the NI channels,

but did not address

the

consequences

of making adjustments to other channels while one channel

was'noperable.

Technical Specification Table 3.3-1 specifies

a minimum of three

Power

Range Nuclear Instrumentation

channels

(out of four total) are required

to be operable for the Neutron Flux High Positive Rate trip function,

and that Action Statement

2 applies.

Table 3.3-1 Action Statement

2

states,

in part, that Power Operation

may proceed with the number of

channels

one lesg than the total

number of channels

provided

the inoperable

channel .is placed in the tripped condition within six

hour's

and the minimum channels

requirement is met.

Table 3.3-1 Action 2b contains

a provision for bypassihg the inoperable

channel for up to four hours for surveillance testing of the other

channels

per Specification 4.3.1.1.

The purpose of bypassing

an

(tripped) channel is to provide for surveil'lance testing of

one of the three operable

channels while power operation continues.

Without .bypassing

a tripped channel,

the testing of one of the operable

channels

would generate

a second trip signal, satisfying the two-out-of-

four reactor trip logic, which was what happened

on June 8,

1997.

The

inspectors

found that there

was

no installed bypass function for the

Power Range NIs and no procedure

to accomplish that function.

The failure to restore

N41 to operable status or bypass it prior to

continuing surveillance activities on a second

channel

was contrary to

the TS provision and is identified as

a violation of TS 3.3.1,

Table

3.3-1 (50-400/97-06-01).

c.

Conclusions

A reactor trip from 28 percent

power

was caused

by operator error while

adjusting nuclear instrumentation during surveillance activities.

Operator

performance to stabilize the plant following the trip was good.

The

NRC was appropriately notified in accordance

with 10 CFR 50.72.

One

violation was identified against

TS 3.3.1, Table 3.3-1.

01.3

Post-tr i

Review

a.

Ins ection Sco

e

93702

'I

The inspectors

reviewed the licensee's

post-trip review procedure for

the June 8,

1997 reactor trip to determine whether all related problems

and corrective actions

had been

documented.

The inspectors

independently

reviewed post-trip data to evaluate operator

and plant

performance.

The inspector attended the Plant Nuclear Safety Committee

meeting for which the root cause of the reactor trip was discussed.

b.

Observations

and Findin s

Procedure

OHH-004, Post Trip/Safeguards

Actuation Review, Revision 8/2,

described the licensee's post-trip review process.

The post-trip review

package

required by OHH-004 was reviewed by plant management

on June 8,

1997.

Based

on resolution of the root cause of the trip, which was

operator error

(discussed

above in report section 01.2),

and correction

of other trip-related deficiencies,

reactor restart

approval

was

documented

on an OHH-004 attachment

and granted

on June 8,

1997.

The inspectors

noted that initial troubleshooting activities for the

Unit Auxiliary Bus 1A fast bus transfer failure were narrowly focused

and did not adequately

consider plant equipment status.

Operators

failed to recognize that both control

room and local breaker indication

lamps were not illuminateg for Unit Auxiliary Transformer Breaker

108

following the automatic fast transfer attempt.

As a result.

Breaker

108"s position was never questioned.

Plant computer

sequence of events

logs, which were relied upon by the licensee's

investigation team, did

not include the status of Breaker

108 because its position had not

changed.

The licensee's initial troubleshooting efforts were focused

on

potential failur'e mechanisms

in Station Startup Transformer'reaker

107

and its trip on overcurrent.

The inspectors

observed the lack of

indication and considered that if breaker

108 did not trip, the trip of

'reaker

107 could be explained

as

an -expected

occurrence

since the main

generator

would have been motorized.

The licensee

discovered that Breaker

108 never opened,

and that its

control

power fuses

had blown, resulting in the loss of its local

and

control

room indication.

Breaker

107 tripped on overcurrent

when both

breaker s were paralleled to Unit Auxiliary Bus 1A,

a condition which

attempted to motorize the main generator.

The failure was ultimately

linked to

a charred trip coil in Breaker

108 that was later sent to a

laboratory for further analysis.

The cause of the trip coil's failure

to trip the breaker during the fast transfer

sequence

was still under

investigation at the conclusion of the inspection period.

A spare

breaker

was installed in Breaker

108's cubicle along with new control

power fuses prior to restarting the plant on June 8,

1997.

C.

Conclusions

01.4

a.

b.

The licensee's

OHH-004 post-trip review package

was accurate.

The

inspector's

independent

review of post-trip data concluded that plant

performance

was as expected,

except for the failure of the fast transfer

from the Unit Auxi.liary Transformer to the Station Startup Transformer

for Unit Auxiliary Bus lA.

The 'licensee's initial troubleshooting

efforts for the fast bus transfer failure were narrowly focused

due to

not adequately

assessing

the initial post-trip conditions.

Sin le Train Safet

In 'ection

Ins ection Sco

e

93702

The inspectors

reviewed operator

and plant equipment performance during

a partial safety injection (SI) on Hay 14,

1997.

The inspectors

responded to the control

room at, the time of the event

and verified that

the plant was placed in a safe condition.

A post-event

review was

completed to ascertain

the root cause

and licensee's

corrective actions

and is discussed

further in Section H2.2 of this report.

Observations

and Findin s

With the plant in Hode 5 (Cold Shutdown)

on Hay 14,

1997,

a partial

safety injection ("A" train signal only) resulted in a small

volume of

water (approximately

126 gallons by calculation) gravity feeding from

the refueling water storage tank

(RWST) to the reactor coolant system

(RCS) via the high head safety injection (HHSI) flowpath.

This occurred

while maintenance

technicjans

were performing

a test

on the solid state

protection system

(SSPS)

using procedure

HST-I0072,

Tt ain "A" 18 Honth

Hanual Reactor Trip, Solid State Protection

System Actuation Logic and

6

Haster

Relay Test, Revision 7.

A more detailed discussion of the

procedural

deficiency which. caused this event is contained in Section

H2.2 of this report.

A single train SI signal

was generated

from Hain Steam Line Low Pressure

which started the "A" emergency diesel

generator,

the "A" emergency

.. sequencer,

the

".A" residual

heat

removal

(RHR) pump,

and the "A"

emergency service water

(ESW)

pump,

among other

components.

The "A"

charging/safety injection. pump did not start because it was under

clearance

due to Technical Specification restrictions related to RCS

Low

Temperature

Overpressurization

Protection.

However, valves

1CS-291,

1SI-l, and 1SI-4 automatically opened which provided

a flowpath for the

RWST to gravity feed the

RCS.

RCS standpipe level indication increased

from 21 inches

below the reactor vessel

flange to 19 inches

below the

flange before operators

terminated the injection by securing 1SI-1 and

1SI-4.

The

RCS heated

up approximately

1 degree

Fahrenheit after the "8" ESW

header

(which was supplying the operating

"B" RHR heat exchanger)

was

isolated

from normal service water as designed.

The "A" RHR pump

started

and operated in recirculation

mode with its heat exchanger

bypassed,

since it was originally aligned in shutdown cooling mode and

placed in standby.

The plant was stabilized with systems

restored to

their previous

Hode 5 alignments within minutes of the SI.

The Unit

Senior Control Operator exited the Emergency Operating Procedures

within

30 minutes of the event.

There were minimal safety consequences

as

a

result of this event.

C.

01.5

a'.

Conclusions

The plant performed

as designed during an inadvertent partial Safety

Injection event while shutdown.

A small

amount of Refueling Water

Storage

Tank inventory was gravity fed to the Reactor

Coolant System

when certain high head safety injection valves automatically realigned.

The Reactor Coolant System heated

up slightly as

a result of the

expected isolation of service water.

Operator performance to stabilize

the plant was good.

(Section 01.4)

~Uit St t

Ins ection Sco

e

71707

71711

The inspectors

observed the star tup from Ref'ueling Outage

7 to determine

if procedures

were followed, and technical specification requirements

were met.

Procedures

GP-2,

Normal Plant Heatup from Cold Solid to Hot

Subcritical

Hade

5 to Hode 3, Revision 13; GP-4,

Reactor

Startup

(Hode 3

to Hode 2), Revision 16;

and GP-5,

Power Operation

(Hode 2 to Hode 1),

Revision 16/1,

governed these activities.

b.

Observations

and Findin s

The inspectors

observed that operators

were following procedures

as

required during 'the startup.

Several

items were encountered

by the

operators

as follows.

The inspectors

noted that rod H-12 gave erroneous

indication at step position 112

- 114 as it had during previous startups

.-- since late 1995

(WR/JO 95-AKIB1).

This item was not repaired during the

refueling outage.

The inspector could not find this item in the

operator workaround log.'.'. Several

rod bank deviation alarms did not

clear as expected at the cycle 8 fully withdrawn rod position of 225

steps stated in procedure

PLP-106,

Technical Specification

Equipment

List Program

and Core Operating Limits Report, Revision 15.

These

were

the rod insertion limit alarm and the rod bank deviation alarm.

Their

reset values were later

determined to be 225.5 steps.

The alarms

had to

be manually reset using the computer.

The licensee

was investigating

the cause of this error.

During synchronization to the grid on June 7, 1997, the turbine picked

up more load than expected

(56 megawatts

verses

45 megawatts).

This

caused

level oscillations which required that the "A"

and

"C" feed regulating. bypass

valves be taken out of automatic.

These

valves

had maintenance

performed

on them during the outage to allow them

to control in automatic.

The "B" valve adequately controlled in

automatic.

The licensee's

investigation after the reactor trip (section

01.2) revealed that the stroke for the "A" and

"C" valves

was set at

1

and 1/2 inches instead of 2 inches.

The "B" valve was set at 2 inches.

The inspector recalled that these valves performed similarly during

a

synchronization to the grid on Harch 30,

1996 when the turbine Dicked up

more load than expected.

The licensee corrected the valve stroke

problem which allowed the valves to stay in automatic for the

synchronization

on June 9,

1997 (45 megawatts).

The synchronization to the grid on June 9, 1997, after the reactor trip,

was much smoother

than the one on June 7,

1997.

The June

9

synchronization

was performed at

a higher

power level (8-9 percent

vs 4-

5 percent)

allowing a smoother shift of steam flow from the condenser

steam

dumps to the turbine generator

which resulted in less of a power

change.

C.

02

Conclusions

The inspectors

concluded that procedures

were followed and that

operators appropriately investigated

alarms

as they annunciated.

Operational

Status of'acilities and Equipment

02.1

En ineered Safet

Feature

S stem Walkdowns

71707

The inspectors

used Inspection

Procedure

71707 to walk down accessible

portions of'he containmeqt structure prior to final closure in

preparation

for plant restart

from the refueling outage.

Equipment

operability, material condition,

and housekeeping

were acceptabl,e

in all

05

-" 05.1

06.1

a.

b.

C.

cases.

Several

minor discrepancies

were brought to the licensee's

attention

and were corrected.

The inspectors identified no substantive

concerns

as

a result of these

walkdowns.

