ML17262A796

Insp Rept 50-244/92-02 on 920119-0309.Violations from Insp on 911202-20 Noted.Major Areas Inspected:Plant Operations, Radiological Controls,Maint/Surveillance,Security, Engineering/Technical Support & Safety/Quality Verification

ML17262A796
Person / Time
Site:	Ginna
Issue date:	03/24/1992
From:	Lazarus W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML17262A794	List: ML17262A793 ML17262A795 ML17262A796
References
50-244-92-02, 50-244-92-2, NUDOCS 9204030024
Download: ML17262A796 (34)

See also: IR 05000244/1992002

Text

U. S. NUCLEAR REGULATORY COMMISSION

REGION I

Inspection Report 50-244/92-02

License: DPR-18

Facility:

R. E. Ginna Nuclear Power Plant

Rochester

Gas and Electric Corporation (RGB')

Inspection:

Inspectors:

January,

19 through March 9, 1992

T. A. Moslak, Senior Resident Inspector, Ginna

E. C. Knutson, Resident Inspector, Ginna

D. C. Lew, Project Engineer, Branch 3

Approved by:

W.J

s, hi, Reactor Projects Section 3B

INSPECTION SCOPE

Date

Plant operations, radiological controls, maintenance/surveillance,

security,

engineering/technical

support, and safety assessment/quality

verification.

INSPECTION OVERVIEW

Op

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at hot shutdown conditions.

The licensee aggressively pursued the causes of the trips which

were related to a possible main generator voltage regulator malfunction and to a main

feedwater pump trip, respectively.

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radioactive material released

through unmonitored steam flow paths.

M inten nce/ urveillance:

Power was reduced to permit plugging of leaking main condenser

tubes.

Effective management

involvement minimized the period of reduced power operation.

En ineerin /Technical S i

rt: Deficiencies in engineering support identified during a

Service Water System Operational Performance Inspection have resulted in apparent

violations of regulatory requirements in the areas of design control and Final Safety Analysis

Report updating.

'F204030024

920326

PDR

ADOCK 05000244

8

PDR

TABLEOF CONTENTS

VERVIEW

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TABLE OF CONTENTS

1.0

PLANT OPERATIONS.......... ~...................

1.1

Operational Experiences

1.2

Control ofOperations...........................

1.3

Loss of Main Generator Excitation Voltage/Reactor Trip

1.4

Reactor Trip Resulting From Loss of "A" Main Feedwater Pump

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2.0

RADIOLOGICALCONTROLS ..........,............

2.1

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

2.2

Radioactive Material Release Accountability for Unmonitored.

Discharge Paths

3.0

MAINTENANCE/SURVEILLANCE

3.1

Corrective Maintenance

3.1.1

Main Condenser Circulating Water Tube Leaks

3.1.2

Nuclear Instrument Power Mismatch Bypass Switch

Replacement

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

3.2

Surveillance Observations

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SECURITY

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5.0

ENGINEERING/TECHNICALSUPPORT

5.1

Service Water System Operational Performance Inspection (50-244/91-

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6.0

6.2

6.3

6.4

6.5

6.6

SAFETY ASSESSMENT/QUALITY VERIFICATION

6.1

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

6.1.1

(Closed) Unresolved Item (50-244/90-31-03) Implementation of

Long Term Corrective Actions....................

6.1.2

(Closed) Unresolved Item (50-244/89-80-06) Evaluation of Site

Contingency Procedures

Related to Fire Fighting

Periodic Reports.................................

Licensee Event Reports (LERs)..................,.....

Plant Operations Review Committee Meetings....... ~... ~...

Material Procurement Program Review ............,......

Quality Assurance/Quality Control (QA/QC) Subcommittee Meeting

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7.0

ADMINISTRATIVE~

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7.1

Backshift and Deep Backshift Inspection

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Exit Meetmgs

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DETAILS

1.0

PLANT OPERATIONS

1.1

Operational Experiences

The plant operated at approximately 97% power for most of the inspection period.

On

February 3, 1992, in response

to a load dispatcher's

request, power was reduced to permit

repair to an off-site sub-station.

Since a substantial power reduction was required, power

was further reduced to 47% to support plugging main condenser

tubes.

Upon completing

repairs, a power escalation began.

Coincident with increasing electrical load, the main

turbine tripped when the main generator lost excitation voltage.

In response,

operators

attempted to manually stabilize the plant at no-load conditions but a reactor trip occurred

when the "A" steam generator reached

the low-low level setpoint (17%).

Following

extensive evaluation to determine the cause for the turbine trip, the plant resumed full power

operations on February 10th.

On February 20, 1992, power was redqced to 48% in response

to main condenser

tube

leakage.

Five condenser

tubes were plugged and power was returned to 97% on February

22, 1992.

