ML17264A484

Replacement

Project (IP 50001)

3.1.1 Project Status

3. 1.2 Observations

3.2

Reactor Coolant System Average Coolant Temperature

Instrument Drift (IP 37551)

3.3

Instrument

Bus Inverter

A Failure (IP 37551)

PLANT SUPPORT

.

4. 1

Emergency

Preparedness

(IP 82701)

.

4. 1. 1 Conduct'of Emergency

Preparedness

(EP) Activities .

.

4. 1.2 Status of EP Facilities,

Equipment

and Resources

4. 1.3

EP Procedures

and Documentation

.

4.1.4 Staff Knowledge

and Performance

in

.

4. 1.5 Staff Training and gualification in

4. 1.6 Organization

and Administration

.

4. 1.7 guality Assurance

in

EP Activities

4. 1.8 Miscellaneous

EP Issues

.

4.2

Radioactive Liquid and Gaseous

Effluent Control

Programs

(IP 84750)

~

4.2.1

Management

Controls

.

4.2.2

Review of Off-Site Dose Calculation

Manual

(ODCH)

.

4.2.3 Radioactive Liquid And Gaseous

Effluent Control

Programs

..

12

13

14

15

17

18

19

20

21

24

25

4.3

4.2.4

Blowdown Tank and Spent

Fuel

Leakages

4.2.5

NRC Assessment

and Planned

Licensee Action

4.2.6 Calibration of Effluent/Process

RMS

.

4.2.7 Air-Cleaning Systems

Radioactive

Waste Storage,

Processing

Systems,

and

(IP 71750)

~

"Emergency Diesel Generator

(SG)

Replacement

Security

Program

4.4.1 Plant Modifi'cations

.

4.4.2 Procedures

4.4.3 Security Organization

.

Pool

~

Equi

~

pment

25

27

28

30

32

33

5.0

SAFETY ASSESSMENT/OUALITY VERIFICATION (IP 71707)

5.1

.Reactor

Fuel Receipt Inspection

.

5.2

Periodic Reports

.5.3

Licensee

Event Reports

6.0

ADMINISTRATIVE (IP 71707)

6.1

Senior

NRC Management Site Visits

6.2

Review of UFSAR Commitments

.

6.3

'Exit Meetings

.

ATTACHMENT 1

Attachment

1

Review of the

NERP and

EPIPs

33

34

35

DETAILS

1.0

OPERATIONS (Inspection

Procedure

(IP)

71707)'.1

Operations

Overview

At the begi'nning of the inspection period, the plant was operating at full

power (approximately

97 percent).

On March 7,

1996, the reactor

was manually

tripped from approximately

50 percent reactor

power due to a secondary plant

transient that was caused

by an automatic trip of a main circulating water

pump motor.

All engineered

safety features

equipment functioned

as required

and operators

promptly stabilized the plant in hot shutdown.

A plant startup

was performed

on March ll, 1996,

and the plant operated

at full power for the

remainder of the inspection period.

There were no other significant

operational

events or significant challenges

to plant equipment during the.

inspection period.

Overall, operator

performance

was very good during the

reporting period.

1.2

Implementation of Improved Technical Specifications

On February

24,

1996, the licensee

implemented

Amendment

61 to the operating

license for the

R.

E. Ginna Station.

The Amendment comprised

a complete

revision of Appendix A to the license which contained the Improved Technical

Specifications

(ITS) that were approved

by the

NRC on February

13,

1996.

The

ITS imposed .several

new program changes

on the licensee

(see

NRC Inspection

Report 50-244/95-21)

and required

a total of 1380 new and revised station

procedures

prior to implementation.

Prior to February

24, the inspector

verified that all necessary

new and revised procedures

were completed,

reviewed,

and approved.

On February

24, the inspector verified that all

materials

(procedures,

etc.) in the control

room pertaining to the old

technical specifications

were removed,

and that all materials pertaining to

the

ITS were in place available for use

by operating personnel.

1.3

Control of Operations

The inspectors

observed plant operation to verify that the facility was

operated

safely

and in accordance

with licensee

procedures

and regulatory

requirements.

This review included tours of the accessible

areas of the

facility, verification of engineered

safeguards

features

(ESF)

system

operability, verification of proper control

room and shift staffing,

verification that the plant was operated

in conformance with technical

specifications

and appropriate

action statements

for out-of-service

equipment

were implemented,

and verification that logs and records

were accurate

and

identified equipment status

or deficiencies.

One operational

inadequacy

occurred

when the on-shift operating

crew authorized

work that physically made

both pressurizer

power operated relief valves simultaneously

inoperable,

as

discussed

in section

1.5 of this report.

'he

NRC inspection

manual

procedure or temporary instruction that was

used

as inspection

guidance is listed for each applicable report section.

t

1.4

Manual Reactor Trip due to Loss of a Nain Circulating Water

Pump

The main circulating water system supplies cooling water to the main

condensers

to condense

exhaust

steam

from the'wo low pressure

turbines.

The

system consists of two headers,

each of which is supplied

by a circulating

water

(CW) pump.

Each header supplies

a main condenser.

The headers

are

cross-connected

upstream of the main condensers

to allow for reduced

power

operations with a single operating

CW pump.

After passing

through the main

condensers,

main circulating water is returned to the lake via a common

discharge

canal.

At 6:15 p.m.

on March 7,

1996, the

B-CW pump motor tripped.

Control

room

operators

were alerted to the problem by the associated

main control board

annunciator.

Turbine load was rapidly reduced to approximately

50 percent in

accordance

with abnormal

procedure

AP-CW.1, "Loss of a Circulating Water

Pump."

The reduction in heat

removal

from the B-main condenser

from reduced

circulating water flow caused

an increase

in the associated

turbine

backpressure.

The low pressure

turbines

are not designed to operate at the

high backpressure

conditions that existed following the

B-CW pump trip. A

vendor-recommended

limitation of five minutes of operation applies

under high

backpressure

conditions.

The rapid power reduction, caused

steam generator

(SG) water levels to decrease

(i.e., "shrink").

Although the actual

feedwater requirement

was reduced,

the

automatic

feedwater

control system overcompensated

for the shrink in an

attempt to restore

normal

SG water levels,

and the water levels in both

SGs

began to rise.

Due to the response

time of the automatic feedwater control

system relative to the rate of SG water level increase,

level continued to

rise to the engineered

safety features

(ESF) feedwater isolation setpoint of

67 percent.

After several

high level

ESF isolations

had occurred

on both SGs,

levels

began to stabilize.

Although backpressure

in the B-main condenser

was

also recovering, it did not occur quickly enough to avoid exceeding

the five

minute turbine operating restriction.

At 6:22 p.m., the shift supervisor

directed that the reactor

be manually tripped.

Plant response

to the trip was

normal.

All safety

systems

and equipment

responded

as required, with the

exception of one source

range nuclear instrument channel

(N-31), which failed

to indicate after it was energized.

Operators

promptly stabilized plant

conditions in hot shutdown.

Investigation revealed that the

B-CW pump breaker

had tripped due to actuation

of the power factor relay.

The relay trip setpoint

was checked

and found to

'e

correctly set.

Inspection

and testing of the breaker

and the

B-CW pump

motor revealed

no obvious problems.

from review of available data for the

B-CW pump, the licensee

determined that the motor power factor had

been

gradually decreasing

over

a period of months.

The licensee attributed this to

development of an oxide layer at the wiper contact. for the variable

transformer that supplies

the exciter field.

This resulted

in reduced

voltage,

and therefore

reduced current supplied to the exciter and

a lagging;

motor power factor.

The licensee

determined that the likely cause of the

power factor trip had

been the gradual

decrease

in the exciter current,

combined with normal variation in the

4KV supply bus voltage.

In this case,

a

voltage incr ease

also caused

the power factor to decrease.

As corrective

3

action, the exciter variable transformer

was cleaned.

Additionally,

operations

instituted

a requirement to record

B-CW pump power factor and

exciter field current whenever

4KV bus voltage changed

by 50 volts.

This was

intended to provide early indication of a downward trend in power factor and

allow for adjustment of the exciter field current before the power factor trip

set point was approached.,

The inspectors

noted that the secondary

plant transient during this event was

significantly, different from the loss of the

B-CW pump event that occurred in

August 1995.

In both cases,

increased

backpressure

in the B-main condenser

resulted in condensate

being transferred

from the B-hotwell to the A-hotwell

via the

common header that supplies the 'condensate

pumps.

On the earlier

occasion,

the hotwell level transient resulted in a loss of net positive

suction

head

(NPSH) to the condensate

and main feedwater

pumps,

and the plant

was manually tripped based

on concern that these

pumps could be damaged

by

cavitation.

On this occasion,

NPSH was adequate

throughout the transient.

The inspectors

considered that the most likely cause of the difference

was

that power had

been

reduced

more rapidly during the recent event than it had

during the August

1995 event.

As a result, the maximum backpressure

was lower

than in the August event

and

a water, seal

was maintained

between the condenser

and the condensate

pumps suction.

No pump cavitation

was evident during this

event.

Source

range nuclear instrument channel

N-31 was required to be operable prior

to conducting

a reactor startup.

Troubleshooting

indicated that the detector

had failed.

Also, the initial replacement

detector

was found to be defective

following replacement. 's

a result,

time was available to conduct several

other maintenance activities prior to startup.

Among these activities -were

adjustment of the pressurizer

power operated relief valve

(PORV) stroke times

(discussed

in section

1.5 of this report)

and replacement of valve internals

for the A-motor driven auxiliary feedwater

pump discharge

check valve,

CV-4009.

Following completion of planned maintenance

on the evening of

March 9,

1996, failure of the A-steam generator

atmospheric relief valve

further delayed startup; this item is discussed

in section

1.6 of this report.

Problems

encountered

with the control rod step counters during attempted

startup

(discussed

in section

2. 1. 1 of this report) delayed reactor startup

until the morning of March ll, 1996.

A reactor startup

was successfully

completed

on March 11,

1996, with

criticality being achieved at 3:54 a.m.

The main generator

was paralleled to.

the grid and power was escalated.

Full power was achieved at 9:22 a.m.

on

March 12,

1996.

The inspectors

considered that the operator's

response

to loss of the

B-CW

pump was very good.

Through discussions

with licensee

personnel

and review of

archived plant data,

the inspectors

concluded that the plant responded

normally to the reactor trip, with the exception of source

range nuclear

instrument

channel

N-31.

A four-hour non-emergency

report was

made to the

NRC

as required

by 10 CFR 50.72

and was subsequently

reported in LER 96-003

on

April 8,

1996.

Operator performance during the reactor startup

and power

escalation

was very good; communications, were precise

and actions

were

deliberate.

The inspectors

had

no additional

concerns

on this matter.

h

J

Jf

1

E"

4

1.5

Both Pressurizer

Power Operated Relief Valves

Made Inoperable During

Stroke Time Adjustments

During the March 7-10 forced outage,

the licensee

performed maintenance

on the

pressurizer

power operated relief valves

(PORVs).

As discussed

in inspection

report 50-244/95-17,

the

PORV block valves

have

been closed for most of the

operating

cycle to control minor

PORV seat

leakage.