Operator Training and Qualification

0 erator License Status

Chan

e

71707-

The licensee

sent

a letter to the

NRC on Hay 6,

1997 informing the

NRC

of a failure to meet the 30-day notification requirement

under

10 CFR 50.74(a)

regarding

an individual holding

a Senior Reactor Operator

license that was'eassigned

to the CP8L Robinson Plant in August 1994.

This was discovered

when the individual returned to the Harris Plant to

start

a new job assignment.

This was considered

a violation of 10 CFR 50..74(a)

~

This licensee identified and corrected violation is being

treated

as

a Non-Cited Violation, consistent with Section VII.B.1 of the

NRC Enforcement Policy (NCV 50-400/97-06-02).

Operations Organization

and Administration

0 erations

Hang er Chan e

Ins ection Sco

e

71707

The inspector

reviewed the qualifications of the new Operations

Hanager

against the requirements of Technical Specification 6.2.2.e

and ANSI

3.1-1978Property "ANSI code" (as page type) with input value "ANSI3.1-1978" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process..

In addition, the inspector

reviewed the operations

organization chart to verify that the same Technical Specification

requirements

were,met.

Observations

and Findin s

The inspector

found that the Operations

Hanager

met the requirements of

the technical specification in that he was previously licensed at the

Harris Plant

under license

number

SOP 21241,

which was no longer active.

He also met the requirements of the ANSI standard.

The previous two

operations

managers

held active senior reactor operator

(SRO) licenses,

so there

was no need for an operations

supervisor position (middle

'anager)

with an active

SRO license.

Under the new operations

manager,

the middle manager

position has

been reestablished

through the

superintendent-

work control.

The inspector verified that the

Super intendent-

Work Control (operations

supervisor)

held an active

senior reactor operator

license

and that the organization chart

showed

the shift superintendents

reporting to him.

The licensee

submitted

a

technical specification

amendment

request

on June

12,

1997 to update the

technical specification wording in relation to these positions.

Conclusions

The inspector

concluded t4at the

new operations organization including

the new manager

and the superintendent-

work control (operations

07

07.1

08.1

08.2

08.3

~

9

supervisor)

met the r'equirements of the technical specification

and the

ANSI standard.

Quality Assurance in Operations

Licensee

Self-Assessment

Activities

40500

During the inspection period, the inspectors

reviewed multiple. licensee

self-assessment

activities, including:

Plant Nuclear Safety Committee

(PNSC) meetings

on Hay 29,

1997,

June 5,

1997,

and June 8,

1997.

Nuclear Safety Review Committee

(NSRC) meeting on June

17,

1997

PNSC and

NSRC performance

was gener ally good.

Hiscellaneous

Operations

Issues

(90712,

92700,

92901)

Closed

VIO 50-400/97-03-01:

Failure to report

a non-compliance with

Technical Specifications to the

NRC in accordance

with 10 CFR 50.73.

The inspector

reviewed the licensee's

response

dated

Hay 26,

1997 and

associated

LER 50-400/97-005-00.

The inspector concluded that this

violation had been corrected.

This item is closed.

Closed

VIO 50-400/97-03-03:

Failure to establish

procedures

for

operating motor-driven

AFW pumps,

and "A" train

RHR and

CCW systems

from

the auxiliary control panel.

The inspector

reviewed the licensee's

response

dated

Hay 26,

1997.

The

response identified that procedure

AOP-004,

Remote Shutdown,

Revision 12, included the instructions for operating

components

required

for safe shutdown with no fire from the auxiliary control panel.

The

inspector verified that Section 3.2.3 of the procedure

implemented this

corrective action.

In addition,

procedur e OST-1813,

Remote

Shutdown

System.Operability,

Revision 7, included testing of components

required

for safe shutdown with no fire.

The inspector verified that these

components

were added.

In addition, Inspection Report 50-400/97-04

Section H2.2,

documented

observation of OST-1813 which included these

components.

This item is closed.

Closed

VIO 50-400/96-02-02

LER 50-400/96-004-00

and -01:

Inadequate

procedures for bypassing

RWST level.

Corrective actions described in the licensee's

response,

dated

Hay 9,

1996,

and accepted

by the

NRC on Hay 16,

1996,

were verified as

completed by the inspector,.

This issue

was reported by the licensee in LER 50-400/96-004-00

and

Supplement

01.

The actioqs described in their LER were also verified as

completed.

The actions included procedure revisions,

counselling of

per'sonnel,

and real time training.

This item is closed.

08.4

10

Closed

VIO 50-400/95-017-01:

Failure to follow turb'tne test procedure

resulting in reactor trip.

Corrective aetio'ns for this violation were presented

in LER'0-400/95-

010-00 which was closed in inspection report 50-400/95-17.

Additional

corrective actions were presented

in the licensee's

response,

dated

-

= January

10,

1996 and accepted

by the

NRC on January

19,

1996.

The corrective actions were reviewed

and verified by the inspector

as

being completed.

The actions included refresher

training and

installation of permanent

switch position indication marks on the main

control board

(and simulator).

Discussions with licensee

personnel

in

the control

room indicated that the modification was

an improvement.

This item is closed.

08.5

Closed

LER 50-400/95-011-00

and -Ol:

Reactor trip/safety injection

during testing.

This

LER reported

a reactor trip and safety injection on November 5,

1995, that occurred during routine testing.

The cause

was determined to

be contacts

on

a blocking relay failing to maintain continuity.

As

discussed

in the

LER supplement,

the tailure mechanism

was deter mined to

be surface tarnish on the relay contacts

which prevented the test

circuit current from providing the arc energy necessary to burn through

the silver contacts.

The test procedure

was revised to require cycling

'the test switch several

times to ensure the test switch contacts

are

wiped to remove any tarnish prior to opening the slave relay contacts.

Corrective actions described in the

LER and its supplement

were verified

by the inspectors

as completed.

The event

and corrective actions were

reviewed with operations

personnel

for their understanding.

The original

LER also reported the unexpected

opening of the Hotor-

Driven Auxiliary Feedwater

Pump

(HDAFW) pump flow control valves

(FCVs)

as

an unplanned

Engineered Safety Features

(ESF) actuation.

This

occurred

on November 6,

1995 while licensee

personnel

were continuing

through the same procedure

(OST-1044,

ESFAS Train A Slave Relay Test

Quarterly Interval, Revision 4) that had been in progress

when the

reactor trip/safety injection occurred the day before.

The

HDAFW pump

flow control valves went full open as designed while testing the K635

blocking relay in the solid state protection system,

but the

valves'ction

was unexpected

because

the procedure did not alert the operators

that the valves would receive

an automatic

open signal.

The valves

had

been throttled while in Hode 3 (from the reactor trip) to control steam

generator

levels.

Steam generator

levels remained within the normal

operating

band following the unexpected

valve openings.

Further investigation of previous performances of OST-1044

and its

sister procedure

OST-1045,

ESFAS Train B Slave Relay Test Quarterly

Interval, discover ed

a siqilar occurrence

on October

30,

1994.

Operators

had failed to flag the earlier

event

as

a potentially

08.6

08.7

repor.table

unplanned

ESF actuation.

'This event was included in LER

95-11.

Procedures

OST-1044

arid OST-1045 were revised to alert operators that

the valves will go full open while testing the K635 slave relay if'hey

were in .throttled or closed position.

The procedures .cautioned not to

perform the test if the

AFW system

was being used to control

steam

generator levels.

For the 1994 unplanned

ESF actuation, training was

provided to reemphasize

with operations

personnel

reporting requirements

for such events.

The inspectors verified the licensee's

corrective actions were

completed.

This

LER and its supplement

are closed.

Closed

VIO 50-400/97-01-03:

Inadequate

corrective action pertaining

to LER 50-400/96-003-00,

for core flux mapping.

Closed

LER 50-400/97-005-00:

Failure to perform core flux mapping

following plant operation with reactor

power greater

than

100 percent.

The licensee

responded to the violation on April 14,

1997 and issued

LER

97-005-00

on March 17,

1997 pertaining to the violation.

The

NRC

accepted

the violation response

on April 25,

1997.

The corrective

actions presented

in both documents

were verified by the inspector

as

being completed.

These items are closed.

Closed

LER 50-400/97-009-00:

Technical Specification

(TS)

compensatory

measures

were not taken prior to defeating the Control

Room

Ventilation Isolation signal

by removing

a fuse during clearance

preparation.

This LER was submitted to document

a violation of Technical Specification 3.3.3.1,

action 29, which requires the control

room

ventilation outside air intake to be isolated within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months after the

respective radiation monitor actuation input signal

becomes

inoperable.

The violation occurred

on April 7,

1997,

when

a fuse (L4/2973) was

removed from the Control

Room Ventilation Isolation Signal

(CRVIS) power

supply circuitry.

This fuse was removed per clearance

96-0158 in

preparation for a plant modification

(ESR 96-00320).

By removing the

fuse, the B-train CRVIS signal

was defeated,

including the actuation

input signal

from the control

room outside air intake radiation monitor

(RM-3504SB).

The TS action was not identified during the review or

approval of the clearance

and subsequently

was not performed

as

required.

The cause of this condition was determined

by the licensee to be

personnel

error on the part of the individuals involved in preparing

and

approving the clearance.

An incor rect conclusion in ESR 96-00320 about

CRVIS train operability also contributed to the error

by influencing the

individuals involved in approving the clearance.

The licensee's

subsequent

investigation determined that the"event

had no adverse safety

.

significance,

because

the A-train CRVIS signal

and A-train radiation

08.8

12

monitor

remained operable to provide'he isolation signal

had

a

radioactivity release

event. occurred.

The licensee's

corrective actions involved counseling the individuals

involved in clearance

96-0158

and having operations

and engineering

personnel

review the completed event investigation.

These actions

were

completed

on April 16,

1997 and Hay 7,

1997, respectively;-

The failure to isolate the respective control

room ventilation outside

air intake within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months after the B-train radiation monitor actuation

input signal

became

inoperable is

a violation of TS 3.3.3.1.b,

action

29.

This licensee-identified

and corrected violation is being treated

as

a Non-Cited Violation, consistent with section VII.B.l of the

Enforcement Policy (NCV 50-400/97-06-03).

The inspectors verified that

the corrective

actions

were completed.

This

LER is closed.

Closed

LER 50-400/97-011-00:

Inappropriate Technical Specification

(TS) Interpretation resulted in violations of ECCS Accumu)ator Technical

Specification

and entry into Technical Specification 3.0.3.

This

LER was submitted to document two violations of Technical Specification 3.5.1.a,

which requires the plant to be in Hot Standby

within 7 hour8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months s of accumulator inoperability for inadequate

level or

pressure,

and one missed entry into TS 3.0.3,

which occurred while two

accumulators

were inoperable.

The first violation of TS 3.5.1.a

occurred

on December

10,

1996,

when the "A" Emergency

Core Cooling

System

(ECCS) Accumulator had been inoperable approximately

14 hours1.62037e-4 days 0.00389 hours 2.314815e-5 weeks 5.327e-6 months ,

and the other violation occurred

from Harch 20,

1997, to Harch 22,

1997,

when the "A" accumulator

had been inoperable approximately '46 hours5.324074e-4 days 0.0128 hours 7.60582e-5 weeks 1.7503e-5 months .