On February 29, 1992, an automatic shutdown of the "A" main feedwater pump occurred

due to low seal water differential pressure,

resulting in low-low (17%) "A" steam generator

water level and a subsequent

reactor trip. Following review of the trip and completion of

repairs, the plant was restarted

and full power reached

on March 3, 1992.

1.2

Control of Operations

Overall, the inspectors found the R. E. Ginna Nuclear Power plant to be operated safely.

Control room staffing was as required.

Operators exercised control over access

to the

control room.

Shift supervisors consistently maintained authority over activities and provided

detailed turnover briefings to relief crews.

The inspectors reviewed control room log books

for activities and trends, observed recorder traces for abnormalities,

assessed

compliance

with Technical Specifications, and audited selected safety-related

tagouts.

During normal

work hours and on backshifts, accessible

areas of the plant were toured.

No inadequacies

were identified.

1.3

Loss of Main Generator Excitation Voltage/Reactor Trip

Event Overview

During offsite power distribution system switchgear testing on February 3, 1992,

RGB'dentified

a problem with a main line transformer breaker at one of its off-site substations.

Work area isolation for corrective maintenance

on this breaker required deenergizing one of

Ginna's primary transmission circuits, which consequently limited station power output to

2

60%.

Operators commenced

a controlled power reduction at 10:45 AM to support the off-

site maintenance.

Since a significant power reduction was already required, station

management

reduced power to less than 50% to support plugging main condenser

tube leaks.

Due to small magnitude voltage oscillations experienced while adjusting voltage early in the

load reduction, operators placed the main generator voltage regulator in manual control.

This eliminated the voltage oscillation problem, and power was stabilized at 47% at

approximately 2:00 PM on February 3, 1992.

47% reactor power was selected based on

maximizing power production during the main condenser

maintenance,

while maintaining a

3% margin below the reactor protection system setpoint for an automatic reactor trip due to a

main turbine trip (P-9 permissive).

During this period of reduced power operation, the licensee conducted main turbine trip and

stop/intercept valve testing.

To prevent short-term variations in steam flow, as a result of

testing, from producing reactor power oscillations due to automatic rod motion, the rod

control system was placed in manual control for the duration of this testing.

I

At about 10:15 PM, the Control Operator (CO) made a routine small adjustment to main

generator voltage.

Preparations

were in progress to commence the last in the series of main

turbine tests when, at 10:20 PM, the "Generator Lockout Relay" annunciator energized.

This indicated that the main generator output breakers

had opened in response

to a loss of

generator excitation voltage and that the main turbine had tripped.

As anticipated, no reactor

trip occurred because power was less than the 50% turbine trip/reactor trip setpoint.

The

steam dump system actuated to reduce average reactor coolant system (RCS) temperature to

its no-load value of 547'F.

The steam generator water level control system fully opened the

feedwater regulating valves to raise steam generator water levels and ensure an adequate

heat

sink for the reactor.

Despite operator actions to manually coordinate power reduction, RCS

pressure control, and steam generator water level control, a reactor trip from 23% power

occurred at 10:25 PM when the "A" steam generator low-low water level trip setpoint (17%)

was reached.

Following the reactor trip, operators proceeded

to stabilize plant conditions in hot shutdown.

As RCS cooldown continued, an automatic feedwater header isolation occurred due to low

steam generator water level coincident with low RCS average temperature.

This in turn,

caused

an automatic startup of the auxiliary feedwater (AFW) system, including both motor

driven pumps and the steam turbine driven pump.

Although the system operated

as

designed,

operators noted rapid oscillations of 30 to 40 gpm in turbine driven AFW pump

flow. Since both motor driven AFW pumps were operating normally, the turbine driven

pump was shut down from the main control board (MCB) after approximately three minutes

of operation.

At 10:29 PM, in response

to lowering pressurizer level due to the continuing RCS cooldown,

the Head Control Operator shut the main steam isolation valves (MSIVs) as pressurizer level

reached 6%.

This action initially arrested

the cooldown at approximately 534'F and

pressurizer level began to increase due to charging pump operation and RCS heatup.

However, approximately

13 minutes later, operators noted that the RCS was again cooling

down at approximately 0.5'P/minute.

At that point, control room personnel noted that the

"A" MSIV was not fully seated

as indicated on the MCB. The Auxiliary Operator was

dispatched

to check the position of the "A" MSIV and reported that it was shut by local

valve position indication. At 10:52 PM, approximately 23 minutes after the control switch

had been placed in the "close" position, the "A" MSIV indicated shut by MCB indication.

At 11:15 PM, both steam generator atmospheric relief valves (ARVs) automatically opened

due to high steam generator pressure

as a result of the RCS heatup.

Primary plant conditions

were subsequently

stabilized at no-load temperature

using one motor driven AFW pump and

the ARVs for decay heat removal.