Earlier attempts to stop

this leakage

had involved mechanical

("benchset")

adjustment of the

PORVs, .

which, in turn,

had affected their stroke times.

The

PORVs also serve

as

relief valves for the low temperature

overpressure

protection

(LTOP) system

(only used while the reactor is shut

down and cooled down),

a function in

which stroke time is a critical parameter.

The purpose of the

PORV

maintenance

conducted

on March 8,

1996,

was to make adjustments

to the valves

and verify their stroke times, in preparation for placing the

LTOP system in

service during the upcoming refueling outage.

The work was to be conducted

in accordance

with maintenance

procedure

M-37.150,

"Copes-Vulcan/Blaw-Knox Air Operated

Control Valves Inspection

and

Refurbishment."

A work package

(WO 19503588)

had already

been prepared to

accomplish this work during the upcoming outage.

Conducting this maintenance

with the plant at normal operating temperature

(rather than during plant

cooldown) required work in a higher temperature

environment than would

normally be the case.

To minimize the amount of time that the worker s would

have to spend in this adverse

environment,

M-37. 150 was modified to allow work

on both

PORVs simultaneously.

The procedure

involved disconnecting

the

normal'ir/nitrogen

supply from the

PORV actuator.

While the normal air/nitrogen

supply was disconnected,

operation of the

PORV from the main control board

would not possible.

Therefore,

an inadvertent result of the procedure

change

was that both

PORVs would simultaneously

be made inoperable.

Based

upon subsequent

discussions

with the licensee,

the inspectors

noted the

on-shift operations

personnel

reviewed the

PORV maintenance

package prior to

authorizing work to begin.

Operators

apparently believed,

in error, that the

maintenance

would only affect the ability to operate

the

PORVs with air,

and

that they would still be able to operate

the valves using nitrogen.

They

concluded that

PORV operability would not be affected

and authorized the work

to begin.

At approximately 2:55 p.m.

on March 8,

1996,

both

PORVs were made inoperable

when the air/nitrogen supply lines were disconnected

from the valve actuators.

The maintenance

was completed

and the air/nitrogen supply lines were

reconnected

by approximately 4:32 p.m. causing

both

PORVs to be physically

.

inoperable for a total of

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and 37 minutes.

Technical Specification

LCO 3.4.11 requires that both

PORVs

be operable

in Modes 1, 2,

and 3;

and actions

required if both

PORVs are inoperable

are

1) immediately initiate action to

restore

one

PORV to operable status,

2) within one hour, close

and remove

power from the associated

block valves,

and 3) within eight hours,

be in Mode

3 with Tavg less than

5004F.

The unavailability of both

PORVs above

500

F

represents

the loss of the available vent path safety function and invalidates

other assumptions

in the accident analysis for a steam generator

tube rupture.

e

The change to procedure

M-37.150 that allowed-work to be done

on both

PORVs at

the

same time was accomplished

by adding

a note to an existing temporary

procedure

change

(PCN 96-T-0055) that had

been developed

as part of the

original work package.

However, the

10 CFR 50.59 applicability review was not

reperformed.

The entire change

received

a subsequent

independent

review as

required

by A-601.3, "Procedure

Control

Temporary Changes."

According to

this procedure,

the independent

reviewer is responsible for reviewing the

10 CFR 50.59 Safety Review Form for adequacy

and completeness.

The shift

supervisor also reviewed

and approved the change;

according to A-601.3, review

responsibilities

included

a review of the temporary

change for impact on plant

operations.

However, in this case neither the independent

reviewer nor the

shift supervisor

adequately

accomplished

the review.

Technical Specification Section 5.4. 1 requires that written procedures

be established,

implemented

and

maintained covering the applicable

procedures

recommended

in Regulatory

Guide

1.33, Revision 2, Appendix A, February

1978.

Regulatory

Guide 1.33

recommends

a written administrative

procedure

covering procedure

adherence

and temporary

procedure

changes.

Administrative procedure A-601.3, "Procedure Control

Temporary Changes,"

was established

to meet this recommendation.

The failure

to properly implement procedure

A-601.3 for the temporary procedure

change for

the

PORV maintenance

is

a violation of TS Section 5.4.1

(VIO 50-244/96-01-01).

Stroke time testing

on the

PORVs was completed at approximately 5:59 p.m.

and

was immediately followed by seat

leakage testing.

The first PORV tested,

PCV-430, exhibited significant leakage

(on the order of 20 gallons per

minute).

Since the benchset

on the other

PORV (PCV-431C)

had

been similarly

adjusted,

operators

concluded that it would also

have excessive

seat

leakage;

therefore,

a seat

leakage test

was not performed

on PCV-431C.

Technical specification (TS) 3.4. 13 states

that identified leakage

from the reactor

coolant system shall

be limited to 10 gallons per minute.

Based

on this

requirement,

operators

declared

both

PORVs inoperable at 7:40 p.m.

Accordingly, power was removed from the block valves (to meet

TS 3.4. 11)

and

work was initiated to readjust

the

PORV benchsets

to their original values.

Acceptance testing

was completed

and the

PORVs were declared

operable at 1:23

a.m.,

March 9,

1996.

Both instances

of PORV inoperability were reported to

the

NRC in LER 96-003

on April 8,

1996.

The inspectors

concluded that the licensee's

preparations

for maintenance

on

the

PORVs

on March 8,

1996 were not thorough.

The procedure

change that

authorized

simultaneous

maintenance

on the

PORVs did not account for the

TS

operability requirements,

and this was not identified during preparation,

approval,

or implementation of the change.

The

PORV operability problem was

recognized after the

PORVs were leak tested,

and the licensee

then took prompt

action to comply with TS

LCO 3.4. 11.

The licensee is performing

a human performance

review of this event.

However,

the inspectors

considered that

an apparent

lack of communication

and

coordination

between

the maintenance

and operations

organizations

also

contributed significantly to this event.

1.6

Failure of the A-Steam Generator

Atmospheric Relief Valve While Shutdown

During the March 7-10 forced outage,

maintenance

was performed

on the A-motor

driven auxiliary feedwater

(MDAFW) pump discharge

check valve (discussed

in

section 2.1. 1 of this report).

During the outage,

reactor

coolant system

(RCS) temperature

was being controlled by steam release

through the steam

generator

atmospheric relief valves

(ARVs).

Operators

had closed the A-main

steam isolation valve

(MSIV) and were controlling

RCS temperature

using only

the

B-SG and

B-MDAFW pump, since the work isolation for the check valve

maintenance

made adding feedwater .to the A-SG difficult.

At 9:20 p.m.

on March 9,

1996,

when resto} ing from the

A-MDAFW pump

maintenance,

operators

attempted to establish

steam flow in the header

and

slightly opened the A-SG ARV to assist

in opening the A-MSIV.

However, rather

than opening slightly, the

ARV failed open to. approximately

60 percent.

After

the valve opened,

controls

on the main control 'board

had

no further affect on

valve position.

RCS temperature

and pressure,

and

SG water levels, all began

to lower.

Level in the A-SG was initially low (22 percent)

due to no

feedwater addition during the

AFW pump maintenance,

and reached

the

17 percent

low level

ESF setpoint approximately three minutes into the event.

This

generated

a reactor trip signal (all rods were already fully inserted)

and

caused

an automatic start of the non-operating

B-MDAFW pump.

Operators

responded

to the event

by shutting the A-MSIV and dispatching

an

auxiliary operator

(AO) to manually isolate the A-ARV.

Two AOs responded;

one

begari to shut the manual isolation valve while the other attempted to close

the

ARV using its manual

operator.

The isolation valve was fully closed in

approximately

3$ minutes

and stopped

the steam release.

As a result of this transient,

RCS temperature

dropped

approximately

15 degrees

Fahrenheit ('F),

RCS pressure

dropped

approximately

120 psi,

and

water level in the A-SG reached

approximately six percent.

The low level in

the A-SG made the A-RCS loop inoperable for heat removal.

Technical

Specification

LCO 3.4.5 allows 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to restore operability,

and the

A-RCS

loop was restored to operability at 9:40 p.m.

when

SG water level

was returned

to zl6 percent.

The cause of the A-SG ARV failure was determined to be

a failed air system

volume booster relay that translates

the control air signal into operating air

for the valve.

The relay was replaced,

and the

ARV was returned to service

on

March 10,

1996.

The inspector

was in the control

room throughout this event

and assessed

that

operator

response

was excellent.

Control

room operators rapidly determined

the cause of the transient

and took action to isolated the fault by shutting

the A-MSIV and dispatching operators.

The AOs responded

quickly into an

extremely harsh

noise environment

and rapidly isolated the failed ARV.

A

four-hour non-emergency

report was

made to the

NRC as required

by 10 CFR 50.72

and was subsequently

reported in LER 96-004

on April 8,

1996.

The inspectors

had

no additional

concerns

on this matter.

2.0

NAINTENANCE

2.1

Naintenance Activities (IP 62703)

, 2.1.1 Routine Observations

The inspectors

observed

portions of plant maintenance activities to verify

that the correct parts

and tools were utilized, the applicable industry code

and technical specification requirements

were satisfied,

adequate

measures

,were in place to ensure

personnel

safety

and prevent

damage to plant

structures,

systems,

and components,

and to ensure that equipment operability

was verified upon completion-of post maintenance

testing.

The following

maintenance activities were observed:

~

Hydrogen recombiner

corrective maintenance

Prior to implementing

Improved Technical Specifications

(ITS) at the

Ginna Station

on February

24,

1996, the licensee

required that all

surveillance tests

included in the

ITS be current.

Since the

containment

hydrogen recombiners

did not have

a surveillance test

requirement

under the old technical specifications,

these

systems

needed

a 24 month functional test to meet surveillance

requirements

SR 3.6.7. 1

and

SR 3.6.7.2 of the ITS.

Several

functional tests

were performed

on the A- 5 B-recombiner

system

trains before February 24,

1996.

One test revealed

a significant flow

blockage in the A-train that caused

flow to be less than the system's

minimum requirements.

The inspectors

observed

the troubleshooting

and

disassembly of portions of the A-train components.

After identifying

the blocked region

as

an orifice near pressure

regulating valve V-10200,

approximately one-half cup of iron oxide particles

was removed

when the

valve was disassembled.

After the system

was restored,

the A train was

successfully flow tested.

All maintenance

and testing

on the

recombiners

was well controlled

and the procedures

used for these

activities were available

and followed.

Operations

personnel

made the

necessary

systems

isolations

and tagouts with independent verifications

for=-the maintenance

and test work.

'

C-standby auxiliary feedwater

(SAFW) pump service water check valve

CV-9627A inspection for missed

IST observed

on February

23,

1996

On February

15,

1996, the licensee

determined that

an inservice test for

. check valve 9627A was not performed in the time frame identified in a

relief request

(VR-5) for ASME Code,

Section

IX test requirements

(See

section

5.3 of this report).

The valve is in the service water suction

line to the

C-SAFW pump,

and the required inspection involves

disassembly

and full stroke exercising the valve every other refueling

outage.

The inspectors

witnessed

the valve disassembly

and testing

activity on February

22,

1996.

A small

amount of silt was noted

around

the ledge of the valve seat

and at the bottom of the valve body.

However, it did not appear

that the amount of material

present

would

have prevented full valve closure.