The "A" accumulator

was not declared

and the required actions

were not performed,

because

the TS Surveillance

Requirements

(SR)

4.5.1.l.a.1

was inappropriately interpreted

by the licensee.

This SR

verifies proper accumulator pressure

and level by the absence of alarms,

and TS Interpretation

(TSI 88-001)

was in place to allow manual

logging

of accumulator pressure

or level

when the respective

alarm was sealed in

or otherwise inoperable.

This alternate

method of verifying accumulator

pressure

and level

was determined

by the licensee to be contrary to TS,

and the accumulator

was inappropriately declared operable.

Also on Harch 21,

1997, the "B" ECCS Accumulator was inoperable for 42

minutes coincident with the "A" accumulator being inoperable resulting

in a missed entry into TS 3.0.3.

The "B" accumulator

was declared

due to connections with non-seismically qualified piping

whi e filling from and draining to the

RWST.

The inoperability of the

"A" accumulator

was not recognized

due to the TSI and therefore

the TS 3.0.3 entry went unnoticed.

The cause of this condition was determined

by the licensee to be

a

procedural

inadequacy

and an incorrect TSI that allowed an alternate

method of performing

a supveillance

requirement without NRC approval.

08.9

- 13

The licensee's

corrective actions involved canceling EI 88-001 on

Hay 8,

1997, revising all of the procedures that referenced

TSI 88-001,

and initiating a Night Order informing operations

personnel

about the

cancellation of TSI 88-001 on Hay 9,

1997.

All of the appl'icable

procedures

identified by the licensee

were revised by Hay 18,

1997.

The

inspectors verified that the corrective actions

were completed.

The

licensee

has

an ongoing TSI review program that was implemented

as

corrective action for Violation 50-400/96-10-01,

which was

how this item

was identified.

That program will be reviewed during closure of

Violation 50-400/96-10-01.

The failure to declare the "A" accumulator

and take the

required actions is a violation of TS 3.5.1.

This licensee-identified

and corrected violation is being treated

as

a Non-Cited Violation,

consistent with section VII.B.1.of the Enforcement Policy (NCV 50-

400/97-06-04).

This LER is closed.

Closed

LER 50-400/97-013-00:

Entry into Node 6 without required

components,

resulting in Technical Specification 3.0 '

violation.

This

LER documented

a violation of Technical Specification (TS) 3.0.4,

which prevents entry into an operational

mode while relying on the

provisions of a TS action statement.

This LER was discussed

in NRC

report 50-400/97-04,

paragraph

01.3 as

a violation (50-400/97-04-01) of

TS 3.0.4.

The corrective actions will be reviewed during closure of the

violation.

This LER is closed.

08.10

Closed

LER 50-400/97-008-00:

Safety-related

Air Handling Units not

declared

inoperable during maintenance

on associated

temperature

switches resulting in a violation of Technical Specifications.

This event

was reported

because

the licensee

had determined that certain

safety-related air handling units had not been declared

during maintenance

on their associated

temperature

elements,

temperature

transmitters

and/or temperature

switches.

This condition was caused

by

an incorrect interpretation of'perability requirements

related to

safety-r elated air handling units.

Technical Specification

Interpretation

(TSI)87-002,

Revision 2, which was approved in August

1988, provided guidance

on this issue

by stating that the automatic

start of a fan on high temperature

was not an oper ability requirement.

This incorrect interpretation resulted in deficient plant procedures

and

processes

that provided guidance for control of component operability.

The licensee identified six instances

when temperature circuitry

components

were out of service for a time period that exceeded

the

Technical Specification

(TS) action statements

for the specific

components

cooled by the air handling unit and/or were out of service

during plant mode changes,

which is

a violation of TS 3.0.4.

Some of

these

instances

involved components in Air Handling Unit AH-26 (1A-SA)

in February

1990,

(TS 3.7.7), the AH-86 (lA-SA) Air Handling Unit in

H1

H1.1

a.

- 14

Februar y 1991,

(TS 3.7.4),

and the E'-88 (1B-SB)

ESW Intake Str ucture

Exhaust

Fan in October

1991.

(TS 3.7..4).

The corrective actions

were to issue

an Operations

Night Or'der on March

14,

1997,

about the condition, to revise TSI 87-002 on November

22,

1996, to state that the automatic high temperature

fan start signal

may

be required for fan operability,

and to place the maintenance

procedures

on administrative hold.

The inspector verified that these actions

were

complete.

The licensee

planned to update the plant process

used for

component operability control

and to revise the maintenance

procedures

on administrative hold with Action Item Assignment 96-03662.

The failure to declare certain safety-related

air handling units

inoperable during maintenance

on their =associated

temperature

elements,

temperature

transmitters

and/or temperature

switches is a violation of

the TS action statements

for the specific components

cooled by the air

handling units and/or were out of service during plant mode changes,

which is

a violation of TS 3.0.4.

This licensee-identified

and

corrected violation is being treated

as

a Non-Cited Violation,

consistent with section VII.B.1 of the Enforcement Policy (NCV 50-

400/97-06-05).

This LER is closed.

II. Maintenance

Conduct of Maintenance

General

Comments

Ins ection Sco

e

62707

The inspectors

observed all or portions of the following work

activities:

96-AHBH1

96-ACHB1

97-AFXE1

97-AEQI1

97-ABDJ1

Perform CH-H0009,

Jamesbury Butterfly Wafer-Sphere

Valves

- 14-20" Disassembly

and Maintenance,

Revision

5,

on Valve 1SW-83.

Perform CH-H0226, Anchor/Darling Butterfly Valves,

Revision 0, on Valves

1SW-274 and

1SW-40.

Adjust preload

on closing spring for Motor-Driven

Auxiliary Feedwater

Pump flow control valve actuator

(1AF-51) .

Chart Recorder Felt Tip Pen Replacement

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 theiq assigned

tasks.

The inspectors

frequently

observed

supervisors

and system engineers

monitoring job progress,

and

~ 15

quality control personnel

were preseht

whenever required by procedure.

When applicable,

appropriate radiation control measures

were in place.

c.

Conclusions

E

The maintenance

performances

were adequately

conducted.

H2

Maintenance

and Material Condition of Facilities and Equipment

H2.1

Surveillance Observation

a.

Ins ection Sco

e

61726

70313

The inspectors

observed all or portions of the following work

activities:

OST-1004,

Power

Range Heat Balance,

Computer Calculation, Daily

Interval, Revision 13/2.

OST-1823,

lA-SA Emergency Diesel

Generator

Operability Test

18

Month Interval, Revision 10/2.

OST-1826, Safety Injection:

ESF Response

Time, Train B 18 Month

Interval

on

a Staggered

Test Basis,

Revision 9/2.

HST-I0072, Train "A" 18 Month Manual Reactor Trip Solid State

Protection

System Actuation Logic and Master Relay Test,

Revision 7.

HST-I0073, Train "B" 18 Month Manual Reactor Trip Solid State

Protection

System Actuation Logic and Master Relay Test,

Revision 8.

EPT-825T,

Temporary, Procedure for Boric Acid to Blender Flow Test,

Revision 0.

EST-724,

Shutdown

and Control

Rod Drop Test Using Computer,

Revision 5.

OST-9005T,

Temporary Procedure for OST-1813 Retest

Modes 1-6,

Revision 2/1

EST-210, Periodic Containment Integrated

Leak Rate Testing

(Type A

Test) Revision 8/2.

b.

Observations

and Findin s

The inspector

found that the testing was adequately

performed.

During

the calibration of excore nuclear instrumentation

under procedure

OST-

1004, which refers to procedure

OP-105,

Excore Nuclear

Instrumentation,

Revision 8/1, Attachment 2, the inspector

observed

the operator

incorrectly record the as-left gain potentiometer setting for nuclear

instrument

N44.

The operator

corrected the error after being notified

of it.

The inspectors

also noted that the course gain adjustment

potentiometer

was hard for the operators to use,

and just unlocking the

potentiometer

caused

a high flux rate trip for that nuclear

instrument.

During the performance of Safety Injection:

ESF Response

Time, Train "B"

(OST-1826), plant equipmeqt

responded

as expected.

~

~ 16

OST-9005T was performed to retest sections of OST-1813 that could not be

completed

because of plant conditions

and test parts of the control

power circuitry for the Auxiliary Control

Panel

(ACP).

OST-9005T was

performed to ver'ify the operability .of the automatic reactor trip

function associated

with transfer

relays

(43T-4/SA and 43T-26/SB), the

transfer switches

and controls for valves

1SW-124

and 1SW-126, the

transfer switches for Emergency Service Water

Pump '1A-SA,- the transfer

switches for 43TDGl/SA through 43T-DG6/SA,

and the control

power fuses

transferred

by interposing relays

on transfer to the ACP.

These

'elays,

switches,

instrumentation,

fuses,

and annunciators

were verified

as required by Technical Specification (TS) 3.3.3.5.

Specific problems with certain surveillance test are discussed

in

sections

H2.2 and H2.3 below.

c.

Conclusions

The surveillance

performances

were adequately

conducted.

Plant

personnel

and equipment

performed well during the 18-month integrated

safeguar ds test

and

a retest of auxiliary control panel

relays.-

H2.2

Surveillance Test Procedure

Causes Partial Safet

In ection

a.

Ins ection Sco

e

61726

The inspectors

reviewed the root cause of the Safety Injection event

discussed

in paragraph

01.4 to determine

common themes

between it and

other surveillance procedural

problems in recent years.

b.

Observations

and Findin s

Test Procedure

HST-I0072, Train "A" 18 Honth Hanual

Reactor Trip, Solid

State Protection

System Actuation Logic and Haste

Relay Test, Revision

7,

had been revised several

weeks before the event

on Hay 14,

1997 to

incorporate testing of General

Warning circuits in .the Solid State

Protection

System

(SSPS).

A General

Warning condition could be caused

by any one of several

inputs including the loss of 48

VDC and

15VDC

ower supplies or a removed logic card.

A General

Warning condition on

oth trains of SSPS would generate

a reactor trip signal.

In 1996, the

licensee identified during its Generic Letter 96-01 review that the

General

Warning inputs had not been independently verified or tested in

the past.

Licensee

personnel

considered that, although not required by

Technical Specifications,

such

a test would be an enhancement

to the

procedur e.

The General

Warning circuit test

was added to Section 7.1 of the

'rocedure.

Step 7.1.5,

Row 3a in the associated

table-directed

the

technician to position the Hemory Switch in the "A" train SSPS

panel to

position Number

1 from "off".

When the technician performed. this step

on Hay 14,

memory ground qircuit continuity was broken which allowed

reviously blocked safety injection (SI) and reactor trip signals to

ecome unblocked.

The unblocked signals included

Low Pressurizer

~ 17

Pressure

SI,

Low Steamline

Pressure

SI,

and

RCS

Low Flow and Pressurizer

Low Pressure

reactor trips,. among others.