Corrective Actions

Anal

is of imulator Re ul

In an attempt to verify that operational guidance provided to operators for future operations

at just below 50% reactor power was adequate,

the training department used the plant

simulator to repeat the trip scenario with varying degrees of operator interaction.

Although

the results did not definitively identify an optimum mode of operation for avoiding a reactor

trip, they did support that automatic control modes for the rod control and feedwater

regulating valve control systems provided the greatest margin to reaching a trip setpoint.

Results of these simulator runs were disseminated

to operations personnel for information but

no procedure changes

were appropriate.

The inspector considered this effort to be a positive

initiative by the licensee, both in terms of attempting to identify vulnerabilities in the

response

to the actual trip, as well as in providing future operational guidance.

"A" M IV Slow

losure

With plant conditions stabilized in hot shutdown, the "A"MSIV was cycled several times to

verify its operability.

On the first three attempts, the valve rapidly (within a matter of

seconds) went to a nearly full shut position (as indicated by local position indication) and

then stopped.

On subsequent

cycles, the valve went fully shut in less than five seconds.

A similar slow closure of the "A" MSIV following a reactor trip occurred on September 26,

1990.

In response

to that event, the licensee performed an analysis of the adequacy of MSIV

operation.

The MSIVs are Atwood and Morrill30-inch swing check valves which employ an

air actuated piston for opening and a spring for closure.

Closure is also assisted by gravity

(the disc drops from a horizontal position to close) and, ifpresent,

steam flow from the

associated

steam generator.

In that analysis, RG&E concluded that frictional force developed

by the packing on the disc pivot may be sufficient to overcome the force of the closure

spring and prevent full closure under low- or no-flow conditions; however, they further

concluded that these valves would fully shut under design basis accident conditions, and

therefore functioned satisfactorily.

Details of the analysis are presented

in Inspection Report,

50-244/90-19.

Failure of the "A" MSIV to fully close during the September 26, 1990 event

was attributed to the combination of packing friction and low differential pressure

across the

disc; its ultimate closure was attributed to increased differential pressure which resulted when

steam to the turbine driven auxiliary feedwater pump (which taps off upstream of the MSIV)

was secured.

Slow closure of the "A" MSIV during the February 3rd trip was similarly

attributed to the combination of packing friction and low differential pressure.

In response

to the past slow closure experienced

on September 26, 1990, the licensee

committed to performing several actions to evaluate and improve MSIV performance.

During the 1991 refueling outage, many of these items were completed with some scheduled

to be performed during future outages.

During the 1992 refueling outage, the "A" MSIV

will undergo a major inspection and both valves willbe repacked with a different type of

packing material in an attempt to reduce packing friction. In accordance with Technical Specification 4.7, MSIVs are tested during each refueling outage under no flow and at no

load conditions, to verify that they close upon signal within five seconds.

Through review of

test records,

the inspectors confirmed that the valve met this criteria.

Since at power

conditions affected valve performance,

(he inspectors willcontinue to follow licensee efforts

to improve MSIV performance

as an unresolved item that requires further review and

evaluation (50-244/92-02-01).

Turbine Driven Auxilia

F

water P m

On February 4, 1992, the turbine driven auxiliary feedwater pump was started in accordance

with the monthly performance test procedure (PT-16M-T) in an attempt to identify the source

of the flow oscillations that occurred following the reactor trip. Upon startup, significant

steam leakage was observed in the area of the throttle block.

Subsequent

investigation

revealed the source to be the seating surface between the throttle block and the turbine

casing.

The pump had been considered operable until this point because,

in spite of the flow

oscillations, it was still capable of delivering flow in excess of the technical specification

requirement.

Repair of the throttle block steam leak, however, made the pump inoperable

and placed the licensee in a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> technical specification action statement.

The throttle

block was removed and the gasket replaced.

This eliminated the steam leak, however, rapid

flow oscillations were still present when the pump was again started.

Pump operation was

recorded on video tape; subsequent

evaluation of this record revealed the cause of the

oscillations to be a loose linkage in the throttle mechanism.

Specifically, a stop nut on a

threaded rod had worked loose, thereby allowing for travel within the linkage.

The linkage

was tightened and operational testing was completed satisfactorily.

The pump was declared

operable on the afternoon of February 4, 1992.

As interim corrective action for the loose stop nut, the licensee instituted a four-hour

verification of its position.

Permanent corrective action to lock the position of the stop nut is

being developed.

Main

enerat r Volta e Re ulat r

RG&E undertook a thorough examination of the main generator voltage regulating system.

This troubleshooting involved both static and operational testing, and was extensively

supported by corporate engineering,

as well as the vendor and an independent

test laboratory.

All other trip-related plant deficiencies had been satisfactorily addressed

by the afternoon of

February 5. While voltage regulator troubleshooting continued, a reactor startup was

conducted on the evening of February 5.

Power escalation was halted at approximately 2%

rated thermal power, pending resolution of the main generator voltage regulator problem.