The licensee

exercised

the valve

disk and observed

freedom of motion through its complete range.

The

valve disk was then blue checked

and full seat contact

was confirmed.

The valve was reassembled

and properly torqued in accordance

with

procedure

requirements.

All portions of this work were performed in the

presence

of a

gC inspector

and all inspection verifications were

properly made.

The valve was subsequently

restored to operability.

The

inspectors

concluded that this work was timely and well controlled in

accordance

with procedure

requirements.

~

Auxiliary feedwater

pump discharge

check valve CV-4009 final bonnet

torquing,

observed

on March 9,

1996

AFW system operation during the March 7-10 forced outage revealed that

the

A-HDAFW pump discharge

check valve,

CV-4009,

had excessive

seat

leakage.

The valve seat

and disc were replaced

and the valve was tested

satisfactorily

on March 9,

1996;

however,

on March 20,

1996, during

routine surveillance testing,

the valve again demonstrated

excessive

seat

leakage.

During rework, the licensee

determined that the cause

was

that

an earlier modification to the valve body in the area that accepts

the seat ring had not been

accounted for during the March 9 maintenance,

and the seat ring in the replacement

valve internals

was not modified.

This resulted

in an improper reassembly that caused

the test failure on

March 20.

The licensee is performing

a root cause

analysis

(AR 96-0172)

of the CV-4009 maintenance

problems.

(IFI 50-244/96-01-02).

~

Control rod step counter troubleshooting,

observed

on March 10,

1996

During an attempted reactor startup,

operators

observed that the step

counter for control

bank

C group

1 did'ot operate.

Replacement of the

counter module failed to correct the problem.

Subsequent

troubleshooting

involved several

iterations of single

and multiple

circuit card replacements

in the rod control cabinet.

The problem was

ultimately traced to a circuit card malfunction;

however,

troubleshooting

had

been complicated

by a second malfunction that was

introduced

by the replacement

step counter module.

Correction of this

problem delayed the reactor startup

by approximately

one day.

The

technicians

demonstrated

a high level of technical

competence;

however .

their initial troubleshooting efforts lacked

a systematic

approach to a

resolution of the root cause

and resulted, in a time delay (approximately

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ) in restarting the reactor plant.

System engineering

and

maintenance

management

eventually

became

involved in the troubleshooting

efforts and

a prompt resolution

was achieved.

The inspectors

considered

that earlier involvement by system engineering

and maintenance

management

may have provided better overall direction,

a more systematic

approach to the troubleshooting,

and

a more prompt resolution.

2.2

Surveillance

and Testing Activities

2.2.1 Routine Observations

(IP 61726)

Inspectors

observed

portions of surveillances

to verify proper calibration of

test instrumentation,

use of approved

procedures,

performance of work by

qualified personnel,

conformance to limiting conditions for operation

(LCOs),

I'

,4

0

9

and correct post-test

system restoration.

The following surveillances

were

observed:

~

M-72. 1. 1, "Reactor Coolant

Loop

RTD [Resistance

Temperature

Detector]

Integrity Check," observed

February 7,

1996

Testing of loop A average

temperature

(Tavg) hot leg (Th)

RTD, TE-401A,

performed

because

the associated

instrument

was indicating lower than

the three other channels.

This item is discussed

further in section 3.2

of this report.

~

Performance

Test (PT)-12.2,

B," observed

February

15,

1996

~

Instrument Calibration Procedure

(CPI)-SPAN-5.10, "Calibration Alignment of

Delta T Dana Amplifier at

70X Power or Greater,

Channel

1,

Loop A,"

observed

February

15,

1996

Performed to compensate

for drift in Tavg/hT

RTD element

TE-401A,

as

discussed

in section 3.2 of this report

~

PT-32A, "Reactor Trip Breaker Testing

"A" Train," observed

March 1,

1996

Included troubleshooting for R-29 (containment

high range radiation

monitor) spiking, noted during previous reactor'trip breaker testing;

troubleshooting

is on-going

~

PT-169-B, "Auxiliary Feedwater

Pump

B quarterly," observed

March 9,

1996

Partial, retest for the CV-4009 repairs

~

PT-6.2,

"N.I.S.

[Nuclear Instrumentation

System]

Intermediate

Range

Channels

N-35 and N-36," observed

March 9,

1996

N-35 calibration check

The inspectors

determined

through observing the above surveillance tests that

operations

and test personnel

adhered to procedures,

that test results

and

equipment operating

parameters

met applicable

acceptance

criteria,

and that

redundant

equipment

was available during testing for emergency operation.

2.2.2 A-Emergency Diesel Generator

Fuel Oil Transfer

Pump Failed Surveillance

On February

1,

1996, during quarterly in-service

(ASME Section XI) performance

testing

(PT-12.6,

"Diesel Generator

Fuel Oil Transfer

Pump Tests"

of the

A-Emergency Diesel

Generator

(EDG) fuel oil transfer

system,

the fuel oil

transfer

pump failed to achieve the required discharge

pressure

and flow (16

psig

and 23.27

gpm achieved;

vs. 17.7-20.9 psig and 25.8-29.9

gpm acceptable).

As a result, the

A-EDG was declared

inoperable,

placing the plant in a seven

day Limiting Condition for Operation

(LCO).

Subsequent

troubleshooting

by

operations

and maintenance

personnel

concluded that the apparent

cause of the,

pump's low discharge

pressure

was failure of the

pump recirculation valve

10

SOV-5907A to tightly close, resulting in pressure

and flow losses

during

filling of the day tank.

Since the failed valve was original plant equipment

and

a replacement

was not

readily available,

operations

and engineering

evaluated

the impact on plant

safety

and

A-EDG reliability.

As a precautionary

measure,

the fuel oil

transfer

system

was temporarily modified by securing

SOV-5907A in the open

position.

In this configuration, flow to both the day tank and fuel storage

tank (recirculation flow) will result when filling the day tank.

This

condition is acceptable

since the positive displacement, transfer

pump can

still deliver the minimum required flow to the day tank (>2.62 gallons per

.

minute,

as stated in the Updated Final Safety Analysis Report,

section 9.5.4).

'o

confirm adequate

flow, PT-12.6

was performed following deenergizing

the

valve;

a discharge

pressure

of 15 psig and

a flow of 20'.23

gpm were obtained.

Accordingly, the

A-EDG was'eturned

to service

on February 3,

1996.

Prior to performing this reconfiguration,

the proposed

Temporary Modification

Permit (96-007)

and supporting Safety Evaluation

(SEV 1059) were reviewed

and

approved

by system engineering,

operations,

and the Plant Operations

Review

Committee

(PORC).

Reconfiguring

was considered

precautionary

since it was

postulated that the degraded

valve could cause

an electrical failure that

could fail the control fuses

and disable the entire 'A-EDG fuel oil transfer

system.

The temporary modification disconnected

the power leads for

SOV-5907A, isolated the valve from the control circuit, and eliminated the

possibility of fuse failure due to coil degradation.

To reestablish

A-EDG

operability, the licensee

used guidance contained in Generic Letter 91-13,

Technical

Guidance

9900 "Operability."'here the

ASME Section

XI acceptance

criteria is more conservative

than the regulatory limit, this guidance states

that the corrective action

may be

an analysis to demonstrate

that the specific

degradation

does not impair system operability and the component will still

fulfillits function.

The licensee

purchased

a commercial

grade replacement

valve since

an identical

valve was

no longer manufactured.

Therefore,

the dedication

process

was

used

to qualify the replacement

valve and the solenoid operator.

Procurement

engineering

completed

a comparative analysis,

establish

valve performance

requirements,

and identified the critical attributes that the quality

assurance

department

would verify prior to accepting

the replacement

valve for

installation.

Receipt inspection of the part number, voltage,

power. rating,

dimensions,

and coil resistance

was to provide assurance

that the item ordered

was the item received.-

On February

13,

1996, the failed valve

(ASCO model

8210A35)

was replaced with

an

ASCO model

HC8210C35.

The inspector

observed

the installation of the

replacement

valve and post-installation testing of the fuel oil transfer

system.

Relevant documentation

reviewed included the work package,

commercial

grade dedication technical evaluation for the replacement

valve

(TE 96-505),

temporary modification permit, tagging order (to remove the system from

service),

ACTION report,

and

UFSAR section 9.5.4.

Mechanical

maintenance

personnel

installed the valve in a professional

manner,

using foreign material

exclusion controls

on open piping, complying with

11

procedural

requirements for bolt tightening, flange fit-up and closely

coordinating procedural

hold point verifications with the quality control

inspector.

I&C technicians

reterminated

solenoid wiring with the control

circuit using skill-of-the-craft techniques.

Following installation,

Results

and Test

(R&T) technicians

had operations

personnel

realign the system. for

testing.

Testing

was conducted

in conformance with the test procedure

and

system performance

parameters

met acceptance criteria.

Although the performance criteria of PT-12.6 were met during post-installation

testing, during system recirculation,

high pump discharge

pressure

(44 psig)

caused

the system relief valve

(RV-5959) to lift. This condition did not

compromise

system operability; however, it indicated that SOV-5907A had

been

in a degraded

condition (that is, not fully closing) prior to the IST baseline

parameters

for the

FO transfer

pump being established

in 1992.

An ACTION

report (96-0088)

was generated

to document

and resolve this condition.

Subsequent

to returning the fuel oil transfer

system to service,

the inspector

interviewed the procurement

engineer regarding the commercial

grade dedication

of the replacement

valve.

Through this discussion,

the inspector determined

that

a prompt and thorough evaluation

was completed for suitable

replacement

components.

The engineer

adhered to the relevant engineering

and

administrative

procedures

in establishing critical valve performance

attributes

and by identifying quality control receipt inspection criteria.

Additionally, the inspector interviewed the cognizant

system engineer

regarding installation of the temporary modification following the initial

valve failure.

Through this discussion

and review of the supporting

documentation,

the inspector concluded that the fuel oil transfer

system

was

capable of performing its intended safety function following deenergizing

SOV-5907A.

Upon identifying that

SOV-5907A had failed, prompt and extensive

actions

were initiated by the operations,

maintenance,

and engineering

departments,

to evaluate

the condition from a safety

and regulatory

perspective,

to restore the A-EDG to service

by installing a temporary

modification, to qualify a suitable

replacement for the failed valve,

and to

expeditiously install/test the replacement.

These activities were effectively

coordinated with appropriate

management

and

gA oversight.

2.2.3 Notor Driven Auxiliary Feedwater

Pump Anomalous Discharge

Flow

On February

12,

1996, the licensee

performed monthly surveillance testing

on

the

B-MDAFW pump.

Approximately one-half hour after the

pump was secured,

a

control

room operator

noted that the two main control board instruments for

B-MDAFW pump discharge

flow were showing erratic indication.

The operator

documented

the condition in a work request/trouble

report

(WR/TR 013045).

The following day, the inspector noted the

WR/TR concerning the

8-MDAFW flow

indication.

The inspector

reviewed archived data from the plant computer

and

noted that,

although erratic,

both flow instruments

showed the

same pattern at

the

same time.

About one-half hour after the

pump was stopped,

flow went from

zero to about

25 gallons per minute for about

20 minutes,

and then returned to

zero.