With the plant in Hode 5 and

Technical Specification 6.5.1.2.1

and pressurizer

pressure

channels

below their SI

actuation setpoi'nts,

the "A" train SSPS cabinet generated a'afety

injection signal,

which started the "A" EDG and "A" sequencer

on the

LOCA program

as discussed

in Section 01.4 above.

The first-out

annunciator

was

Low Steamline

Pressure

SI.

The root cause of the SI.was that the procedure

was technically

inadequate

in specifying that the Hemory Switch be taken out of the

"off" position during the given plant condition.

The associated

SSPS

control wiring diagrams

reflected the signal

path from the Hemory Switch

to the SI and Reactor Trip block functions.

However, neither the

procedure writer nor the reviewers identified this path when they

incorporated

step 7.1.5.

This was due to inattention to detail during

the preparation,

review,

and approval

process.

The licensee

also

discovered during its investigation that the reviewer was consulted

during the procedure

preparation

process,

and therefore could not be

considered

completely independent to satisfy administrative requirements

for technical

reviewers.

The licensee

has

had recur ring problems with surveillance

procedure

reviews in the past two years, with one example having similar

consequences.

On October

5,

1995,

a deficient temporary surveillance

test procedure led to a partial safety injection signal which caused the

"B" train emergency

sequencer

to actuate the

LOCA program.

The

temporary test procedure

was prepared,

reviewed,

and approved solely by

Operations

personnel

in that case.

A Violation (50-400/95-15-02)

was

issued against

10 CFR 50 Appendix B for failing to provide for the

review of the test procedure

by personnel fully knowledgeable in the

system's logic.

As a result of that event, the licensee

revised AP-006,

Procedure

Review and Approval Process,

to incorporate

guidance for

performing multi-disciplined procedure

reviews.

AP-006 was subsequently

revised again to require reviews by Engineering personnel

on all

surveillance test procedures

involving the addition or deletion of

components to be tested

or acceptance criteria changes,

as was the case

with HST-I0072, Revision 7.

The inspectors

concluded that,

although the new requirement in AP-006

for surveillance test procedure

reviews by Engineering

was satisfied,

the preparation

and reviews for procedure 'HST-I0072, Revision 7 wer e

inadequate.

This was contributed to by the technical

reviewer not being

totally independent

from the preparer,

and the lack of attention to

detail while researching circuit diagrams

associated

with the

SSPS

General

Warning inputs.

Technical Specification (TS) 6.5.1.1.1 requires

a safety

and

a technical evaluation to be prepared for each procedure

required by TS 6.8.

This includes surveillance

procedures

for reactor

protection system tests

and calibrations [incorporated

by reference in

Regulatory Guide 1.33, Appendix A, item 8.b.(1)(l)].

sgates that technical

evaluations will be

performed by personnel

qualified in the subject matter

and will

determine the technical

adequacy

and accuracy of the proposed activity.

C.

H2.3

a.

b.

. 18

The failure to perform an adequate

technical evaluation for procedure

HST-I0072, Revision 7, is contrary to this requirement

and is identified

as

a violation of TS 6.5.1.2.1

(50-400/97-06-06).

Conclusions

An inadequate

review of procedure

HST-I0072, Revision 7, led to a

partial safety injection actuation

on Hay 14,

1997.

One violation was

identified.

Haintenance

and Testin

of Auxiliar

Feedwater

Flow Control Valves

Ins ection Sco

e

61726

62707

37551

The inspectors

reviewed the licensee's activities to return the

auxiliary feedwater

(AFW) system to service at the end of refueling

outage

7 (RFO-7).

This included resolution of a previously identified

deficiency which prevented the motor-driven auxiliary feedwater

(HDAFW)

pump flow control valves

(FCVs) from opening under high differential

pressure

(DP).

Observations

and Findin s

The inspectors

observed the licensee's

inspection of the valve internals

during RFO-7 for the

HDAFW pump

FCVs (1AF-49, 50,

and 51).

These

activities attempted to correct potential

causes for the valves'ailure

to open under

high DP when required to operate

in Hode 3 (Hot Standby).

Licensee

personnel

performed troubleshooting

and repaired

(as necessary)

the plug and cage assembly for each valve.

The troubleshooting

activities were primarily focused

on the valves themselves,

and not

their actuators.

Following inspection

and maintenance,

which included

removal of excess

packing rings and inspection of other internal

components,

the valves were reinstalled in the plant.

Subsequently

on June 2,

1997, all three valves failed to open during

post-maintenance

testing (per EPT-711,

Hotor Driven Auxiliary Feedwater

Pumps

Flow Control Valve Stroke Test,

Revision 2).

At the time, the

plant was preparing to enter

Hode 3 from Hode 4 (Hot Shutdown) with

pressures

below 100 psig and

AFW pump discharge

pressure

approximately

1650 psig.

This equated to a valve

DP of above

1500 psid.

The test failures were similar to binding 'problems

which occurred in

Spring 1996 (documented in NRC Inspection Report 50-400/96-04).

Following the June 2,

1997 failures, the licensee

placed caution tags

on

the valves'ain control board switches alerting the control

room staff

to declare

them inoperable if they were less than full open.

The

licensee

intended to enter

Hode 3 to conduct further testing at higher

pressures.

This would identify the steam generator

pressure

above which the valves differential pressure

would be low

enough to allow them to open.

l

Later on June 2, with the plant still in Hode 4

(AFW system not yet

required to be operable

by TS), the inspectors

observed the caution tags

on the main control board and questioned

plant personnel

about the

valves'revious testing.

Plant personnel

indicated that the

troubleshooting

and maintenance activities during the outage did not fix

the binding problem and that the valves

had failed the EPT-711 post-

maintenance test during the previous shift.

The inspectors

then learned

of the licensee's

intent to proceed to Hode 3

(AFW system required to be

--- operable) to conduct further testing without having corrected the

binding problem.

The inspectors

informed licensee

personnel

that Technical Specification 4.0.4 prohibited entry into an Operational

Hode or other specified

condition unless the surveillance

requirements

associated

with the

Limiting Condition f'r Operation

had been performed within the stated

surveillance interval or as otherwise=-specified.

The inspectors

informed licensee

management that,

because

the

HDAFW pumps were required

to be oper able in Hode 3, all attendant

surveillance testing must be

performed satisfactorily prior to the mode change.

The TS Bases stated

that the valves

may be in any position, in any mode of operation,

thereby allowing full use of the

AFW system for activities such

as to

adjust steam generator

water levels prior to and during plant startup,

as

an alter nate feedwater

system during Hot Standby, for cooldown

operations,

and to establish

and maintain wet layup conditions in the

steam generators.

The inspectors

added that 18-month

TS Surveillance

Requirement 4.7.1.2.1.b.l,

which required each flow control valve with

.

an auto-open

feature to respond

as required to a test signal,

had not

yet been satisfied

due to the post-maintenance

test failures.

Based

on discussions

with the in'spectors,

the licensee

retested

the

valves

on June

2 (again using procedure

EPT-711) with the plant still in

Hode 4.

When the valves failed again,

work requests

were generated to

inspect the valve actuators.

Plant personnel

discovered that the

actuator springs were set with a preload value corresponding to a three-

inch valve stroke.

The valves were installed in a two-inch stroke

application.

Haintenance

technicians

corrected the spring preload value

to that for a two-inch stroke

and the valves were successfu'Ily tested

(under .high DP) prior to entering

Hode 3 on June 3,

1997.

The licensee

discovered that the actuator spring preload values

had been

set for a three-inch stroke since initial plant startup in 1987.

The

licensee

concluded that the incorrect actuator spring pr eload settings

likely accounted for the 1996 and 1997 test failures as well as other

valve binding examples

noted by operators

during routine

AFW operations.

The licensee's

Operations Surveillance Test

(OST) procedures

which

implemented

TS surveillance

requirements

tested the

FCVs under zero

DP

(with both

HDAFW pump discharge isolation valves located upstream 'of the

FCVs shut).

The FCVs had opened successfully

under this condition which

satisfied the surveillance test criteria that had been established

in

the OSTs.

The licensee's

intentions to proceed to Hode 3 on .June 2,

1997, without demonstratiqg

(through post-maintenance

testing with

procedure

EPT-711) that the-FCVs would successfully

open under high DP

were based

on the previous successful

surveillance testing using the

0

C.

H8.1

= 20

OSTs .and the position that the

AFW system

was considered

as

long as the valves were maintained in a full open position.

The

licensee did not link the failures under procedure

EPT-711 to the TS

surveillance

req'uirement to respond

as required to a test signal

and did

not consider

the TS Bases during their evaluation.

10 CFR 50 Appendix B, Criterion XVI, Corrective Action, requires that

measures

be established to assure that conditions adverse to quality

such

as deficiencies,

deviations,

and nonconformances

are promptly

identified and corrected.

These requirements

are further delineated in

Section

12 of the licensee's

corporate Quality Assurance

Program Hanual,

Revision 18.

The licensee's

activities prior to the inspector

s'nvolvement

were ineffective to resolve the longstanding binding problem

of the

HDAFW FCVs and is identified as

a violation of 10 CFR 50

Appendix B, Criterion XVI (50-400/97-06-07).

Conclusions

A violation was identified for inadequate

corrective actions for

resolving binding problems with the motor-driven auxiliary feedwater

pump flow control valves.

Hiscellaneous

Haintenance

Issues

(90712,

92700,

92902)

Closed

VIO 50-400/95-17-02:

Failure to provide adequate

instruction

for maintenance

on safety related valves.

The licensee's

response to this violation, dated January

10.

1996,

was

accepted

by the

NRC on January

19,

1996.

Corrective actions described

were verified by the inspector

as being completed.

The action included

a revision and issuance of a new maintenance

procedure for dissembling

and reassembling of valves.

In addition,

training was held for maintenance

personnel.

The training included

a

discussion of the causes of the issue,

lessons

learned,

and

a review of

the corrective actions.

This item is closed.

Closed

LER 50-400/95-007-00:

Inadvertent start of the turbine driven

auxiliary feedwater

pump.

During scheduled testing of the lA-SA 6.9 'kV safety bus on September

1,

1995, the steam supply valve (1HS-70)

opened for the'urbine driven

auxiliary feedwater

(TDAFW) pump.

The valve responded

as designed,

but

since the test

was being performed in Hode

1 (at 75 percent

power) with

main steam available,

the

TDAFW pump started.

The pump's response

was

unexpected

because

the procedure,

which was normally performed with the

plant shutdown, did not alert operators that the pump would start if

steam

was available during testing.

The licensee

discovered

aqother test deficiency while investigating the

unplanned

pump start.

The licensee

had failed to perform Technical

Specification

(TS) required monthly Trip Actuating Device Operational

H8.3

. 21

Testing

(TADOT) for an under voltage relay

(86UVX) which opens the

TDAFWP

steam supply valves on an emergency,bus

undervoltage.

The missed

monthly testing was caused

by an erroneous

assumption that testing of

the undervoltage relay (86UV) that actuated the motor-drive'n

AFW pumps

satisfied testing for the relay associated

with the

TDAFW pump.