By the afternoon of February 6, 1992, shutdown troubleshooting was completed.

However,

despite a comprehensive effort, no single cause had been identified for the loss of generator

excitation.

A plan was developed to return to power operation without the voltage regulator

problem identified.

This plan included:

system monitoring at key points in the circuitry

using chart recorders to provide both real-time and historic information; continuous electrical

engineering support for the operations department; hold points during power ascension

for

evaluation of system performance;

and specific instructions to operations personnel regarding

actions to be taken for malfunction or failure of the voltage regulator.

Startup and Power Ascension

A reactor startup was commenced

on the evening of February 5, 1992.

The inspectors

observed portions of the reactor startup, conducted in accordance with Operations Procedure

0-1.2, "Plant Startup from Hot Shutdown to Full Load," revision no. 110, effective

December

12, 1991.

Operations were generally well controlled, and clear, concise

communications between supervisors and operators were observed.

On one occasion,

a

.

procedural step sequence

deficiency was encountered

which stopped operations until a

procedure change was processed.

Criticality was achieved at 10:55 PM on February 5, 1992.

Power was increased

to

approximately 2% and then stabilized for improvement in steam generator water chemistry.

The main generator was closed on the grid at 10:04 PM on February 6, 1992.

No

abnormalities were noted during main generator operations with manual control of the

voltage regulator.

When voltage regulation was shifted to automatic, small magnitude

voltage oscillations were immediately evident.

Voltage regulation was promptly returned to

manual control.

On the recommendation of the Westinghouse representative,

an adjustment

was made to the automatic voltage regulator damping circuit. This eliminated the voltage

oscillation problem, and power escalation to 30% commenced at 12:03 AM on February 7,

1992.

Upon achieving steam generator water chemistry specifications, power escalation

resumed and full power was achieved at 7:50 PM, February 10, 1992.

There were no

further problems with main generator voltage regulation during the remainder of the

inspection period.

The augmented monitoring of voltage regulator components

remains in

place.

Cl

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1.4

Reactor Trip Resulting From Loss of "A"Main Feedwater Pump

During operations at approximately full power on February 29, an automatic shutdown of the

"A" Main Feedwater (MFW) pump occurred due to low seal water differential pressure

(d/p).

Operators responded by manually reducing turbine load and starting all auxiliary

feedwater pumps.

Rod control and feedwater control systems were in automatic at the onset

of the transient and remained so throughout.

In spite of prompt, correct operator actions, the

reactor tripped at 1:46 PM, approximately two minutes after loss of the MFW pump, due to

low level (17%) in the "B" steam generator.

Following the reactor trip, operators stabilized the plant in hot shutdown.

The MSIVs were

subsequently

closed to control RCS cooldown; both valves were fully closed within seconds

of the close order.

The extensive RCS cooldown caused by the reactor trip from high

power, combined with the rapid introduction of feedwater, resulted in a decrease

in

pressurizer level below the indicating range.

The pressurizer did not fully drain, as indicated

by reactor vessel water level indicating system (RVLIS) remaining at 100% and no step

decrease

occurring in RCS pressure

(both of which would indicate steam bubble formation in

the reactor vessel).

Pressurizer

level indication was regained after approximately five

minutes as a result of RCS heatup and charging pump operation.

The minimum RCS

pressure during the transient was approximately 20 psig above the automatic engineered

safeguards

features actuation setpoint of 1750 psig.

The inspector was in the main control room at the time of the reactor trip. The response of

the control room operators

was observed to be highly professional.

In light of the slow

closure of the "A" MSIV on February 3, 1992, the inspector also verified, by local position

indication, prompt closure on this occurrence.

The inspector noted no procedural or

performance deficiencies during response

to the transient and transition to operations in hot

shutdown.

The cause of the main feedwater pump trip was found to be a buildup of corrosion products

in the seal water d/p switch high pressure

sensing line, combined with leakage from an

associated

compression fitting; this flow restriction and leak path caused the high pressure

side of the d/p switch to depressurize,

producing the alarm and trip.

Corrective action

included blowing down the high and low pressure

sensing lines, replacing leaking

compression fitting and associated

tubing, and replacing the d/p switch.

In addition, the "B"

MFP seal water d/p switch sensing lines were blown down and proper switch calibration was

verified. A contributor to the reactor trip was the fact that the delay time between receipt of

the low seal water d/p alarm and the MFP trip was only five seconds.

This problem had

been previously addressed

before the trip occurred, and a modification to extend the time

interval to one minute had been approved for accomplishment during the upcoming refueling

outage.

As a result of this trip, the modification was completed prior to resuming full power

operations.

8

7

Startup commenced

at 3:32 AM on March 1, 1992 and criticality was achieved at 5:18 AM.

No significant difficulties were encountered

during the startup and power ascension.