The inspector considered

that this indicated that flow had actually

occurred,

as

opposed to the condition being the result of coincident

12

~

~instrument failures.

The inspector discussed

this situation with the

licensee,

and the licensee initiated an ACTION report (96-0086) to investigate

the problem.

Further

review of archived data

by the licensee

revealed that the

same

indications that were observed

on February

12,

1996,

had been occurring for at

least several

months with both

MDAFW pumps.

The licensee

assessed

this

condition as not affecting

MDAFW pump operability.

At the close of the

inspection period, the licensee

planned further investigation of this

condition, to be performed during normally scheduled

surveillance testing.

The inspectors

considered that the licensee did not initially respond

aggressively to the

B-MDAFW pump anomalous

flow indication, in that

a

condition that potentially affected the operability of a safety system

was not

promptly entered into the corrective action system.

Subsequent

licensee

actions

appeared

to be appropriate,

and the licensee's

corrective action

process'ill track the condition through appropriate resolution.

3.0

ENGINEERING

3.1

(Update)

Replacement

Project (IP 50001)

3.1.1 Project Status

RGKE's project to replace

both steam generators

(SGs) during the next

refueling outage (April 1996) is currently on schedule

and onsite preparation

activities are ongoing.

Overall, the project continues to be well managed

and

coordinated

between

RGKE and Bechtel.

3.1.2 Observations

The inspectors

reviewed documentation

and observed

various phases of the

preparation for the replacement of the steam generators,

including

reinstallation of liner on the training mockup, training of welders

on the

automatic welding machine, qualification of the "cadweld" rebar splicing

process

and crews, splice installation,

and receipt inspection of both new

steam generators

at the site.

The inspectors

observed

the following activities:

~

The welding of the liner reinstallation in the "mockup" had not been

completed;

however, welding of two sides

had been finished.

The two

radiographs

on the completed

weldments disclosed

some rejectable defects

(lack of fusion) in the root, although the fit-up appeared

satisfactory.

The licensee

was in the process of evaluating

and resolving the discrepancy

and developing

a fix to eliminate

such defects

from the liner welding

process.

~

The inspectors

observed

the training of welders

on automatic welding

machines.

There were six machines onsite.

Five out of the six were being

used for training and one was kept as

a backup.

Ten crews of three persons

each

were being trained

on the machine in two shifts.

13

~

Eight cadweld splicers

had

been qualified.

Each splicer had made two

splices in horizontal,

and two splices in vertical/slope position.

The

qualification splices

had been visually examined

by Bechtel quality control

(gC)

and the vendors representative/trainer,

and were found acceptable.

The inspectors

observed

the tensile testing of the splices

in the onsite

universal testing machine.

All the tested splices

met or exceeded

the

acceptance

criterion of the splices.

~

Both new steam generators

were delivered to the site

on January

7 and 17,

1996.

A temporary work facility was erected

near the station warehouse to

house the generators

during preparation for installation.

The steam

generators

were receipt inspected,

and installation of the upper support

ring a'nd the preparation of pipe nozzles for welding is in progress.

~

The Lampson Transilift crane

assembly

was completed

and

a load test

was

performed

on March 21-22,

1996.

The test load was 440 tons,

and the load

was raised

and lowered through the full range of the main

boom and over the

path that will occur

when the steam generators

are lifted.

The inspectors

observed

the operation of the crane during the load test,

and the survey of

the crawlers

and main

boom while under load.

The test

was satisfactory

and

no deficiencies related,to

the crane

assembly

were noted.

The inspectors

concluded that. the licensee's

planning, preparation,

and

related activities in the area of engineering

and construction well support

the steam generator

replacement

in the coming refueling outage starting

April 1,

1996.

Overall,

RG&E's management of the steam generator

replacement

has

been excellent.

Although some welder qualifications

have

been

behind

schedule,

overall coordination

and preparation for the project has

been very

'ood

and

on time.

3.2

Reactor Coolant System Average Coolant Temperature

Instrument Drift

(IP 37551)

Over

a period of several

months,

operators

noted that one channel of reactor

coolant system

(RCS)

average

coolant temperature

(Tavg)

and differential

temperature

(dT) was indicating slightly lower than the other three.

This was

a potential operational

concern

because

Tavg is used

as

an input to the

automatic rod control system,

and potentially affected the reactor protection

system

(RPS)

as well.

Tavg and

hT are inputs for determining the

overtemperature

and overpressure

differential temperature

(OThT and

OPhT)

reactor trip

setpoints.'nstrument

and Control

(I&C) personnel

investigated

the condition and noted

that the

RCS loop A hot leg temperature

detector

(TE-401A) for the affected

Tavg/hT channel

(RPS channel

1) had

shown

some minor inconsistency

during the

Although the detector

had

been within

allowable tolerance,

they had initiated action to replace

TE-401A during the

next refueling outage.

To assess

the detector's

current condition,

I&C

technicians

performed precision

measurements

of the

RCS loop A Tavg

RTDs per

M-72.1.1,

"Reactor

Coolant

Loop

RTD Integrity Check."

This test

showed that

TE-401A was indicating about 7.0oF lower than the other loop A Tavg hot leg,

RTD (TE-405A).

Testing at the beginning of the operating cycle showed that

P

14

TE-401A indicated

about 4.54F lower than TE-405A; therefore, it was concluded

that TE-401A had drifted about 2.5'F lower since the beginning of the

operating cycle.

Nuclear Engineering Services

performed

an operability a'ssessment

of the

RPS

channel

1 temperatures.

The assessment

determined that the effect of the

TE-401A drift on the

OThT and

OPhT setpoints

was in the non-conservative

direction, but that the resultant

values

were still within the

UFSAR limits.

The assessment

concluded that channel

1 OThT and

OPhT were still operable

and

that

an existing

MCB alarm (annunciator

F-24),

"RCS Delta T Deviation 3'F,"

should

be used to indicate that the limiting acceptable

value of drift had

been reached.

The assessment

further recommended that

a delta

T span

adjustment

be performed for RPS channel

1.

This would not affect the

temperature

indication provided by TE-401A, but would reduce the

non-conservative drift effect from the calculated

values of OThT and

OPhT.

The calibration

was satisfactorily performed

on February

15,

1996.

The inspectors

reviewed the licensee's

assessment

of the

RPS channel

1

temperatures

and evaluation of OThT and

OPhT setpoint margin,

and noted

no

discrepancies.

To further assess

the licensee's

evaluation of instrument

drift, the inspector

reviewed design analysis

DA-EE-95-0109, "Evaluation of 24

Month Instrument Surveillance Intervals."

The licensee

performed this design

analysis to provide justification for extending surveillance intervals in

support of an

18 month operating cycle.

The design analysis

was performed

pursuant to the guidance of Generic Letter 91-04,

"Changes

in Technical

Specification Surveillance Intervals to Accommodate

a 24-Month Fuel Cycle."

The inspector

noted that the licensee's

method for projecting instrument drift

was different than the methods

contained

in Instrument Society of Americ'a

(ISA) Standard

S67.04,

"Setpoints for Nuclear Safety-Related

Instrumentation."

Conformance to this standard is not

a requirement;

however,

in most cases that

the inspector reviewed,

the licensee's

method

was adequately

conservative for

assessing

instrument drift.

The inspector

concluded that nuclear engineering

services

provided timely,

conservative

support in resolving the TE-401A drift problem.

TE-401A will be

replaced during the

1996 refueling outage.

The inspectors

had

no additional

concerns

on this matter.

3.3

Instrument

Bus Inverter

A Failure (IP 37551)

At 2:23 p.m.

on March 12,

1996,

a failure of instrument

bus inverter

A

occurred.

Operators

were alerted to the condition by MCB annunciator

E-3,

"Inverter Trouble."

As designed,

power transferred

automatically through the

automatic static transfer switch to the associated

constant voltage

transformer,

so power to instrument

bus

A was not lost.

Failure of the A

inverter placed the licensee

in a 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months shutdown action statement

per TS 3.8.7.

Investigation revealed that the inverter output fuses

had blown and that there

were

numerou's failed solid state electrical

components

in the inverter,

including diodes

and silicon controlled rectifiers

(SCRs).

The damaged

components

were replaced

and the inverter operated satisfactorily;

however,

15

after about

45 minutes,

the output fuses

blew again.

During subsequent

troubleshooting,

a vendor representative

noted that the inverter output

voltage

was slightly high.

This was due to a group of capacitors

whose

capacitance

had decreased

with age,

together with other capacitors that were

replaced during the

1995 refueling outage.

By the vendor,'s direction, the

total capacitance

was reduced to reduce the output voltage.

This appeared

to

correct. the problem,

and the inverter was declared

operable at 10:29 p.m.

on

March 14,

1996.

However, at 10:48 a.m the following day, the inverter failed

.

again.

The licensee

reentered

TS action statement

3.8.7 with 15 hours1.736111e-4 days 0.00417 hours 2.480159e-5 weeks 5.7075e-6 months

and

54 minutes of the original

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months remaining.

Through the use of sophisticated

monitoring equipment during subsequent

troubleshooting,

ILC technicians

were able to capture

and record

an event in

which inverter output frequency went from 60 Hz to 120

Hz and inverter current

doubled.

The cause of this event

was traced to a defective integrated circuit

(IC) chip on an oscillator board.

The oscillator board

was replaced

and the

inverter operated satisfactorily.

Inverter

A was declared

operable at 2:11

a.m.

on March 16,

1996, with 31 minutes remaining in the action statement.

'he

problem with inverter A was determined to be the defective

IC chip that

was randomly initiating the inverter startup

sequence.

The inverter

initially'tarts

up with a 120

Hz output

(60 Hz during normal operation)

and does

so by

doubling the normal

SCR firing rate.

The resultant

high current

when this

occurred during normal operation

caused

the inverter output fuses to blow.

Shop testing later demonstrated

that the problem was temperature

induced.

This complicated troubleshooting,

which was performed with the cabinet

open

and therefore at relatively cool temperatures.

An earlier attempt to use

infrared thermography for troubleshooting

had

shown the chip to have

a "hot

spot," but it was not recognized

as the source of the problem, partly because

there

was

no baseline

information to compare it to.

The inspectors

considered that the licensee's

response

to the inverter A

failure was e'xcellent with very good management

direction and involvement.

The vendor was promptly consulted

and appropriately utilized during the

extensive troubleshooting effort.

The use of sophisticated

monitoring

equipmeht

made it possible for 18C technicians to record

a short duration

event that led to identification of the problem.

The inspector

had

no

additional

concerns

on this matter.

4.0

PLANT SUPPORT

4.1

Emergency

Preparedness

(IP 82701)

4.1.1 Conduct of Emergency

Preparedness

(EP) Activities

The inspectors

reviewed the, effectiveness

of various licensee controls to

maintain

and manage

the

EP program.

The inspectors

conducted

interviews,

reviewed documentation,

and investigated specific activities to assess

this

aspect of the licensee's

performance.

The inspectors

reviewed the licensee's

efforts associated

with the

EP support

to the steam generator

replacement

project

(SGRP).