The

86UVX feature

was tested every 18-months during the loss of offsite

power test,

but was never realized

as

a monthly requirement.

Both of the above reported

items were caused

by procedural

deficiencies

which have since

been corrected

and verified by the inspectors.

The licensee's

identification of the missed

TADOT testing requirement

prompted

a commitment to perform

a comprehensive

review of Technical

Specification surveillance requirements.

A thorough licensee

review of

protective logic circuit testing 'in 1996 resulted in 35 additional

missed surveillances

being reported in LERs 50-400/96-002-00

through

-

.

13.

The -inspectors

have assessed

portions of the licensee's

logic

circuit review effort as reported in Inspection Reports 50-400/ 97-03

and 96-07 and determined the review effort to be good.

The inspectors

- are continuing to review the licensee's

corrective actions for'he 1996

items to assess

the current state of the licensee's

surveillance

program

and to address

common themes.

The results of this review will be

contained in a subsequent

inspection report when

LER 96-002

and its

supplements

are closed.

Several

additional

items outside of the scope of the licensee's

logic

circuit review have been reported in LERs since

1995.

The comprehensive

TS surveillance

review to which 'the licensee

committed in LER 50-400/

95-007 is scheduled to continue beyond

1997 and address

areas in

addition to the logic and circuit testing addressed

in LER 96-002.

The

assessment

of this effort will be included in the review of LER 96-002.

This item is closed.

Closed

VIO 50-400/96-07-01:

Failure to follow surveillance test

procedures.

I

Closed

LER 50-400/96-015-00:

Unplanned partial engineered

safety

feature actuation

dur ing surveillance

testing due to operator error .

,. The corrective actions described in the licensee's

response,

dated

November 13,

1996,

were verified by the inspector

as completed.

The event

was reported

by the licensee in LER 50-400/96-015-00,

issued

on September

11,

1996.

A near term improvement plan (NTIP) was

developed

and issued to provide

a framework to reduce further violations

and improve performance.

This plan was discussed

in NRC inspection

report 50-400/97-03,

section 08.5.

An assessment

of the effectiveness

of the NTIP was conducted

by the licensee

and

a report issued to the

Hanager of Operations

on Harch 31,

1997.

These self-assessments

are

scheduled to continue perjodically.

These

items are closed.

H8.4

H8.5

H8.6

H8.7

~ 22

Closed

VIO 50-400/97-01-04:

Failure to have

an adeqQate

procedure

for

correctly calculating the moderator temperature coefficient.

Corrective aetio'ns described in the licensee's

response,

dated April 14,

1997,

and supplemented

on Hay 22,

1997 were reviewed

and verified by the

inspector.

The procedure,

EST-702 was revised

on February

7 1997 to

correct the error.

The procedure is currently on =administrative

hold

since it is not expected to be performed until June

1998.

Prior to that

time, further enhancement;s

may be made.

This item is closed;

'losed

LER 50-400/97-012-00:

Auxiliary Control

Panel testing

deficiency.

This LER was issued

on Hay 5,

1997 to document

a condition related to

inadequate testing of control

power circuitry for the Auxiliary Control

Panel

(ACP).

Seventeen

interposing relays that energize

and actuate to:

transfer the control path through alternate

fuses

on a transfer to the

ACP were not verified operable in previous

ACP testing.

This condition

was caused

by an incorrect interpretation of TS testing requirements

and

an incomplete understanding of the function of the interposing relays.

The licensee's

corrective actions involved performing

a sample review of

other

remote shutdown panel transfer circuitry and completing

operational

surveillance test

OST-9005T,

discussed

in paragraph

H2.1 of

this inspection report, for those circuits that had not been tested.

The inspectors verified that the corrective actions were completed.

The

'licensee

intends to combine OST-9005T with OST-1813 for the next

refueling outage

(Action Item Assignment 97-00735).

The failure to verify the operability of the 17 interposing relays

and

the subsequent

transfer of control

power through alternate

fuses is a

violation of TS 4.3.3.5.2.

This licensee-identified

and corrected

violation is being treated

as

a Non-Cited Violation, consistent with

section VII.B.1 of the Enforcement Policy (NCV 50-400/97-06-08).

This

LER is closed.

Closed

LER 50-400/97-014-00:

Safety Injection during Solid State

Protection

System surveillance testing.

This

LER documented the condition that resulted in the partial safety

injection during Solid State Protection

System surveillance

testing.

This event

was discussed

in this report, section 01.3 and H2.2 as

a

violation (50-400/97-06-06) of TS 6.5.1.2.1.

The corrective

actions

will be reviewed during closure of the violation.

This

LER is closed.

Closed

VIO 50-400/95-15-01:

Failure to proper ly annotate

sur veillance

test.

Corrective actions for this event were described in LER 50-400/95-008-

00, issued

September

28,

$995 and in the licensee's

response letter,

dated

December

4,

1995.

H8.8

~ 23

The response letter

was accepted

by the

NRC on December

18,

1995.

The

corrective actions in both documents

were reviewed by the inspector

and

verified as completed.

A memo to operations

personnel

was issued

October

3,

1995 "to clarify expectations

and to assign responsibility for

proper

completion of equipment inoperability records.

LER 50-400/95-008

was closed in NRC inspection report '50-400/95-15

and-

was included here for reference

information.

This item is closed.

Closed

VIO 50-400/95-15-02:

Failure to provide for the review of a

safety injection test procedure.

LER 50-400/95-009-00,

issued

November

3,

1995,

and the licensee's

response,

dated

December 4,

1995,

presented

corrective actions for this

issue.

NRC accepted

the licensee's

response

on December

28,

1995.

The

corrective actions in both documents

were reviewed

and verified as

completed

by the inspector.

H8.9

LER 50-400/95-009-00

was closed in NRC inspection report 50-400/95-17

'nd was included here for reference.

This item is closed.

Closed

VIO 50-400/96-11-02:

Failure to test

IRC-115 from the

Auxiliary Control Panel.

Closed

LER 50-400/96-025-00:

Procedure deficiency caused

by personnel

error .

Corrective actions were described in the licensee's

response,

dated

-Harch 3,

1997,

and accepted

by the

NRC on Harch 21,

1997.

Also, the

licensee

issued

LER 50-400/96-025-00

which described the event

and

presented

corrective actions.

These two documents

were reviewed by the

inspector

and verified that the corrective actions

have been completed.

LER 50-400/96-025-00

was discussed

in NRC inspection report 50-400/97-01

and was kept open pending completion of the corrective actions.

The

actions pertaining to the missed surveillance

have been verified as

completed

and these

items are closed;

H8.10

Closed

LER 50-400/95-003-00:

Inadequate testing of air handling unit

AH-86, cooling water supply valves.

This LER reported deficiencies in the testing methodology for safety

The

LER was discussed

in NRC inspection report

50-400/95-011,

but was kept open pending the licensee's

completion of

their corrective actions.

The corrective actions described in the

LER were verified as completed

by the inspector.

The corrective actions involved revision of

procedures

and performance of a validation test.

The licensee

made

appropriate site personnel

aware of this issue

so that when they

evaluate future test results or plant modifications, proper

consideration will be devoted to indirectly actuated

components. i

El

E1.1

a.

b.

24

This .item was

a precursor

to the licensee's

1996 Technical Specification

'urveillance

Review program. which identified 35 additional reportable

missed surveillance

requirements

as reported in supplements

to LER 50-

400/96-002.

The inspectors

are continuing to review the licensee's

corrective actions for the 1996 items

and plan to address

the licensee's

overall .program for performing logic testing during the continuing

review.

LER 50-400/95-003-00 is closed.

'.'III. En ineerin

Conduct of Engineering

S ent Fuel

Pool

Tem erature Alarm

Ins ection Sco

e

37551

The inspector

reviewed alarm setpoints

during routine tours.

The spent

fuel pool temperature

had been recently evaluated

by the licensee

as

par t of the spent fuel pool

FSAR upgrade. 'he inspectors

reviewed the

alarm response

procedure

APP-ALB-023, which included the spent fuel pool

high temperature

alarm; procedure

EGR-NGGC-0005,

Engineering Service

Requests

(ESR), Revision 4;

FSAR section 9.1.3;

ESR 9600126,

Spent

Fuel

Pool Heat

Load Analyses Revision, Revision 0;

ESR 9700272,

Realignment

of CCW to the

SFP Heat Exchangers,

Revision 0;

and

ESR 9700447,

Spent

Fuel

Pool High Temperature

Alarm Setpoint

Change,

Revision

0

.

Observations

and Findin s

The inspectors

found that the spent fuel pool high temperature

alarm was

set at 144 degr ees Fahrenheit

(F).

Recent

reviews by the licensee

had

changed

some of the design

and operating parameters

for the spent fuel

pool.

ESR 9600126,

Spent

Fuel

Pool Heat Load Analyses Revision,

Revision 0,

was the engineering

document that reviewed the spent fuel

pool heat load design for full core off-load changes

and supported

FSAR

changes.

ESR 9700272,

Realignment of CCW to the

SFP Heat Exchangers,

Revision 0, analyzed the component cooling water

(CCW) to the spent fuel

pool

(SFP)

heat exchangers

after

a loss of coolant accident

(LOCA).

ESR

9700272

made changes to the maximum operating temperature of the spent

fuel pools prior to the start of a

LOCA.

This was based

on radiation

doses in the reactor auxiliary building immediately after

a

LOCA that

would prohibit realignment of the appropriate

valves to reinitiate

CCW

to the SFP heat exchangers.

The new maximum oper ating temperature for

the spent fuel pool cooling system

was calculated to be 112 degrees

F

prior to a

LOCA.

The concern is that operator

access to realign

CCW

flow valves to the

SFP could be effected by high radiation during

a

LOCA.

The inspector questioned

why the

SFP high temperature

alarm set point

was not set at

a lower value in light of ESR 9700272.

The inspector

considered that procedure,EGR-NGGC-0005,

which governs the

ESR process,

listed design inputs in Attachment

2 including alarms for operations,

testing,

and maintenance.

The alarm setpoint of 144 degrees

F was above

4

25

the maximum operating temperature

and should have been evaluated

during

the

ESR 9700272 process.

The inspector discussed this issue with the

licehsee.

The licensee initiated

ESR 9700447,

Spent

Fuel

Pool High

Temperature

Alarm Setpoint

Change,

Revision

0 which was issued

Hay 22,

1997 to revise the alarm setpoint to 105 degrees

F.

The problem of not

considering

an alarm setpoint

change

when modifying the maximum

.operating. temperature

was considered

a weakness

in the implementation of

the

ESR process.

V

c.

Conclusions

A weakness

was identified in a spent fuel pool cooling design

change in

that it did not consider the high temperature

alarm setpoint.

E1.2

Emer enc

Service Water

Pum

"A" Re lacement

a.

Ins ection Sco

e

37551

The inspectors

reviewed the performance testing of the new Emergency

Service Water

Pump "A" to determine if it met the design requirements.