Operations at approximately full power were resumed on March 3, 1992.

2.0

RADIOLOGICALCONTROLS

2.1

Routine Observations

The inspectors periodically confirmed that radiation work permits were effectively

implemented, dosimetry was correctly worn in controlled areas and dosimeter readings were

accurately recorded,

access

to high radiation areas was adequately controlled, and postings

and labeling were in compliance with procedures

and regulations.

Through observations of

ongoing activities and discussions with plant personnel,

the inspectors concluded that

radiological controls were conscientiously implemented.

No inadequacies

were identified.

2.2

Radioactive Material Release Accountability for Unmonitored Discharge Paths

4

Following the reactor trip of February 3, increasing iodine concentrations in RCS coolant

samples indicated that some small fuel rod cladding leakage had developed.

Although small

in magnitude, the inspector was concerned that accurate radioactivity release estimates were

being made, since known steam generator (SG) tube leakage existed (approximately 60 cubic

centimeters/minute

total) and normal decay heat removal was by discharging steam through

the SG atmospheric relief valves, which is an unmonitored release path.

The licensee

responded by developing a release estimate.

The inspector determined that radioactivity

release estimates for routine unmonitored steam releases

are not routinely performed.

This

will remain an open item pending evaluation of the licensee's actions to address

this concern

(50-244/92-02-02).

3.0

MAINTENANCE/SURVEILLANCE

3.1

Corrective Maintenance

3.1.1

Main Condenser Circulating Water Tube Leaks

At 12:10 AM on February 20, 1992, a main condenser circulating water tube leak developed

in the 1B2 water box.

The first indication that a leak had developed was an annunciator

alarm for the all-volatile treatment (AVT) system, which indicated high condensate

conductivity.

Chemical analysis confirmed that elevated sodium concentrations

existed in the

"B" condenser hotwell and both steam generators.

From the relative concentrations of ionic

impurities and sample point locations, further analyses indicated the source of contamination

to be lake water leaking into the 1B2 water box.

Steady-state impurity concentrations

indicated that the leakage rate was approximately 30 gallons per minute.

Although the

condensate

polishing demineralizers removed most of the ionic impurities, they were not

designed to accommodate

a leak of this magnitude.

A 10%/hr power reduction was commenced at 1:38 AM to support placing the "B"

condenser out of service for repairs to the 1B2 water box.

The rate of power reduction was

subsequently

reduced because

the boric acid addition rate was limited by in-progress

maintenance

on the chemical and volume control system (CVCS). Normal letdown was taken

out of service the previous day to support a valve replacement.

A smaller capacity, excess

letdown. system,

was in operation.

Power was stabilized at 45% at approximately 8:30 AM.

The licensee held a management

meeting at 8:30 AM to establish an integrated plan for

maintenance

on the condenser waterbox, the CVCS valve replacement,

and any related

corrective maintenance.

As a result of this meeting, the scope of maintenance activities were

clearly defined, priorities were established,

and management

responsibility for specific

actions associated

with each maintenance action were positively identified.

The inspector

considered this to be a positive management initiative which had resulted from PORC

discussions of lessons learned from the February 3, 1992 forced outage.

Due to the large size of the circulating water leak, the licensee gave extensive consideration

to the possibility that increased

backpressure

due to air leakage into the condenser

once the

waterbox was drained might require the main turbine to be tripped.

As a result, isolation

and draining of the 1B2 waterbox was well planned and closely monitored.

Backpressure

remained sufficiently low to allow continued turbine operation throughout the waterbox

maintenance,

and close management

involvement allowed immediate resolution of operational

concerns which could otherwise have resulted in a turbine trip.

Corrective Actions

A variety of techniques were used to identify leaking circulating water tubes in the 1B2

waterbox.

Infrared thermography was used on initial waterbox entry and was successful in

identifying two leaking tubes.

Use of thermography for identification of tube leaks was a

new technique; although initially successful, difficultywas encountered with condensation

on

the camera lens due to high humidity in the waterbox.

One tube leak was identified by

covering the tube sheets with plastic wrap; condenser vacuum translated through the leak

caused

the plastic wrap over the leaking tube to rupture.

Two additional leaks were

identified and plugged, one using the helium tracer gas technique, and the other during eddy

current inspection of tubes adjacent the leaking tubes.

There was no obvious pattern to the leaking tubes, such as would be expected ifthe cause

had been mechanical impingement.

RG&E concluded that one of the leaking tubes was

probably the major contributor and had failed suddenly; the other four were minor

contributors and had existed prior to the problem.

The cause of the failures could not be

conclusively determined,

although tube vibration was considered likely,

Other corrective maintenance

observed by the inspector during the period of reduced power

operation included replacement of the CVCS nonregenerative

heat exchanger inlet drain valve

(2232) (Work Order No. 9122368).