Prior to this inspection,

16

the inspectors

reviewed

an inter-office memo from the Onsite

Emergency

Planner

(OEP) to the Corporate Nuclear

Emergency

Planner

(CNEP),

Manager

Nuclear

Assessment

(MNA), and the Radiation Safety Communications

Coordinator that

discussed

several

contingencies

which were planned for EP's

involvement in the

SGRP.

The contingencies

addressed

scenarios

including a fire,

a radioactive

release,

mass casualty,

steam generator

drop,

a'dverse

weather,

isolating

containment penetrations,

and loss of electrical

power.

The licensee's

planning for these contingencies

included procedures,

equipment

and

facilities, personnel,

and offsite support.

The inspectors

concluded that the

licensee

was proactive in this effort and

had properly considered

and

satisfactorily planned'to

support the

SGRP effort.

The inspectors

reviewed the licensee's

1996 business

plan (dated

March 1,

1996)

and identified several

EP projects that were included.

The plan

includes

such items

as developing joint EP capabilities with other utilities,

benchmarking

the Nuclear

Emergency

Response

Plan

(NERP) public information

program, utilizing an auto-dial

system for off-hour call-outs,

supporting the

SGRP,

implementing

a severe

accident

management

program,

conducting "train the

trainer" sessions

for Nuclear

Emergency

Response

Plan

(NERP) instructors,

and

improving the process for tracking

NERP responder qualifications.

Based

upon

the review of the business

plan, the inspectors

concluded that licensee

management

has

addressed

EP functions

and needs

in its plan.

The inspectors

reviewed the Commitment

and Action Tracking System

(CATS) and

the

EP items currently in the system.

There were

15 open items (nine were

from the December

1995 exercise)

and none were overdue.

All items were

assigned

to the low priority status,

except for

an item- about the Reactor

Vessel

Level Indicating System.

The inspectors

agreed with the assigned

priorities and

had

no concerns

or questions

regarding the use of CATS for EP

items.

The inspectors

reviewed the licensee's

activities regarding

a licensee-

identified problem pertaining to its call-out drills.

The call-out drills

implement three

Emergency

Plan Implementing Procedures

(EPIPs)

(1-5,

Notifications (Onsite); 3-6, Corporate Notifications;

and 4-5, Public Affairs

Notifications) to notify responders

via a telephone tree.

During the last

NRC

inspection of the licensee's

EP program (Inspection

Report

No. 50-244/95-10),

the licensee

was modifying its'otification process

to place one-hour

responders

earlier in the telephone tree

so that they could meet the one hour

response

goal.

Since that inspection,

the licensee

conducted

three quarterly

call-out drills without fully satisfying all of the intended objectives.

In

each drill, there

was

a different reason for not meeting the drill objectives.

In one, certain responders

exceeded

the one hour goal

by several

minutes

and

in the others,

portions of the telephone tree were not completed

due to a mis-

communication

and

an individual failing to follow procedures.

The inspectors

did not- consider these failures to be individually significant, but were

concerned that the licensee

continues to be unsuccessful

in meeting objectives

for this drill.

The licensee

plans to implement

an auto-dialer

system before

the end of 1996 to notify the responders

in a more timely and reliable manner.

This will be reviewed in a future inspection (IFI 50-244/96-01-03).

'

17

The inspectors

concluded that the licensee

was actively involved in the

Emergency Operations Facility

function.

Sufficient controls were implemented to monitor and assess

EP group

performance.

The

EP group is responsive

to assigned

CATS items

and was

appropriately self-critical regarding the call-out drill problems.

Overall,

-the licensee's

performance

in this area

was assessed

as satisfactory.

4. 1.2 Status of EP Facilities,

Equipment

and Resources

The inspectors

conducted

an audit of emergency

equipment in the Station

Control

Room, Technical

Support Center

(TSC), Operations

Support Center

(OSC),

Survey Center

(SC), Assessment

Facility (AF) and

(EOF).

The inspectors

also reviewed records of various equipment inventory

activities

and test surveillances

conducted during the past year

and reviewed

the capabilities of the licensee's

communication

system.

The inspectors

checked

several

emergency

equipment kits and emergency

cabinets

in the emergency facilities and found them to be appropriately stocked

as

directed

by the licensee's

procedures.

The inspectors verified that survey

meters,

personnel

dosimetry

and respirator canisters

were calibrated

and were

operationally ready.

The inspectors

reviewed equipment inventories

and surveillance

test reports

for 1995

and determined that equipment inventories

were conducted

at specified

frequencies

and checklists

were properly completed

and reviewed.

Inventory

lists included identified deficiencies

and .corrective actions

were well

documented.

While touring the

EOF, the inspectors

examined the survey team closet that

contained radiological instrumentation,

thermoluminescent

dosimeters

(TLDs)

and field emergency kits. It was noted that five TLDs used for survey team

members

were in close proximity to an unshielded

Cs-137 radioactive point

source

used for instrument

response

checks.

The inspectors

discussed. with the

licensee

the potential

exposure

to the TLDs from the point source,

possibly

causing

erroneous

dose results.

The licensee

committed to placing the point

source in a lead shield to prevent exposing the TLDs while in storage.

The Assessment

Facility (AF) is located in the licensee's

Training Center

East.

It has

a sample preparation

laboratory

and

a counting laboratory with a

whole body counter,

an alpha/beta

gas flow proportional

counter

and

a high

resolution

gamma spectrometry

system with two detectors.

The AF is routinely

used

as

an envir'onmental

laboratory during normal plant operations.

However,

in accordance

with the Nuclear

Emergency

Response

Plan

(NERP), Section 6.3.9,

the AF is to be used for receiving

and analyzing environmental

samples

collected

by field survey teams during an emergency

and, per Section 4.3.12,

serves

as

a backup laboratory for analyzing post-accident

sampling

system

(PASS)

samples, if the in-plant laboratory should

become inaccessible.

In

discussions

with members of the chemistry department,

the inspectors

determined that, while the licensee's

instrumentation

in the AF is calibrated

to analyze

a

PASS sample,

there were no procedures for activating this

facility as

a radiological laboratory during an emergency

nor were there

procedures for analyzing radioactive

samples

in the AF.

Further discussions

with the

OEP revealed that the following activities have never

been exercised

0

18

at*the AF in an emergency drill:

1) transporting potentially contaminated

offsite environmental

samples

from the

SC to the AF; 2) analyzing offsite

samples;

and 3) handling, transporting

and analysis of a

PASS sample.

The

lack of procedures

and failure to exercise this facility are violations of

10 CFR Part 50.47(b)(8)

and

(14) which require emergency facilities and

equipment

be provided

and maintained,

and periodic exercises

be conducted to

evaluate major portions of the emergency

response

capability.

(VIO 50-244/96-01-04).

The inspectors

reviewed the licensee's

communication

system capabilities

by

interviewing the Manager,

Communications

Design

and Support.

The purpose of

the interview was to obtain additional information for NRC evaluation

on the

communication

systems

and to follow-up on. information gathered

during the

The licensee's

system

appeared

to be

sufficiently redundant to ensure that

a communication link could be maintained

with offsite agen'cies

during severe

natural conditions.

The CNEP's

and OEP's direct program oversight

has resulted in an excellent

equipment inventory and surveillance test program.

With the exception of the

violation regarding the AF, the emergency facilities and equipment

were

maintained in a state of operationally readiness.

4.1.3

EP, Procedures

and Documentation

The inspectors

reviewed recent

NERP and

EPIP changes

to assess

the impact on

the effectiveness

of the

EP program.

The inspectors

also assessed

the process

which the licensee

uses to review EPIPs

and changes

made to them.

The inspectors

reviewed recent

changes

to the licensee's

NERP and

EPIPs

and

determined that the changes

did not reduce the effectiveness

of the program.

The inspectors

randomly selected

an

EPIP that had

been

changed

and reviewed it

against the licensee's

10 CFR 50.54(q) review process,

as well as the process

described

in administrative

procedure

A-205.2,

"Emergency

Plan Implementing

Procedures

'Committee."

The inspectors

found that the licensee

also performs

a

10 CFR 50.59 safety review for procedure

changes.

No problems

were

identified.

The inspectors

also reviewed

NERP and

EPIP changes

in the regional office.

Those are listed in Attachment

1.

The inspectors

determined that none of the

changes

decreased

the effectiveness

of the

NERP.

The inspectors

also reviewed the frequency of NERP and

EPIP reviews against

Section 7.2 of the

NERP, Annual

Review and Revision of the Plan

and Procedures

and A-601.4,

"Procedure

Control - Periodic Review."

The inspectors verified

that the licensee

conducts

annual

reviews of the

NERP and that

PORC has

reviewed the EPIPs within a five year period.

However, the inspectors

identified that the wording in the

NERP was misleading with respect to the

frequency of EPIP reviews

and should

be clarified,to reflect the intended

review cycle.

The licensee

agreed.

19

The licensee's

NERP and

EPIPs are sufficient to implement the

EP program.

The

changes

made to those

documents

and the change review process

were acceptable.

Overall, this area

was assessed

as satisfactory.

4.1.4 Staff Knowledge and Performance

in EP

The

CNEP and

OEP have two opportunities annually to broaden their

experiences.

Both had recently visited other licensees

to participate in

audits

or peer evaluations

and

had attended

industry seminars pertaining to

to maintain their proficiency.

The inspectors

interviewed four TSC directors to assess

the quality of NERP

training that these individuals received.

The inspectors

had each director

classify four events

and explain the'ir responses

to making protective action

recommendations

(PARS) under changing plant conditions

and

how RVLIS values

corresponded

to core uncovery.

The directors

answered all of'the questions

correctly.

4.1.5 Staff Training and gualification in EP

The inspectors

reviewed

EP training records,

training procedures,

lesson

plans,

EPIPs

and the licensee's

NERP to evaluate

the licensee's

EP Training

Program.

The inspectors

also reviewed chemistry procedures

and training

records for operating the Post Accident Sampling System

(PASS).

Using the

ERO list, the inspectors

randomly selected

50 individuals'raining

attendance

records

from the Training Department files.

The records

indicated

that all of the selected

ERO personnel

had received their annual training and

were qualified to fill their assigned

emergency

response

positions.

The

inspectors verified that the

CNEP had removed individuals from the

ERO list

who failed to meet training requirements,

and that

new

ERO members

had

received the required training.

The inspectors

reviewed various

EP lesson

plans

and determined that they met the objectives set forth in the Nuclear.

Emergency

Response

Plan Training Program Procedure,

TR C.22.

The inspectors

reviewed training agendas

provided by the licensee

and their

contractor to local hospitals,

township fire departments,

sheriff offices and

ambulance services'gainst

NERP, Section

7. 1.4, Special Training for

Participating Agencies,

and found them to be very comprehensive.

State

and

. local agencies

appear to be kept well informed of any

NERP changes.

The

licensee

also participated

in numerous

town meetings providing support to

local agencies.

The inspectors

also reviewed chemistry procedures

for operating the

PASS and

found them to be comprehensive.

The training records

indicated that chemistry

technicians

received

both classroom

and hands-on training annually.

In

addition, the chemistry supervisor recently

began to test technicians

monthly

on operating the

PASS to maintain their proficiency.

In 1995, the licensee

conducted

a semi-annual

Health Physics drill to specifically test the adequacy

of the

PASS

and found performance to be acceptable.