The inspector

reviewed the

pump performance

curves for the old "A" pump

with the

new "A" pump.

b.

Observations

and Findin s

The inspector

reviewed the new pump performance

data

and system

component flow data

(EPT-250) with the

ESW system engineer.

The pump

performance test data

had been plotted on the vendor supplied

pump curve

and the inspector

observed

reasonably

close correlation to the vendor

curve.

The inspector observed that the new pump provided at least

double the margin for the limiting ESW components.

The new pump

increased

system flow from 17,200 gallons per minute to 19,000 gallons

per minute.

C.

E1.3

E7

E7.1

Conclusions

The inspector

concluded that the

ESW "A" pump replacement

had

successfully

increased

design margin,

as expected.

En ineerin

Su

ort for the Refuelin

Outa

e

The inspectors

determined that engineering

support for the refueling

outage

was adequate.

Several

nuisance

alarms annunciated

in the control

room due to engineering modification problems during the star t-up.

Quality Assurance in Engineering Activities

S ecial

FSAR Review

37551

A recent discovery of a licensee operating their facility in a manner

contrary to the Updated Final Safety Analysis Report

(UFSAR) description

Qs

E8

E8.1

~ 26

highlighted the need for

a special

focused review that compares plant

practices,

procedures

and/or parameters

to the

FSAR descriptions.

While

performing the inspections

discussed. in this report, the inspectors

reviewed the applicable portions of the

FSAR that related .to the areas

inspected.

The licensee

made

a presentation

to the

NRC on Hay 31,

1996 concerning-

their corporate-wide

plan for reviewing the

FSAR at the CPLL sites.

The

program has generated

a 1:arge

number of condition reports at 'the Harris

Plant

(323 by the end of'he inspection

per iod).

The results

from this

program will be reviewed in the closure of Unresolved

Item 50-400/96-04-

04, Tracking

FSAR Discrepancy Resolution.

A condition involving

operation outside the design basis of the plant, identified by the

licensee,

is addressed

in paragraph

E8.1.

In addition,

a plant

condition that was different than the

FSAR in relation to the reactor

coolant

pump oil collection system

was reported

in LER 50-400/97-010-00

.

and is addr essed in section E8.4.

The inspector s did not find any

additional discrepancies

other than those identified by the licensee.

Miscellaneous Engineering Issues

(90712,

92700,

92903)

Closed

LER 50-400/96-023-00

-01

and -02:

Design deficiency in

emergency diesel

generator protection circuitry.

This LER was discussed

in Inspection Reports

50-400/96-11

(Section E8.1)

and 50-400/97-03

(Section 08.1).

It reported

a design deficiency in the

protective circuitry for the emergency diesel

generators

(EDGs).

Specifically, the Final Safety Analysis Report

(FSAR), Section

8.3.1.1.2.14.g,

stated that

a voltage restrained

overcurrent relay (51V)

was capable of providing EDG protection by sensing

an overcurrent

condition during periodic load .testing of the

EDG coincident with a loss

of offsite power

(LOOP).

The 51V relay was supposed to trip the

EDG

output breaker

(Breaker

106 for train "A" and Breaker

126 for tr ain "B")

following the

LOOP.

Tripping either Breaker

106 or 126 would cause

an

under voltage on the associated

engineered

safety features

(ESF) bus,

resulting in all non-emergency

loads being stripped

from the bus,

and

the actuation of the emergency

sequencer

LOOP program.

The licensee identified that, during periodic load testing situations

coincident with a

LOOP, the

EDG would not be overloaded sufficiently to

actuate the 51V relay.

This would ultimately prevent the sequence

from

actuating the

LOOP program because

the associated

ESF bus would not have

been deenergized

with the

EDG continuing in the test

mode to pick up

non-emergency

and existing emergency loads.

During this inspection period, the licensee modified the

EDG protective

circuitry to correct the 51V design deficiency.

The modification

'ESR 970005)

used existing

LOOP relays

and their associated

non-Class

1E

input signals to cause the

EDG output breakers

and emergency bus/unit

auxiliary bus

(UAB) tie breakers to open on a

LOOP with the

EDG in test.

This would result in the

ESF busses

being deenergized,

allowing the

safe'guards

sequencers

to start the

LOOP program as required.

The

~ 27

licensee's

reliance

on non-Class

1E signals (tripped signals

from main

generator

lockout relays

and open signals

from unit auxiliary and

startup transformer breakers

supplying unit auxiliary busses)

constituted

an u'nreviewed safety question

per

10 CFR 50.59 requiring

NRC

approval of the modification prior to its implementation.

The NRC's

approval

came via License

Amendment

No. 72, dated

Hay 8,

1997.

The modification was installed for both electrical trains

and was

successfully tested in accordance

with the following temporary test

procedures:

II

~

EPT-828T,

Temporary Procedure for Breaker

102

HOC and Relay 62-

1/1622 Logic Check,

Revision 0;

~

EPT-823T, Temporary Procedure for CR1/1748 Breaker

Logic Check,

Revision 2;

~

EPT-824T,

CR3/1748 Breaker Logic Check, Revision 0;

~

EPT-826T, Temporary Procedure for Acceptance Testing of Breaker

105 and 106 Trip Logic Hodification, Revision 0.

~

EPT-827T,

Temporary Procedure for Acceptance Testing of Breaker

125 and 126 Trip Logic Hodification, Revision 1.

The inspectors verified that the modification was installed

as specified

in the

ESR package

and verified that the above procedures

were completed

satisfactorily.

Other aspects of the modification included revising

procedures to ensure that uninterruptible power supplies affecting the

non-Class

1E inputs to the

LOOP circuitry were available during normal

EDG parallel operations.

The inspector observed

a training session

held

for operators describing the new modification and its affect on routine

EDG testing.

Re ulator

Si nificance

As reported in Supplement

2 to LER 50-400/96-023, this design deficiency

was initially identified and questioned

by the licensee in September

1986, prior to the plant receiving its operating license.

After re-

discovering the problem in late 1996, the licensee

resear ched old

correspondence

between the utility, its ar'chitect engineer,

and the

EDG

vendor from 1986-87

and found no documentation of final resolution of

this condition when it was originally questioned.

The licensee

concluded that the issue

had been erroneously

dropped since it was not

tracked in any of the licensee's

ongoing programs during commercial

operation.

The Shearon Harris

FSAR, Section 7.3 ' '.1,

Emergency

Power Systems,

stated that the

EDGs will be periodically tested

under load.

Should

normal

AC power be lost dgring such

a condition, the

ESF bus tie breaker

between the

EDG and the

ESF bus would open, all nonsafety-related

loads

would be shed

from the

ESF bus without being re-sequenced,

and the

ESF

~ 28

bus automatic loading sequence

would'begin simultaneously.

10 CFR 50.59

states that licensees

may make changes

in the facility as described in

the safety analysis report without prior Commission approval,

unless the

proposed

change 'involves

a change in the Technical Specifications

incorporated in the license

or

an unreviewed safety question.

The 51V

deficiency constituted

a change to the facility and an unreviewed safety

question

because

the probability of occurrence

or the consequences

of an

accident

or malfunction of equipment important to safety previously

evaluated in the safety analysis report may have been increased.

This

related specifically to the potential failure of the emergency

sequencer

to actuate

and start

ESF components

during

a loss of offsite power

accident.

The deficiency was significant because

the plant's design

basis,

as translated in drawings

and normal

and emergency operating

procedures,

was predicated

on the assumption that the sequencer

would

respond

and initiate emergency

loads

as required.

Plant operation

from issuance of the operating license in 1986 through

December

1996 with the 51V deficiency was considered

an apparent

violation of 10 CFR 50.59

(EEI 50-400/97-06-09).

In view of the licensee's

identification and resolution of this and

other design deficiencies

since

1996, the inspectors

concluded that the

licensee's

oversight in 1986 was not characteristic of its current

performance.

This old design issue

was re-discovered

during a

comprehensive

review related to electrical circuit and logic testing in

late 1996,

and would not likely have been identified during routine

surveillance or operational activities.

The finding was

a good example

of the increased

questioning attitude exhibited by the licensee

over the

past year.

The licensee

was continuing its comprehensive.

FSAR review

program

as this inspection period ended.

Items identified by the

FSAR

review are being. tracked under Unresolved

Item 50-400/96-04-04.

All

corrective actions for the 51V issue

have been completed.

This LER and

its supplements

are closed.

Closed

VIO 50-400/96-06-01:

Failure to conduct

10 CFR 50.59 review

for diesel

generator

overload protective interlocks that were not

installed for the component cooling water

pump breakers.

Corrective actions described in the licensee's

supplemental

response,

dated April 8,

1997,

and initial response,

dated October

7,

1996,

were

reviewed

and verified by the inspector.

These

responses

were accepted

by the

NRC on April 29,

1997.

Corrective actions included installation of mechanical

inter locks and

revised operating procedures.

Installation of the kir k key interlock

modification was observed

by NRC inspectors

and is reported in NRC

inspection report 50-400/96-10,

section H1.3.

Additional steps to

prevent recurrence

includes the continuing

FSAR review.

This item is

closed.

E8.3

E8.4

~ 29

Closed

VIO 50-400/96-06-02:

Failure to install interlocks for the

charging safety injection pump and removal of key interlocks which were

referenced

in plant drawings.

Closed

LER 50-400/96-014-00:

Condition outside of design basis in

which two charging/safety injection pumps were inadvertently connected

to the

same

emergency electrical

bus.

The licensee's initial violation response,

dated October

7,

1996, 'and

supplemental

response,

dated April 8,

1997,

were reviewed

and accepted

by the

NRC on April 29,

1997.

The inspector verified completion of'he

corrective actions.

A 10 CFR 50.59 saf'ety evaluation

was completed

by

July 7,

1996,

and concluded that no unreviewed safety question existed.

Administrative controls were utilized to inhibit racking in breakers to

the connect position simultaneously

on the

same

bus until mechanical

interlocks were installed.

Installation of the mechanical

interlocks

was completed

by November

1996 and was observed

by an

NRC inspector

as

reported in NRC inspection report 50-400/96-010,

paragraph

H1.3.

LER 50-400/96-014-00

was reviewed and discussed

in NRC inspection report

50-400/96-09,

section 08.2.

The corrective

actions described in the

LER

were verif'ied by the inspector

as completed.

In addition, the licensee

has prepared

and issued training guides to applicable personnel

on a

selection of regulatory issues.

These include guidance

on

repor tability, preparation of LER and other regulatory correspondence.

The guides are self study and should assist in reducing missing

r eportability issues.

These items are closed.

Closed

LER 50-400/97-010-00:

Design Deficiency

- Reactor Coolant

Pump

Hotor Oil Collection System.

This

LER was issued

on Hay 5,

1997, to document several

design

deficiencies in the Hotor Oil Collection System

(OCS) on the Reactor

Coolant

Pumps

(RCP).

The licensee

on April 18,

1997, determined that

the

RCP motor

OCS did not meet applicable design requirements.