Through attendance

at the pre-job briefing, review of

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work package documentation,

and observation of craft activities, the inspector concluded that

this maintenance

was properly controlled with good coordination between the working groups

involved.

3.1.2

Nuclear Instrument Power Mismatch Bypass Switch Replacement

On January 28, 1992, the inspector observed corrective maintenance performed on the

nuclear instrument system (NIS) power mismatch bypass switch for nuclear instruments N-41

and N-43.

The switch was replaced because it was causing erratic signals from the nuclear

instruments to the automatic rod control system.

This deficiency was identified during

troubleshooting of an intermittent problem with the rod control system,

as discussed

in

inspection report 50-244/91-29.

Overall, the maintenance activity was performed effectively. The technician's

communications

and conduct were formal and professional.

Appropriate test equipment and

tools were staged and readily available.

The inspector verified that test equipment was

calibrated, administrative approvals were obtained prior to starting work, quality control hold

points were established

and implemented,

the replacement

switch was properly certified and

controlled, and technical specification requirements were not violated by this evolution.

Control room operators were informed and cognizant of the maintenance activity.

The briefing which was conducted prior to the start of the maintenance activity was

constructive.

Good interactions were noted among the personnel involved.

As a result of

this briefing, several enhancements

to the procedures

were identified, including clarification

of Quality Control (QC) verification requirements in TSR No.92-019, "NIS Power

Mismatch Bypass Switch Replacement,"

more detailed work step descriptions,

and addition

of a work step to ensure residual voltages were eliminated to prevent incorrect readings..

These procedural changes

and clarifiications were appropriately reviewed and implemented

through a Procedure Change Notice, PCN 92T-0045.

During the maintenance activity, the inspector noted an inconsistency between the

maintenance procedure, M-57.5, "Replacement of NIS Power Mismatch Bypass Switch," and

the corporate engineering procedure, EE-35, which provides specifications for soldering

activities including material specifications for consumable items.

Although the QC procedure

used during the maintenance activity referenced Procedure EE-35, no material specifications

for the solder and flux were included in the maintenance procedure.

No procurement

tracking or control of soldering materials was noted.

Through interviews with licensee

personnel, it was identified that the flux had a one year shelf life, yet flux had not been

ordered through material procurement for several years.

In discussions with Material Procurement personnel,

the lack of solder specifications in the

plant's procurement process

had been identified approximately three weeks prior to the

maintenance activity. The material specification was being developed at the time of the

maintenance activity and has since been completed.

The licensee determined that the solder

Cl

10

used during the maintenance activity conformed to the specification and was acceptable.

Based on the fact that flux does not become a permanent component of soldered joints and

that soldered joints are inspected prior to acceptance,

the licensee concluded that material

specifications for flux were not necessary.

The licensee stated, however, that the flux would

be controlled through their consumable program to ensure that the shelf life is not exceeded.

The pre-job briefing and discussions were thorough and effective.

During this briefing,

participants identified enhancements

to the maintenance procedures

and followed the

appropriate procedural guidelines to implement the changes.

Inconsistency,

however, was

noted in material specifications and acceptance

criteria during the soldering portions of the

evolution (refer to section 6.5).

These inconsistencies

were appropriately addressed

by the

licensee.

3.2

Surveillance Observations

Inspectors observed portions of surveillances to verify proper calibration of test

instrumentation,

use of approved procedures,

performance of work by qualified personnel,

conformance to Limiting Conditions for Operation (LCOs), and correct system restoration

following testing.

The following surveillance was observed:

Periodic Test (PT) 9.1.17, Undervoltage Protection - 480 Volt Safeguard Bus 17,

revision 2, effective date December

10, 1991, observed on February 12, 1992.

No unacceptable

conditions were identified.

4.0

SECURITY

4.1

Routine Observations

During this inspection period, the resident inspectors verified that x-ray machines and metal

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

maintained, personnel were properly badged for unescorted or escorted

access,

and

compensatory

measures

were implemented when necessary.

Site modifications are in

progress to upgrade site security systems.

No unacceptable

conditions were identified.

5.0

ENGINEERING/TECHNICALSUPPORT

5.1

Service Water System Operational Performance Inspection (50-244/91-201)

During the period from December 2nd through December 20th, 1991, a Service Water

System Operational Performance Inspection was conducted by the Special Inspection Branch

of the Office of Nuclear Reactor Regulation.

The results of this effort were documented

in

'

11

Inspection Report 50-244/91-201.

Based on a review of the report by the NRC staff, several

items were identified as violations of NRC requirements.

Details of these findings are

provided in Appendix A. In summary, the violations are:

1.

Design reports, calculations, and analyses were not properly controlled, verified, and

accepted

as required by 10 CFR 50, Appendix B, Criterion III, "Design Control"

(50-244/91-201-01).

2.