Also, in October

1995,

the

NRC performed

a radiological confirmatory measurements

inspection

(NRC

'I

20

Inspection

Report

No. 50-244/95-18).

During that inspection,

the inspectors

observed

the licensee

successfully taking

a

PASS reactor coolant sample.

The inspectors

determined that the licensee

maintained

a good onsite training

program

and noted that the licensee is very diligent in providing training,

conducting drills and maintaining

an excellent rapport with state,

local

and

emergency

support entities.

The licensee

was fully capable of operating the

PASS and technicians

were well trained.

4.1.6 Organization

and Administration

The licensee's

EP organization

and

ERO have remained essentially stable

since

the last program inspection

when

a corporate reorganization

had occurred.

There were no changes

in the management

reporting chain for the

EP group.

The

OEP,

who has

been in his position for over

a year, reports to the

CNEP,

who

reports to the

MNA who then reports to the Vice President

Nuclear Operations.

The inspectors

interviewed the

CNEP and the

MNA separately

regarding the

program,

program initiatives and significant issues.

All responses

were

consistent;

therefore,

the inspectors

concluded that good communications exist

within the

EP group.

Neither the

HNA or the

CNEP has

been

assigned

additional responsibilities

since the last inspection.

However, the inspectors

observed

a minor

discrepancy

in the organization chart in Figure 7.1 of the

NERP.

The chart in

the

NERP does not include Process

Improvement

as

a reporting function to the

HNA.

The inspector's

determined this to be insignificant and the licensee

agreed to revise the

NERP chart.

According to-the

CNEP, offsite personnel

and organizations

remained the

same

except that the director of the State's

emergency

management

organization

was

replaced.

The individuals who report to the director have remained the same.

The inspectors

concluded that offsite support

has not been significantly

effected

by personnel

changes.

The inspectors

found that there were no changes

to personnel

in key

ERO

positions since the last

EP program inspection

and each

ERO position is

staffed with at least three qualified individuals.

Overall, staffing of the

licensee's

organization

and offsite entities

have

been stable.

4.1.7 guality Assurance in EP Activities

The inspectors

reviewed Audit Reports

AINT-1996-0001-NAB and

AINT-1995-0007-GFS, of the'EP Department,

conducted

in 1996 and

1995,

respectively.

The inspectors

also reviewed audit plans, checklists,

procedures

and interviewed personnel

from the

gA Department regarding the

process for conducting

a program audit.

Based

on document review and interviews, the inspectors

determined that the

audits were conducted utilizing an audit plan

and checklists

and that the

audit team included

a technical specialist

from another nuclear utility.

The

1996 Audit Report, stated that program deficiencies identified in 1995 were

corrected with the exception of the licensee failing to keep telephone lists

i

21

current.

The licensee is currently working to resolve this matter

and it has

been entered

into the tracking system.

Overall', the audits

addressed

the

areas

specified in 10 CFR 50.54(t).

'owever,

the inspectors identified that

gA had never audited the contractor

used to audit, train,

and provide radiological medical consultations

to local

hospitals,

although other licensee contractors

had

been audited.

The

inspectors

stated that

an audit of the

EP contractor,

although not a

requirement,

would be beneficial to the program.

While interviewing the

gA Manager

and the Independent

Assessor,

the inspectors

were informed that pre-audit interviews were conducted with the supervisor of

the departments

being audited.

In accordance

with gA Procedure

gA-1803,

"Performance of guality Assurance Audits," the pre-audit conference with the

'supervisor is intended to "solicit scope additions

and management

concerns."

According to the

gA Manager, this conversation

is used to solicit additional

information,

such

as department deficiencies

and problems,

and is then

added

to the audit plan

and checklist.

The inspectors

reviewed the audit plans

and

checklists

from 1996

and 1995,

and could not determine if information from the

pre-audit interview was

added to either the audit plan or checklist or what

portion of the audit focused

on the identified deficiencies or problems.

The

licensee

stated that the pre-audit interview makes

them aware of already

existing problems which serves to better utilize the time spent in an audit.

III

The guideline in Section 4.3 of ANSI/ASME N45.2.12-1977,

states that,

"a brief

pre-audit conference

shall

be conducted with the cognizant organization

manager.

The purpose of the conference

shall

be to confirm the audit scope,

present

the audit plan, introduce auditors,

meet counterparts,

discuss

audit

sequence

and plans for the post-audit conference,

and establish

channels of

communications."

Also, Section 4.3.2.2 states,

"objective evidence shall

be

examined for. compliance with quality assurance

program requirements."

The

inspectors

agreed that

a pre-audit conversation

to discuss

the scope of the

audit is an acceptable

practice,

but having the audited supervisor identify

deficiencies

and problems could raise questions

about the capability of the

audit team to identify program problems independently.

Also, the inspectors

questioned

the audit team's capability of remaining objective in reaching its

conclusions if an issue

has already

been characterized

as

a problem by the

supervisor prior to the audit.

While the contents of the audit, reports satisfied

10 CFR 50.54(t)

requirements,

the inspectors

was not able to determine if the audit was unduly

biased

by the pre-audit interview.

Although the gA Manager believes this

practice to be acceptable,

he agreed to review the matter.

.4. 1.8 Miscellaneous

EP Issues

U dated Final Safet

Anal sis

Re ort

I consistencies

Since the Ginna

UFSAR does not specifically include

EP requirements,

the

inspectors

compared

licensee activities'to the

NERP, which is the applicable

document.

The following inconsistencies

were noted

between

the emergency

plan

and licensee activities by the inspectors.

f,

22

1. The inspectors

reviewed Section 8.1 of the licensee's

NERP describing

recovery

and noted that the Plant Operations

Review Committee

(PORC) is-

responsible for evaluating plant conditions,

reviewing decontamination

activities

and necessary

repairs prior to giving approval for plant

reentry.

The inspectors

reviewed the

PORC charter

and noted that it did

not mention their recovery

phase responsibilities.

Also, per the

NERP,

.

members of the recovery organization will be given recovery training

, annually.

The inspectors

discussed

exercising recovery actions with the licensee.

The licensee

stated that at the conclusion of every exercise,

the recovery

manager

discusses

recovery actions with his staff.

Additionally, the

inspectors

determined that recovery training is included in the annual

emergency

response

requalification training.

However, the licensee

could

not provide assurance

that all

PORC members

are part of the

ERO,

and

therefore,

are receiving the emergency

response

requalification training.

The licensee

stated that the

ERO and the training records

would be reviewed

to determine whether all

PORC members receive the necessary

training

regarding their recovery

phase responsibilities

and the

PORC Charter will

be revised to be consistent with the

NERP.

2. The Nuclear

Emergency

Planning Organizational

Chart listed

on

NERP Figure

7.1 was

compared to the

EP departmental

organization chart

and it was

determined that

a minor discrepancy

existed

(See Section 4. 1.6).

3.

The licensee

has never exercised

the Assessment

Facility for analyzing both

onsite

and offsite samples

during an emergency.

Also, the licensee

does

not have procedures for using this facility as

a radiological laboratory.

These

are required

by Section 7. 1.5 and Section 6.3.9 of the

NERP

(See

Section 4. 1.2 and Notice of Violation).

Closed

IFI 50-244 95-19-01

Reactor

Vessel

Level Indication

S stem

RVLIS

Discre ancies

During the December

1995 exercise,

confusion arose

among participants

pertaining to RVLIS.

Specifically, it was uncertain

what RVLIS value

corresponded

to the top of the fuel.

The lead inspectors

called two licensee

personnel

to obtain the correct value.

The inspectors

was given three

different RVLIS values for the top of the fuel - 1)

42 percent

was the value

from the licensee's

Emergency

Response

Data System

(ERDS); 2)

55 percent

was

from an engineering

drawing;

and 3) 68 percent

was from the emergency

operating

procedures

(EOPs) setpoint

book when in adverse

containment

conditions.

The lead inspector

asked the licensee to resolve the confusion

and to ensure that the concept of adverse

containment conditions,

and its

implication for all instrumentation

readings,

were understood

by engineers

in

the

TSC and

EOF.

The licensee

agreed to correct the

EROS RVLIS value

and to

review all

ERDS parameters

to ensure

accuracy.

The licensee

also agreed to

ensure that the correct values

and the concept of adverse

containment

condition values

would be properly incorporated into all procedures.

Since that time, the licensee

conducted training and revised the core

damage

procedure

and appropriate

EAL basis to clarify the issue.

The value to be

23

used for the top of the fuel is 68 percent,

which is the value used in the

EOPs

and which incorporates

instrument uncertainties

associated

with adverse

containment conditions.

During this inspection,

the inspectors verified the

effectiveness

of the licensee's

training by questioning four TSC directors

about

RVLIS.

Their answers

were correct

and consistent with licensee

expectations.

The licensee

also revised

EPIP 2-16,

"Core Damage Estimation,"

by cautioning users to utilize the setpoints

and instructions

found in the

EOPs

and to consider

core exit thermocouple

temperatures,

in addition to water

level,

when analyzing core conditions.

The licensee

also

added

an engineering

diagram depicting

RVLIS values to their corresponding

reactor

vessel

location

to assist

personnel

in assessing

core uncovery.

The licensee

changed

the

wording in several

emergency

action level basis

documents to clarify minimum

level for core cooling.

The licensee is currently reviewing and revising its

EROS data point library to ensure that RVLIS and other values

are correct.

Based

upon the licensee's

corrective action to this issue, this item is

closed.

C osed

U I 50-2

93-18-02

U t

m l

r tec i e

t o

e

o

e

d tio

During the November

1993 exercise,

an area for potential

improvement

was noted

regarding a,failure to issue

a timely PAR.

When

a General

Emergency

(GE) is

declared,

a

PAR is to be issued with the 15-minute notification.

The

licensee's

notification form listed four choices for PARs:

1) There is no

need for protective actions outside the site boundary;

2)

Need for protective

action is under evaluation;

3) Sheltering

recommended;

and 4) Evacuation

recommended.

During the exercise,

the

GE was declared at approximately

10: 15 a.m.

At 10:25 a.m., the licensee

issued

the

PAR

"Need for protective

action is under evaluation."

The licensee

was prepared to issue

a

PAR based

on plant conditions at the time of the

GE declaration;

however, prior to

making the offsite notifications, plant conditions

changed

such that the

PAR

also changed.

The licensee

took time to evaluate

the latest plant and

radiological conditions to make the appropriate

PAR,

and correctly issued

the

PAR to shelter at 10:55 a.m.

This was '40 minutes after the

GE had

been

declared

and did not meet the

15 minute goal.

During inspection

94-21, the inspectors

determined that the licensee

deleted

"Need for protective action is under evaluation"

as

a

PAR option.

..This

removed the implication that

PAR issuance

can

be delayed.

Also, the

inspectors

reviewed requalification training lesson

plans

and confirmed that

the objective of issuing

a

PAR within 15 minute of the

GE declaration

had

been

emphasized

to potential decision-makers.

However,

due to the potential public

impact of delaying

a-PAR, this issue

remained

open pending the timely and

accurate

PAR issuance

by the licensee

during an

NRC evaluated

exercise.

During the licensee's

December

6,

1995 full-participation exercise

(Inspection

Report 95-19), the licensee

successfully

demonstrated

the timely and accurate

issuance of PARs.