The

Final Safety Analysis Report

(FSAR) Section 9.5.1 states that the

RCPs

are equipped with an oil collection system that is designed

and

installed such that failure will not lead to a fire during normal

and

design basis accident conditions.

It also states that the system is

capable of collecting oil from all potential pressurized

and

unpressurized

leakage sites in the

RCP lube oil system.

This design

was

established to meet the fire protection program requirements of NUREG-

0800/NRC Branch Technical Position

CHEB 9.5-1.

The deficient

OCS enclosure did not satisfy the above design

requirements.

A six-inch wide gap was found in the

OCS enclosure at the

base of the upper lube oil cooler on all of the

RCP motor s, which could

allow RCP oil to spray or splash out of the

OCS onto the

RCP.

The lower

oil pot drain valve pipe nipple extended

beyond the motor casing,

thereby creating

a leak pyth outside the

OCS enclosure

on all of the

RCPs.

The upper oil pot on two of the

RCPs were found to have

a capped

dragon line.

The capped drain lines could cause the upper oil pot to

30

overfill with oil.

The upper

OCS catch

pans

on the "B"'CP could be

filled by sprinkler water which woul.d make them unavailable for

containing oil, since the "B" RCP enclosure

has several

overhead fire

protection spr4klers.

This condition was caused

by inadequate

OCS design detail in the

Westinghouse

drawings supplied to CP&L, which allowed the system to be

incorrectly fabricated during initial plant construction.

Another

factor contributing to the improperly constructed

OCS enclosure

was

a

lack of understanding of the design basis for the system during

construction.

The licensee modified and repaired the

OCS enclosure to resolve the gap

at the base of the upper lube oil cooler.

This was completed

on all

three

RCPs currently in use.

The licensee will modify the spare

(old "B" RCP) before it is used

as

a replacement

in refueling outage

8

.

(ESR 97-00297).

The spare

RCP has been placed

on hold pending

completion of the modifications on the

OCS enclosure.

The additional

deficient conditions were corrected

by April 14,

1997.

Re ulator

Si nificance

The

OCS deficient condition resulted in operation outside the design

basis of the plant, which was contrary to the

UFSAR Section 9.5.1

description.

This design

was established to meet the fire protection

program requirements of NUREG-0800/NRC Branch Technical Position

CMEB

9.5-1.

This

FSAR design discrepancy will be reviewed in the closure of

Unresolved

Item 50-400/96-04-04,'racking

FSAR Discrepancy Resolution,

addressed

in paragraph

E7.1.

The licensee

conducted

a thor ough review of this issue

and took

appropriate corrective actions in responding to the finding.

The

inspectors

reviewed the circumstances

surrounding the design deficiency

in the

RCP motor oil collection system,

and verified that the

modifications

made were completed

on the three

RCPs currently in use.

The future corrective actions will be reviewed during closure of the

Unresolved

Item.

This

LER is closed.

IV. Plant Su

rt

Radiological Protection

and Chemistry (ROC) Controls

General

Comments

71750

92904

The inspector

observed

radiological controls during the conduct of tours

and observation of maintenance activities and found them to be

acceptable.

The inspector observed that

a requirement to frisk hands

prior to removing an article from the small article monitors

had been

initiated.

This change

was in response to URI 50-400/97-300-.03.

31

Status of EP Facilities.

Equipment,

and Resources

P2.1

Facilit

Ins ection

a.

Ins ection Sco

e

82701

The inspectors -examined the licensee's .emergency

response facilities

(ERFs)

and equipment to determine whether

they were maintained in a

state of operational

readiness,

and whether

changes

made since the last

such inspection

(October

1995) were technically adequate

and in

accordance

with NRC requirements

and licensee

commitments.

b.

Observations

and Fihdin s

The inspectors

toured the Technical

Support Center

(TSC), Operational

Support Center

(OSC),

and Emergency Operations Facility (EOF).

Selected

equipment

and supplies within these facilities were inspected,

including

the Emergency

Response Facility Information System

(ERFIS)

and various

communications

systems.

All tested

equipment

was found to be in

operable condition, with one exception -- an operational

problem with

ERFIS at the

EOF.

When the

EOF is activated,

data from the Safety

Parameter

Display System

(SPDS),

which is a subset of ERFIS, would

typically be displayed

on the three large front-projection video

monitors arrayed

across

one wall of the

Command

Room.

The SPDS screens

could not be selected

and displayed from the computer console in the

EOF

management

area.

This computer problem, discovered at about 5:00 p.m.

on June 3,

was resolved within about one hour

using on-shift expertise.

Assessment

by the licensee

determined that ongoing cabling modifications

in the

EOF had affected

normal operation of the ERFIS display.

The

functionality of the

EOF would not have been significantly impeded in a

real

emergency

because

the problem could have been corrected in a timely

manner,

even during off-hours.

The licensee's

emergency

response

facilities (particularly the TSC and

EOF) were very well designed

and

maintained

(aside

from the anomaly just discussed),

and employed state-

of-the-art displays of real-time data.

Hiscellaneous

instruments

and supplies stored in cabinets in the TSC,

OSC,

and

EOF were selectively examined.

The organization of these

cabinets

was excellent,

and no discrepancies

were identified.

c.

Conclusions

ERFs were well designed

and equipped,

and were maintained at an

acceptable

level of'perational

readiness.

P2.2

Public Alert And Notification S stem

a.

Ins ection Sco

e

82701

The inspector s reviewed tge licensee's

methodology for notifying the

public in the event of an emergency,

and the results of system testing

during 1995 and 1996.

b.

Observations

and Findin s

32

C.

P3

P3.1

a.

b.

The licensee maintained

a public alert and notification system

'consisting of 81'irens within the 10-mile Emergency Planning

Zone

(EPZ)

around the Harris Nuclear Plant (two sirens

were added in Wake County

during 1996).

In addition,

households within five miles of the plant

were provided tone-alert radios to -supplement the outdoor siren system.

The inspectors

reviewed the summary data,

as communicated to the, Federal

Emergency

Hanagement

Agency (FEHA), for 1995 and 1996 testing of the

siren warning system.

For the 81 sirens,

the aggregate

success

rates of

the biweekly silent tests,

quarterly growl tests,

and annual full-cycle

test (collectively termed "average siren availability) were 99.0 percent

for 1995 and 98.6 percent for 1996.

The applicable acceptance

criterion

used by FEHA for such test results is 90 percent.

The success

rates of

the full-cycle test alone were 98.7 percent for 1995 and 91.4 percent

for 1996.

Conclusions

The operational

status of the siren system exceeded

the minimum

requirements

established

by FEHA.

EP Procedures

and Documentation

Emer enc

Res

onse Plan

Ins ection Sco

e

82701

The inspectors

reviewed the licensee's

maintenance of the Emergency Plan

(Plan)

and selected'commitments

therein,

and reviewed recent revisions

to the Plan to determine whether changes

wer e made in accordance

with

10 CFR 50.54(q).

Observations

and Findin s

Since the previously referenced

October

1995 inspection,

the licensee

has promulgated five revisions

(Revisions

26 through 30) of the Plan.

The version in effect at the time of the current inspection

was

Revision 30, effective February 13,

1997.

Review of Revisions

26

through 30 identified many substantive modifications, including changes

- in the Emergency Action Levels (EALs), which formed the basis for the

emergency classification methodology.

Hany other changes

were judged to

be minor or administrative in nature,

including some organizational

modifications.

During review of documentation

associated

with Revision 28 (which

comprised editorial "cleanup" only), the inspectors

noted that the Plan

revision was processed

by the licensee's

Document Services

group and

assigned

an effective date of July 31,

1996.

However, the required

fin'al approval of Revisiog 28 by the Plant Nuclear Safety Committee

(PNSC) did not transpire until August 1,

1996.

This process

was not in

accordance

with Administrative Procedure

AP-006,

"Procedure

Review and

33

Approval" (the version in effect at the time was Revision 24, dated

June 3, 1996), which specified in Section 5.1.4 that

PNSC approval

was

required prior to a Plan change being finalized.

This failure to follow

an administrativ'e procedure constitutes

a violation of mino'r

significance

and is being treated

as

a Non-Cited Violation (NCV),

consistent with Section

IV of the

NRC Enforcement Policy.

(NCV

50-400/97-06-10:

Failure to follow procedural

requirements

in the

processing of Emergency Plan, Revision 28)

The inspectors

reviewed the primary and alternate

means

used by the

licensee to notify its Emergency

Response

Organization

(ERO) personnel

if an emergency is declared during off-hours.

These processes

were

described in Plan Sections 3.8.4

and 4.2.f, respectively.

The automated

calling system

used

a computer-driven

program to methodically fill ERO

g

ositions

as personnel

responded telephonically following notification

y the system.

In the event of the automated

system's unavailability,

the alternate

methodology comprised

a system that made

use of (a)

pager s

carried by "key position"

ERO personnel,

(b) Health Physics,

Chemistry,

and Haintenance

departmental

call-outs,

and telephonic call trees

facilitated by wallet-sized "call in cards".

This methodology appeared

to be well designed

and maintained,

with quarterly updates of the cards.

Although no regulatory or Plan requirements

existed for testing of the

primary and backup

ERO notification systems,

the licensee

was regularly

testing the primary system,

generally on

a monthly basis except during

refueling outages.

However, the inspectors

discovered that the

licensee

had never conducted

a test or drill of the manual

backup system

for ERO call-out.

The inspectors

discussed

the desirability of

conducting

a test of the manual 'system at some reasonable

frequency in

order to verify its efficacy, to identify any procedural

deficiencies,

and to provide training to potential

users.

Licensee

management

representatives

agreed with this view. and informed the inspectors that

they planned to conduct tests of the backup system for off-hour

ERO

notification, probably at occasional

intervals in lieu of the usual

monthly primary system test.

'etween

the October

1995 inspection

and the ending date of the current

inspection,

emergency declar ations were made by the licensee

on

November

5 and December

14,

1995.,

and January

22,

1997.

All three were

made at the Notification of Unusual

Event

(NOUE) level.

The January

22,

1997,

and the December

14,

1995,

NOUE declarations

were the subject of

and tardy notification to the

NRC.

The inspectors

examined licensee

documentation of these

declarations,

and concluded that each

was correctly classified

based

on

the licensee's

EALs, and that, except

as addressed

above, notifications

to cognizant offsite authorities

were made in accordance

with

requirements

regarding timeliness

and content.

Documental

review confirmed the licensee's

conduct of the required

annual

review of EALs with State

and local governmental

authorities for

1995 and 1996.

This reviqw was accomplished

annually by means of a

formal presentation to cognizant officials during meetings of the Harris

4

C.

P3.2

a.

b.

. 34

Task. Force.

No dissenting observations

or comments

wete received

from

those agencies,

according to the licensee.

Conclusions

Emergency Plan Revisions

26-30 were made in accordance

with 10 CFR 50.54(q),

although failure to follow administrative procedures

in the

processing of Revision 28 was identified as

an

NCV.

Emergency

.

declarations

on November 5,

1995,

December

14,

1995,

and January

1997,

were made in accordance

with applicable procedures;

however,

as

previously addressed

by the

NRC, the December

14,

1995,

and the

January 22,

1997, event declarations

were untimely.