The Final Safety Analysis Report was not accurately updated to reflect the actual

service water system configuration as required by 10 CFR 50.34(b) and 10 CFR 50.71(e) (50-244/91-201-11).

3.

Pre-operational

test results were not reviewed to compare current system operation

and configuration to the original design basis as required by 10 CFR 50, Appendix B,

Criterion III, "Design Control," and Criterion XI, "Test Control" (50-244/91-201-14).

Additionally, the following items are considered

unresolved pending further staff review to

ascertain whether each is an acceptable item, a deviation, or a violation:

Reanalysis of the service water system hydraulic model and application of its results

~

~

to the system (50-244/91-201-02).

Evaluation of the safety classification of the "A" spent fuel pool heat exchanger

(50-244/91-201-04).

Assessment of the single failure of a service water pump discharge check valve

(50-244/91-201-07).

Establishment of the appropriate service water system low pressure setpoint

(50-244/91-201-12).

Evaluation of the controls to assure that redundant equipment willnot be taken out of

service while companion equipment is undergoing surveillance testing (50-244/91-201-

15).

The staff acknowledges

actions of RG&E to include other weaknesses

and areas for

improvement identified in Inspection Report 50-244/91-201 into the RG&E Commitment and

Action Tracking System to assure formal resolution of these matters.

Regarding the inclusion of the appropriate number of operable service water pumps in the

Ginna Technical Specifications, it is the NRC staff's understanding

that an analysis will be

submitted for NRC staff review.

Pending staff review of this analysis,

an interim

administrative control has been established by RG&E requiring that three (3) service water

pumps be operable and, ifless than three pumps are operable, a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> limiting condition

12

for operation would be entered until a third service water pump is restored to operable status,

or the reactor will be placed in hot shutdown within the next six hours and in cold shutdown

in the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

RG&E's progress in addressing

these issues willbe evaluated in future NRC inspections.

6.0

SAFETY ASSESSMENT/QUALITY VERIFICATION

6.1

Licensee Action on Previous Inspection Findings

6.1.1

(Closed) Unresolved Item (50-244/90-31-03) Implementation of Long Term

Corrective Actions

This item remained open pending the implementation of long term corrective actions taken in

response

to the temporary disabling of Engineered

Safeguard Features instrumentation in

December

1990.

In response

to the violation, RG&E itemized 29 long term actions that

would be taken to prevent recurrence.

'through review of relevant documentation and

discussions with licensee representatives,

the inspector determined that these items are being

appropriately addressed.

As a final action, the licensee's Nuclear Safety Audit and Review

Board will meet on March 10-11, 1992, and perform a review of the effectiveness of these

corrective actions.

The inspectors had no further concerns on this matter.

6.1.2

(Closed) Unresolved Item (50-244/89-80-06) Evaluation of Site Contingency

Procedures

Related to Fire Fighting

This item remained open pending the establishment of an action plan to delete fire fighting

plans and strategies from site contingency procedures

and reformat this information.

Through discussions with the site fire protection engineer and review of relevant

documentation,

the inspector determined that an action plan has been developed.

Fire

brigade site contingency procedures

are now going to be incorporated into a fire response

plan.

In order to ensure consistencies

in the fire response plan and address configuration

management

considerations,

a fire response plan task management

manual is being drafted.

This manual willprovide the technical basis of the fire response plan, the plan task

description, a writing and drafting guide, and a milestone schedule.

Full development is

scheduled for completion by December 31, 1992.

The inspectors had no further questions on

this item.

6.2

Periodic Reports

Periodic reports submitted by the licensee pursuant to Technical Specification 6.9.1 were

reviewed.

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

that test results and/or supporting information were consistent with design predictions and

performance specifications,

and that reported information was accurate.

The following

reports were reviewed:

8

13

Monthly Operating Reports for January

1992

Semiannual Radioactive Effluent Release Report (July - December,

1991)

No unacceptable

conditions were identified.

6.3

Licensee Event Reports (LERs)

LERs submitted to the NRC were reviewed to determine whether details were clearly

reported, causes were properly identified, and corrective actions were appropriate.

The

inspectors also assessed

whether potential safety consequences

were properly evaluated,

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

requirements of 10 CFR 50.72 were met.

The following LERs were reviewed (Note: date indicated is event date):

92-001

Component Failure in Containment Radiation Monitor Causes

Containment

Ventilation Isolation (January 5, 1992)92-002

Feedwater Transient, due to Loss of Main Generator Excitation Induced

Turbine/Generator Trip, Causes Low-Low Steam Generator Level Reactor

Trip (February 3, 1992)

The inspector concluded that the LERs were accurate and met regulatory requirements.

No

unacceptable

conditions were identified.

6.4

Plant Operations Review Committee Meetings

On January 29, 1992, the inspector observed a scheduled Plant Operational Review

Committee (PORC) meeting.

Areas reviewed included plant operations events,

modifications, procedure changes,

corrective action reports, and limiting conditions for

operations.