Due to an administrative oversight, this item was not

closed at that time.

The inspectors

determined that the licensee's

performance

during the December

1995 exercise

was sufficient to close

URI 50-

244/93-18-02.

I

4.2

Radioactive Liquid and Gaseous

Effluent Control

Programs

(IP 84750)

4.2.1 Nanagement

Controls

o

am

C

a

es

The inspector reviewed the organization -and administration of the radioactive

liquid and,gaseous

effluent control programs.

The inspector

determined that

there were no changes

to the radioactive effluent control

programs

since the

last inspection

conducted

in July 1994.

The Chemistry Department

has primary

responsibility for conducting the radioactive liquid and gaseous

effluent

control programs.

Other responsible

groups for the programs

are:

1) Operations,

2) Instrument

and Controls (I&C), 3) System Engineers,

4)

Results

and Test

(R&T), and 5) Radwaste

Operations.

ualit

Assurance

A

Audits

The inspector

reviewed the

1995

gA audit report (Report No. AINT-1995-0010

-GFS), required

by Section 6.5.2.8 of the technical specifications

(TS).

The

gA audit covered eight areas,

including radioactive liquid and gaseous

.

effluent control programs, radiation protection,

and the Radiological

Environmental Monitoring Program.

There were

no audit findings or

deficiencies identified by the

1995 audit team for the effluent control

programs.

Based

on the

1995 audit report review, the inspectors

determined

that the licensee

met the

TS requirement.

eview of Semiannual

Annual

Rad oactive

E f uent

Re

o ts

The inspector reviewed the

1994 semiannual

and the

1995 annual radioactive

effluent release

reports.

These reports provided data indicating total

released

radioactivity for liquid and gaseous

effluents.

These reports also

summarized

the assessment

of the projected

maximum individual

and population

doses resulting from routine radioactive airborne

and liquid effluents.

Projected

doses

were well below the

TS limits.

The inspector determined that

there were no obvious anomalous

measurements

or omissions

in the reports.

4.2.2 Review of Off-Site Dose Calculation Nanual

(ODCN)

The inspector

reviewed the licensee's

current

ODCM (effective date

February

24,

1996).

The

ODCM provided descriptions of the sampling

and

analysis

programs that are established

for, quantifying radioactive liquid and

gaseous

effluent concentrations

and for calculating projected

doses. to the

public.

All necessary

parameters,

such

as effluent radiation monitor setpoint

calculation methodologies,

site-specific dilution factors,

and dose factors,

were listed in the

ODCM.

The licensee

adopted other necessary

parameters

from

Regulatory Guide

1,. 109.

,,Based

on the above review, the inspector determined that the licensee's

ODCM

contained all necessary

information and instruction to establish

and implement

the radioactive liquid and gaseous

effluent control programs

and the

Radiological

Environmental Monitoring Program.

r

25

4.2.3 Radioactive Liquid And Gaseous

Effluent Control

Programs

To determine the implementation of the

TS and the

ODCM requirements,

the

inspectors

toured the plant,

reviewed the following selected

licensee's

procedures,

and reviewed selected

radioactive liquid and gaseous

discharge

permits:

~

CH-RETS-Minipurge

~

CH-RETS-Purge-CV

~

CH-RETS-PV-Release

~

CH-RETS-GDT-Release

~

CH-RETS-LIg-Release

During the tour, the inspector noted that all effluent radiation monitoring

systems

(RMS) were operable

at the time of this inspection.

During the review

of the above radioactive liquid and gaseous

effluent procedures,

the inspector

noted that the procedures

were easy to follow and contained sufficient level

of detail.

The inspector also determined that the reviewed discharge

permits were

complete

and met the

TS/ODCM requi} ements for sampling

and analyses

at the

required frequencies

and met the lower limits of detection established

in the

ODCM.

4.2.4 Steam Generator

Blowdown Tank and Spent

Fuel

Pool

Leakages

This portion of the inspection evaluated

the licensee's

efforts to accurately

quantify and characterize

suspected

leakage

from the steam generator

blowdown

tank and the spent fuel pool system,

and potential

dose

consequences

of any

releases

to the environment.

This evaluation

focused

on the licensee's

actions

and their results in this area since January

1996 and future plans

with respect to the steam generator

blowdown tank and the spent fuel pool

system.

S

G

Blowdown Tank Leaka

e

On January

5,

1996, the licensee

noted that small

amounts of iodine-131

(I-131) and iodine-133 (I-133) were measured

in grab samples

taken from the

turbine building retention tank and the intermediate

subbasement

ground water

in-leakage.

Further licensee

investigation results revealed that the origin

of the leakage

was from the discharge

piping of the steam generator

(SG)

blowdown tank.

The retention tank, also

known as the turbine building drains

tank, is located in the turbine building and collects drainage

from

miscellaneous

drains

such

as roof drains

and floor drains.

The licensee

was

not able to determine

the leak rate,

because

there is no flow measurement

instrument installed for measuring

the flow rate downstream of the blowdown

tank.

Therefore,

the total

amount of leakage to the soil under the turbine

building floor was not known.

The licensee

speculated

that the leakage

was

small,

because

iodine activities from the retention tank and the intermediate

subbasement

ground water in-leakage

were very low.

During the outage in

April 1996, the licensee

plans to modify the discharge

piping, which is

expected to stop this leakage

pathway.

26

The licensee

took routine grab samples

from the

SG blowdown tank and analyzed

them for gamma emitters

and tritium.

The licensee

also performed the

projected

dose

assessment,

as required

by the

TS and the

ODCH.

The inspector

reviewed the analytical results

and the projected

dose

assessment

results,

which were calculated

based

on the total release of the

SG blowdown tank for

the period of January to February

1996.

Major gamma emitters

were

radioiodines with range of lE-6 to lE-7 pCi/cc.

Tritium activity was about

1E-4 pCi/cc.

The maximum projected thyroid doses for January

and February

was

1.99E-2

mrem and 2.58E-2

mrem, respectively.

These values

were well below

regulatory limits.

The licensee

suspects

that

a small fraction of

radioiodines

(mainly I-131 and I-133) may be dep'osited

in soil under the

turbine building floor, while tritium may be migrating into ground water.

Based

on the above reviews

and short half-life of radioiodines,

the inspectors

determined that the leakage

was not currently of sufficient magnitude to

affect public health

and safety or the environment.

S ent Fuel

Pool

Leaka

e

During previous inspections

(Inspection

Rep'ort Nos:

50-244/95-20

and 95-21),

an

NRC inspector

reviewed the licensee's

investigation results for the

suspected

fuel pool leakage,

including planned future actions.

t

There are three on-site environmental wells located northeast

(Well C),

southeast

(Well B), and southwest

(Well A) of the plant.

Analytical results

of tritium at Wells A and

B suggested

that tritium activities

had not

increased

since

November

1995.

But tritium activities at Well

C had increased

since September

1995,

as

shown in Table 1.

Table

1 - Analytical Results of Tritium for On-Site Environmental

Wells

Unit: pCi cc

Date

9-1-95

10-16-95

11-8-95

11-17-95

11-28-95

12-15-95

1-18-96

1-25-96

2-7-96

2-23-96

"

Well A

No Measurement

1.74E-8

6.31E-8

-3.80E-8

6.58E-7

No Measurement

Well

B

No Measurement

4.98E-7

No Measurement

3.45E-7

1.96E-6

No Measurement

Well

C

1.76E-6

6.90E-7

No Measurement

2.02E-7

-1.74E-7

2.05E-6

4.16E-6

3.40E-6

1.53E-5

1.75E-5

27

Below the minimum detection level.

Normal environmental

background is

approximately

1E-7 pCi/cc.

Mell

C was the optimum location to monitor possible

environmental

release

through ground water due to the prevalent northeasterly direction of ground

water flow.

Analytical results of Wells A and

B were used

as environmental

background,

since they are upstream of the underground water flow.

During this inspection,

the inspector discussed

the site hydrology with the

licensee

and

a consultant.

The consultant

(Dr. R. Poreda,

Associate

Professor,

University of Rochester)

presented

tritium underground migration

study results,

and desc} ibed the underground water mixing ratio.

The high-

mixing ratio indicated relatively low underground

water movement.

The mixing

ratio at the Mell

C was the highest

and suggested

that the underground

water

movement

was slow at this location.

This study supports

the slow tritium

increase

seen at Well C,

as illustrated in Table l.

The depth of Well

C is about

20 feet from ground level.

In order to assess

the underground

water movement better,

a new deep well adjacent to Well

C has

been

recommended

by the licensee's

consultant to obtain better

characterization

and representation

of suspected

leakage to the environment.

4.2.5

NRC Assessment

and Planned

Licensee Action

Based

on reviews of limited analytical data

and interviews with the licensee

and its contractor,

the inspector

made the following conclusions:

~

The sources of contamination

at Mell

C may be multiple, such

as leakage

from the spent fuel pool

and

SG blowdown tank.

Routine discharge

pathways,

such

as condenser air ejector effluents, might also contribute to the

tritium activity at Well C; and,

~

The suspected

leakage

from the spent fuel pool

and the

SG blowdown tank,

do

not currently impact public health

and safety

and the environment.

In an effort to provide for assessment

of suspected

leakage,

the licensee

plans to:

~

Install

a deeper monitoring well (or a multi-level monitoring well)

adjacent to Well

C and analyze

ground water samples;

~

Continue to monitor and analyze

samples

from on-site Wells A, B,

and

C;

~

Continue to monitor and evaluate

the ground water movement;

and,

~

Determine actions for resolution of remediation of suspected

leakage.

~

Apply an epoxy coating to the bottom of the fuel transfer canal to stop

leakage

through the foundation bolts supporting the fuel transfer cart

rails.

~

A

28

The inspector

found the licensee's

current action plan to be appropriately

scoped.

4.2.6 Calibration of Effluent/Process

RHS

The inspector reviewed the most recent calibration results for the following

effluent/process

RHS to determine the implementation of the

TS requirements:

~

RE-10A, Containment

Iodine

Gamma Detector

~

RE-12,

Containment

Gas Detector

~

R-12A, Containment

Purge

(SPING-4)

~

R-14A, Plant Vent (SPING-4)

~

R-15A, Condenser Air Ejector

(SPING-4)

~

RE-17,

Component

Cooling Water Detector

~

RE-18, Liquid Waste Disposal

~

RE-19,

Blowdown

~

RE-20 ALB, Spent

Fuel Pit Service Water Detectors

The

18C Department

and the RP/Chemistry

Department

had the responsibility to

perform electronic

and radiological calibrations,

respectively, for the above

radiation monitors.

All reviewed calibration results

were within the

licensee's

acceptance criteria.

The inspector discussed

the maintenance

of operability/reliability with the

members of the

18C and RP/Chemistry staff.

From these interviews, the

inspector determined that these individuals had good knowledge of the

RHS

relative to operability requirements

and performance history.

The inspector

noted that the

RHS read-out devices in the control

room were replaced with

digital devices.

Consequently,

calibration results

are more reliable because

more accurate

readings

can

be obtained.

The inspector also noted that the

licensee

performed daily trending analysis for the above

RHS in the main

control room.