Plant

Emer enc

Procedures

82701

The inspectors

reviewed the licensee's

administration

of selected

Plan

.

requirements

through evaluation of the adequacy of the implementing

details contained in the Plant Emergency Procedures

(PEPs).

Based

upon

selective review, the licensee's

PEPs were determined to be generally

thorough in terms of detail

needed to implement the various requirements

and commitme'nts in the Plan.

No examples of Plan commitments without

appropriate

PEP implementing details were identified by the inspectors.

Selected

copies of the Plan and

PEPs which were available for use at the

TSC,

OSC,

and

EOF were checked

and found to be current revisions.

Staff Training and Qualification in EP

Trainin

of Emer enc

Res

onse Personnel

Ins ection Sco

e

82701

The inspectors

conducted

a broad-perspective

review of the training

program for the Emergency

Response

Organization

(ERO) to determine

whether Plan requirements

and the intent of regulatory requirements

were

being met.

Observations

and Findin s

The inspectors

reviewed the Plan and procedures

applicable to the

ERO

training program, particularly procedure

TPP-203,

"Emergency

Preparedness

Training Program".

The

ERO training program included the

requirement for specialized training courses for all

ERO personnel

(clearly delineated in a detailed position-to-course matrix), and

a

requirement for persons fillingdesignated

key ERO positions to

participate in an exer cise or drill as part of'he qualification

process,

and annually thereafter.

A program enhancement

implemented in

early 1997 was the addition of a mentoring process

for individuals newly

assigned to designated

key ERO positions.

l

c.

Conclusions

35

The licensee's

ERO training program was in accordance

with the Plan

training commitments

and with the intent of NRC regulatory 'requirements

and guidance.

The training program was recently enhanced

by the

addition of a mentoring process.

P5.2

Emer enc

Res

onse Drills

a.

Ins ection Sco

e

82701

The inspectors

compared the licensee's drill commitments to the actual

drills performed,

and evaluated the quality of those drills.

b.

Observations

and Findin s

The inspectors

reviewed the documentation

packages

for 13 training

drills that were conducted in 1996-1997.

The scenarios

were

challenging,

and the licensee's

critiques of the drills were very

detailed.

One exception

was the

EP drill scenario

which is discussed

in

NRC Inspection Report 50-400/96-02 Section 5.5.

The inspector concluded

that

a diligent effort had been

made to use the critique findings as

a

basis for initiatives to upgrade

ERO proficiency. The most recent

drills, conducted with each of the four ERO "teams" (designated

A, B, C,

and D) in January

1997,

were simulator-driven

and included scheduled

"freeze" points approximately every hour to allow critiques of

performance to that point.

Player

feedback regarding this approach

was

extremely positive.

c.

Conclusion

The licensee's

program of emergency

response training drills was

conducted in accordance

with Plan commitments,

and was judged to be

a

strength.

P6

EP Organization

and Administration

P6.1

EP Staffin

Chan es

a.

Ins ection Sco e

82701

The inspectors

reviewed this area to determine if any changes

in

management

or personnel

had occurred which could adversely affect the

management

and implementation of the emergency

preparedness

program.

b.

Observations

and Findin s

The organization

and management of the emergency

preparedness

program

were reviewed

and discussed

with licensee

representatives.

Several

staff and management

persqnnel

changes

since the October

1995 inspection

affected the emergency planning function, including reassignment

in

December

1995 of the position of'P Unit Supervisor.

In late 1996,, the

C.

P7

P7.1

a.

b.

C.

~ 36

EP Unit was transferred

"temporarily" from the Regulatory Affairs to

Plant Support Services

because of management

personnel

reassignments.

The inspectors

interviewed various cognizant staff and management

personnel

in an 'effort to ascertain

the effects of these

changes

on the

EP program at Harris.

No deleterious effects were identified.

The Harris Plant

had established

an

EP Advisory Board, consisting of

five senior managers

who provided advice

and guidance

on

EP matters

and

management

endorsement

of.. major decisions

regarding the

EP program.

The

inspectors

attended

the quarterly meeting of the Board on June 4,

1997.

Various topics relating to ERO staffing, drills, training,

and

procedures

were discussed.

The composition of this Board and the

substantive

guidance

and direction it provided were clear indicators of

a strong level of management

support for the Harris

EP program.

Conclusions

No degradation

had occurred in the organization or management of the

emergency

preparedness

program.

Emergency preparedness

appeared to be

receiving strong management

support at Harris.

Quality Assurance in EP Activities

10 CFR 50.54 t

Audit of Emer enc

Pre aredness

Pro

ram

Ins ection Sco

e

82701

The inspectors

reviewed this area to assess

the quality of the required

audit and to verif'y that the audit met the requirements of

10 CFR 50.54(t).

Observations

and Findin s

The inspectors

reviewed documentation

associated

with the

EP program

audits conducted in 1996 and 1997 by the licensee's

Nuclear

Assessment

Section

(NAS).

The 1996 audit, conducted

Harch 25-April 4 and

documented in NAS Report File No. H-EP-96-01, identified one strength,

three weaknesses,

three issues,

and five items f'r management

consideration.

The 1997 audit,

conducted

February 10-21 and documented

in NAS Report File No. H-EP-97-01, identified two strengths,

five

weaknesses,

two issues,

and eight items for management

consideration.

These audits were judged to be thorough

and independent,

and the nature

of the identified issues

indicated comprehensive

understanding of the

EP

area by the -auditors.

The audits provided evidence of the licensee's

ability to self-identify and correct emergency

preparedness

program

deficiencies.

Conclusions

The

NAS audits fully satiqfied the

10 CFR 50.54(t) requirement f'r'n

annual

independent

audit of the

EP program.

. 37

S1

Conduct of Security and Safeguards Activities

S1.1

General

Comments

71750

The inspector

observed security and safeguards

activities during the

conduct .of tours,

and observation of maintenance activities,

and found

them to be good.-

Compensatory

measures

were posted

when necessary

and

properly conducted.

Fl

Control of Fire Protection Activities

Fl. 1

General

Comments

71750

The inspector

observed fire protection equipment

and activities during

the conduct of tours

and observation of maintenance activities and found

them to be acceptable.

V. Mana ement Meetin s

X1

Exit Meeting Sumary

The inspectors

presented

the inspection results to members of licensee

management

at the conclusion of the'inspection

on June 25,

1997.

The

licensee

acknowledged the findings presented.

The inspectors

asked the licensee

whether any of the material

examined

during the inspection should be considered proprietary.

No proprietary

information was identified.

op

k.

Licensee

~ 38

PARTIAL LIST OF PERSONS

CONTACTED

D. Alexander, Supervisor,

Licensing and Regulatory Programs

D. Batton, Superintendent,

On-Line Scheduling

D. Braund, Superintendent,

Security

B. Clark, General

Hanager,

Harris Plant

A. Cockerill, Superintendent,

ISC Electrical

Sy'stems

J. Collins, Hanager,

Haintenance

J.

Dobbs,

Hanager,

Outage

and Scheduling

J.

Donahue,

Director Site Operations,

Harris Plant

R. Duncan,

Superintendent,

Hechanical

Systems

W. Gurganious,

Superintendent,

Environmental

and Chemistry

H. Hamby, Supervisor,

Regulatory Compliance

H. Keef, Hanager, Training

D. HcCarthy, Superintendent,

Outage

Hanagement

B. Heyer,

Hanager,

Operations

K. Neuschaefer,

Superintendent,

Radiation Protection

W. Peavyhouse,

Superintendent,

Design Control

W. Robinson,

Vice President,

Harris Plant

G. Rolfson,

Hanager,

Harris Engineering Support Services

D. Tibbitts, Hanager,

Nuclear Assessment

R.

Var ley, Supervisor,

Emergency Preparedness

Unit

NRC

V. Rooney, Harris Project Hanager,

NRR

H. Shymlock, Chief, Reactor Projects

Branch 4

IP 37551:

IP 40500'P

61726:

IP 62707:

IP 70313:

IP 71707:

IP 71711:

IP 71750'P

82701:

IP 90712:

IP 92700:

IP 92901:

IP 92902:

IP 92903:

IP 92904:

IP 93702:

. 39

INSPECTION PROCEDURES

USED

Onsite Engineering

Effectiveness of Licensee Controls in Identifying, Re'solving,

and

Preventing

Problems

Surveillance Observations

Haintenance

Observation

Containment Integrated

Leak Rate Test surveillance

Plant Operations

Plant Startup from Refueling

Plant Support Activities

Operational

Status of the Emergency Preparedness

Program

In-Office Review of Written Reports of Non Routine Events at Power

Reactor Facilities

Onsite Followup of Events

Followup

- Plant Operations

Followup - Haintenance

Followup

- Engineering

Followup - Plant Support

Onsite Response to Events

ITEHS OPENED,

CLOSED,

AND DISCUSSED

~0ened

50-400/97-06-01

VIO

Failure to restore

N41 to operable status

or bypasss

it'rior to continuing surveillance activities on a

. second

channel

(Section 01.2).

50-400/97-06-02

50-400/97-06-03

50-400/97-06-04

50-400/97-06-05

50-400/97-06-06

50-400/97-06-07

Failure to meet the 30-day notification requirement

under

10 CFR 50.74(a)

regarding

a Senior Reactor

Operator license

(Section 05.1).

I

Failure to isolate the respective

control

room

ventilation outside air intake within one hour after

the B-train radiation monitor actuation input signal

became inoperable

(Section 08.7).

Failure to declare the "A" accumulator

and

perform the required actions

(Section 08.8).

Failure to declare certain safety-related air handling

units inoperable during maintenance

(Section 08.10).

Failure to perform an adequate

technical evaluation

for procedure

HST-I0072, resulting in a safety-

injection (Section H2.2).

Inadequate

corrective actions to resolve binding

problems for the motor-driven auxiliary feedwater

pump

flow control valves (Section H2.3).

50-400/97-06-08

50-400/97-06-09

~ 40

NCV

Failure to test 17'nterposing

relays for the

auxiliary. control, panel

(Section H8.5).

EEI'ailure to conduct

a 10 CFR 50.59 safety 'review for

.emergency diesel

generator

protective circuitry

(Section E8.1) .

50-400/97-06-10

Closed

NCV

Failure to follow procedural

requirements

in. the

processing of Emergency Plan Revision 28 (Section

P3.1).

50-400/97-06-02

50-400/97-06-03

50-400/97-06-04

50-400/97-06-05

50-400/97-06-08

50-400/97-06-10

50-400/95-15-.01

50-400/95-15-02

50-400/95-17-01

50-400/95-17-02

50-400/96-02-02

50-400/96-06-01

Failure to meet the 30-day notification requirement

under

10 CFR 50.74(a)

regarding

a Senior Reactor

Operator license

(Section 05.1).

Failure to isolate the respective control

room

ventilation outside air intake within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months after the

B-train radiation monitor actuation input signal

became

(Section 08.7).

Failure to declare the "A" accumulator