The licensee plots

RMS readings

twice in a day on the control

charts to track any changes.

The inspector stated that the tracking of RHS

readings

was

an excellent effort to verify the system operability and

reliability.

Based

on the above reviews,

the inspector determined that the licensee's

performance

and achievements,

relative to calibration of the

RHS and the

upgrading projects,

were sufficient to demonstrate

good operability and

reliability of the system.

4.2.7 Air-Cleaning Systems

ir-Clean n

S stems

e uired

b

the Technical

S ecification

The inspector

determine the

emergency 'air

-The inspector

reviewed the licensee's

most recent surveillance

test results to

implementation of TS requirements for the:

1) control

room

supply systems,

and 2) containment air recirculation system.

reviewed the following surveillance test results:

~

Visual Inspection

~

In-Place

HEPA Leak Tests

29

~

In-Place Charcoal

Leak Tests

~

Air Capacity Tests

~

Pressure

Drop Tests

~

Laboratory Tests for the Iodine Collection Efficiencies

All test results

were within the licensee's

TS acceptance

criteria.

The

inspector

had

no further questions

in the above surveillance tests.

ir-Cleanin

S stems

Oescr

bed in the

U dated Final Safet

nal sis

e ort

During the reviews of other air-cleaning

systems

committed

by the

UFSAR, the

inspector

noted that the licensee's

procedure did not have acceptance

criteria

for the airflow capacity test

and resulted deviations

from the

commitments.

The current industry practice for the acceptance criteria of the

airflow capacity test is +10 percent of the designed flow.

These

acceptance

criteria are also listed in ANSI N510-1986.

The following was noted:

~

UFSAR 6.4.2.2.1:

Airfloh capacity for the Control

Room during the

normal operation is 8,045 cfm.

Surveillance Results:

~

UFSAR 12.3.3.2:

2-5-94

12,821

scfm

4-13-95:

-

10,431

scfm

Airflow capacity for the Plant Vent is 75,000 cfm.

The value is being used for the setpoint calculation,

as defined in the

ODCH.

Surveillance

Results:

3-31-92:

66,554

scfm for A-Train

68,819

scfm for B-Train

3-8-94:

67,364

scfm for A-Train

75,662

scfm for B-Train

3-21-95:

63,139

scfm for A-Train

68,247

scfm for B-Train

10-5-95:

61,660

scfm for A-Train

No data for B-Train

~

Auxiliary Building Ventilation System:

No airflow capacity

was defined in

the

UFSAR.

Therefore,

the licensee

assumed,

based

on nominal air flow per

filter (84

HEPA filters x 1,000 cfm per filter

84,000 cfm).

The inspector noted that the

UFSAR did not provide any acceptance

criteria for

the air capacity test,

and the listed values for the above

systems

were vague

relative to design requirements.

Although these

apparent

discrepancies

between surveillance

tasks

and the values listed in the

UFSAR do not have

a

significant impact

on public health

and safety

and the environment,

the

inspector

stated that:

1) airflow capacity test procedures

should

be updated

to follow the industry practice;

2) design-base

airflow capacity should

be

retrieved from the original design basis,

rather than

assumed

(e.g., auxiliary

I

30

building ventilation system);

and,

3)

UFSAR should

be reviewed

and updated to

reflect the current plant designs

and configurations.

This item is considered

unresolved

pending further review (URI 50-244/96-01-05).

The licensee

stated

that the

UFSAR is being reviewed

and will be updated.

4.3

Radioactive

Waste Storage,

Processing

Systems,

and Equipment (IP 71750)

The Waste Disposal

System

(WDS) at the Ginna Station consists of three

subsystems

used to collect and process all potentially radioactive liquid,

gaseous,

and solid waste.

All the equipment for these

subsystems

has

been in

place since original plant construction,

except for the

a liquid waste

evaporator that was removed from service

and abandoned

in place in 1990

and

an

ultra filtration unit physically removed from the plant in 1980.

Radioactive

fluids entering the

WDS are collected in sumps

and tanks until a determination

is made

on the type

and level of treatment

necessary.

The fluids are

sampled

and analyzed to determine the level of radioactivity before

any discharge

is

made.

Liquid wastes requiring cleanup before release

are collected

and

processed

by a vendor supplied demineralization

system.

All solid waste is.

packaged

and stored

on site until they are shipped offsite for disposal.

Gaseous

waste is pumped to a gas

decay tank where it is held for a suitable

decay period.

The gases

are then discharged intermittently at

a controlled

rate through

a monitored plant vent.

The principle components of the

WDS

include the following:

1) Miscellaneous

Waste Disposal

System (radio chemistry laboratory drain tank

and discharge

pump; laundry hot shower tanks;

intermediate building sump

pump)

2) Liquid waste drains,

waste holdup tank (auxiliary building equipment

and

floor drains)

3) Spent resin tanks

and cubicle

4) Liquid waste evaporator

and waste

condensate

tanks

(abandoned

in place,

no

maintenance

required)

5) Reactor coolant drain tank

6)

Gas waste disposal

system

(gas compressors,

compressor

moisture separators

and compressor

seal

heat exchangers,

and gas

decay tanks)

The inspector

discussed

the radiological conditions present

in the

WDS

equipment with the principle health physicists at the station.

There are

currently no hot spots or high exposure

areas that are accessible

to

personnel,

and no spills of radioactive material

have occurred

from the

WDS

since

an incident in 1983.

No residual effects from that incident appear to

remain.

No excess

personnel

exposure

or contamination incidents

have occurred

in recent years

from the use of these

systems.

The system engineer for the waste disposal

systems

conducts quarterly walkdown

inspections.

For each walkdown, the engineer

documents

the condition of the

equipment

and identifies any,deficient conditions that require corrective

action follow-up.

The most recent

walkdowns were performed in February

1996

and no conditions requiring immediate maintenance

were identified.

Minor

discrepancies

were noted

and were scheduled for routine maintenance.

Portions

of the radwaste

systems

already

have established

performance criteria since

they will fall within the scope of 10 CFR 50.65

(Maintenance

Rule) in July

~

31

1996.

The system engineer

performed

a two year historical evaluation of these

systems

and documented

the amount of corrective maintenance

and the

modifications

made over that period.

The inspector reviewed this

documentation

and determined that the amount of corrective maintenance

and the

number of modifications have not been significant.

The inspector

reviewed the

P8 IDs for these

systems

and conducted visual

inspections of all accessible

equipment.

Overall, these

systems

are well

maintained

and do not appear to represent

a significant radiological

hazard to

plant personnel.

All areas

and equipment

observed

are serviced

by the

filtered ventilation system for the auxiliary building,

and fire protection

systems

also were present

in these

areas.

Section 1.2.6 of the

UFSAR for the

Ginna Station contains

a brief description of the purpose

and

use of the Waste

Disposal

System.

The description indicates that the system collects

and

processes

for disposal all potentially radioactive liquids, gaseous,

and solid

waste resulting from reactor operation

and cleans

up all effluents released

to

the environment to concentration

levels below those required

by 10 CFR 20.

Operating procedures

are designed to limit normal effluents to within the

limits required

by 10 CFR 50, Appendix I.

Solid wastes

produced at the Ginna

Station are packaged

and shipped for disposal

at authorized locations.

The

inspector

concluded that no inconsistencies

appear to exist between the

locked high radiation area.

description of the waste disposal

system

and its use,

and the system installed

and

used in the plant.

The inspector also determined that there

does not

appear to be

a need for enhanced

inspection of these

systems

beyond

the'outine

inspections currently performed.

ontaminated

Stora

e Buildin

CSB

The licensee

maintains

a separate facility at the Ginna Station with a

controlled environment for storing contaminated

and reusable tools and

equipment.

Equipment that can

be decontaminated

to less

than 8 mR/hr on

contact is stored in containers that protect the equipment

and personnel.

The

general

area

background levels inside the

CSB are currently about

1 mR/hr.

The

CSB also contains

a specially designed

work area for decontaminating

the

stored

items after they are used.

The wor k area contains

the appropriate

facilities for filtered ventilation and collection sinks for capturing liquids

and solids

removed during the decontamination

work.

The inspector toured the

CSB and observed

the arrangement

of stored

equipment

and plant personnel

'andling

and processing materials

and equipment returning to storage.

The

radiological controls in place

appeared

to be effective and the general

state

of housekeeping

in the

CSB was very good.

Video Ins ection of S ent Resin Tank Roo

The two spent resin tanks at Ginna are located inside

a cubicle in the lower

level of the Auxiliary Building adjacent to the charging

pump room.

The

cubicle

has

been

blocked off to personnel

access

since late

1970 due to the

high radiation levels present

inside the cubicle after the first plant

operating- cycle.

An unsealed

concrete

block barrier completely fills the

inner doorway into this area

and provides shielding from the high radiation

inside.

The outer doorway in front of the concrete

blocks is maintained

as

a

The cubicle was last entered for a radiological

32

n

survey in 1993 after all spent resin stored onsite

was shipped

away for

disposal.

The cubicle contains

two 150 ft'apacity resin tanks

and

associated

piping to store contaminated

spent resin from the

CVCS purification

system demineralizers.

Routine entries for surveys

are not made into the cubicle since all valves

and

operator controls for the equipment

are located outside the cubicle.

However,

on Harch 20,

1996, the licensee

removed

one row of concrete

blocks at the top

of the doorway to gain access

for a remote= radiation survey,

and for a remote

color video inspection.

The inspector

observed

the inspection

on a remote

monitor and noted the material condition of the cubicle.

Host areas

were

visible to the camera

except directly under the two tanks. 'ne tank contained

approximately

40 ft'fspent resin

and was creating

a radiation field of 400

mR/hr just on the insi'de surface of the block wall.

Both tanks

and all of

their associated

piping are stainless

steel.

The equipment also appeared

to

be in very good condition,

and was not'deteriorating.

There were no signs of

current leakage of any liquid or resin from any of the piping. or" tanks.

The

walls and floors of the cubicle were dry.

A padlock and small piece of sheet

metal

were noted

on the floor; however,

the cubicle was otherwise clean,

and

was not being

used to store

any waste material in barrels or other containers.

Overall, the cubicle appeared

to be in very good condition and did, not

represent

a potential

hazard to personnel.

The 40 ft'fspent resin in one

tank represents

the total stored inventory onsite at the present

time.

The auxiliary building also contains

a "DI Vault" which houses

several

deionization vessels

used in the

CVCS purification system,

the

SFP cleanup

system,

and other purification systems

in the plant.

This vault was also

blocked off to personnel

access

in 1970 due to the very high radiation levels

inside.

The last radiological

survey available for this vault was taken in

February

1988

and indicated that tank surface contact readings varied from

, 2 10 R/hr.

The survey also indicated the'resence

of a small, amount of

water on the floor that was apparently leaking from a pipe in the overhead, of

the vault.

The licensee

was not able to confirm whether there is currently

any water present

in the vault, or if any maintenance

was performed

on

interior piping in 1988.

However, the inspector

observed that the block wall

in the access

doorway was not sealed,

and there

was

no water present at the

exterior base of the wall.

The licensee

agreed to perform a remote video

inspection of the vault during the current refueling outage,

and will document

the general

condition of equipment

and the radiation levels in the room.

4.4