The PORC adequately

met the intent and purpose of the meeting.

The technical specification

requirements for an adequate quorum and items for review were satisfied.

Thorough reviews were noted during the meeting.

For example, discussions

on a main

feedwater pump room ventilation problem were thorough.

Although the PORC recognized

that this was a non safety-related equipment, they nonetheless

determined that it was

necessary

to track the issue in the corrective action report to ensure that a related issue of

nuisance alarms for control room operators

as well as the problem itself were resolved.

The

PORC demonstrated

its commitment to address problems from a safety focus rather than

strictly a compliance focus.

14

The inspector also observed

a scheduled PORC meeting on February 13, 1992, and PORC

post-trip reviews on February 5 and 29, 1992.

6.5

Material Procurement Program Review

As a result of some inconsistencies

noted during a maintenance activity in the material

specifications for soldering material (Section 3.1.2), the inspector reviewed the plant's

material procurement area to determine ifthese inconsistencies

reflected a programmatic

weakness.

The licensee is in the process of revising and improving their program.

This effort has

included development of commercial dedication specifications for safety-related

components,

controls for consumable items, and consistency between Plant Material Procurement,

Corporate Engineering, and Construction requirements.

The licensee has completed a

significant portion of the component specifications for commercial items.

Two commercial

grade dedication plans, Crane Valve Co. gate valves (Evaluation No.91-057) and globe

valves (Evaluation No.91-087), were reviewed and determined to be thorough.

These

dedication plans included detailed critical parameters for the components

as well as the bases

for these parameters.

The licensee has prioritized the importance of each component, and is

continuing to develop specifications,

as well as identifying additional components which may

require specifications; an example is the solder material described in Section 3.1.2 of this

report.

At the end of the inspection period, the specifications for solder had been completed.

II

The licensee has prioritized and made good progress in the control of consumable items and

the items maintained by other plant work groups.

For example, the solid state drawers,

modules, and power supplies which are kept by the Instrument and Controls (1&C) group

have been controlled by Maintenance Procedure M-71.2, "Module Rework/Test Procedure."

The procedure requires that these modules cannot be placed into operation unless Quality

Control has accepted

the material.

Most consumable items have been returned to the stock

room for control.

The oversight of the soldering flux was partially attributed to review of

material in the I&C shop.

All shops, however, had been reviewed.

The Material

Procurement group intends to review all items in the I&C shop which should address

any

other potential deficiencies.

The licensee has recognized that the procurement specification and processes

between the

plant and Corporate Engineering and Construction have inconsistencies,

Efforts are

continuing to identify the inconsistencies

and develop resolution for inconsistencies.

Overall, the licensee has made significant progress and improvements in the material

procurement area.

The order of problems to be addressed

appears

to be properly prioritized

and weaknesses

in the program have been identified and are appropriately being addressed.

Deficiencies identified with the solder material did not indicate a programmatic problem.

15

6.6

Quality Assurance/Quality Control (QA/QC) Subcommittee Meeting

On January 29, 1992, the inspector attended the quarterly meeting of the RG&E corporate

QA/QC subcommittee.

The inspector observed that the meeting was well attended by plant

and corporate management.

Discussions were open and candid on the nature and status of

audit findings, with good participation by all members.

The inspector had no questions on

these matters.

7.0

ADMPGSTRATIVE

7.1

Backshift and Deep Backshift Inspection

During this inspection period, backshift inspection was conducted on February 5, 1992.

Deep backshift inspections were conducted on the following dates:

January 25, February

17,

23, 29, and March 1, 1992.

7.2

Exit Meetings

At periodic intervals and at the conclusion of the inspection, meetings were held with senior

station management

to discuss the scope and findings of this inspection.

The exit meeting for

inspection report 50-244/92-02 was held on March 13, 1992 with the following individuals

attending:

Name

Title

Thomas Moslak

Edward Knutson

Robert Mecredy

Joe Widay

Thomas Marlow

Richard Marchionda

Andy Harhay

Steve Adams

Paul Gorski

Clair Edgar

. Paul Wilkens

Mike Lilley

Jeff Wayland

Ron Jaquin

Matt Clark

Terry White

Jack St. Martin

Tom Harding

Tom Plantz

Fred Mis

Don Filion

Sr Resident Inspector-NRC

Resident Inspector-NRC

Vice President,

Ginna Nuclear Production-RG&E

Plant Manager-RG&E

Superintendent,

Ginna Production-RG&E

Superintendent,

Support Services-RG&E

Mgr. HP & Chemistry-RG&E

Mgr. Technical Services-RG&E

Mgr. Mech. Maintenance-RG&E

Mgr. Electrical Maintenance/I&C-RG&E

Mgr. Nuclear Engineering Services-RG&E

Mgr. Nuclear Assurance-RG&E

Reactor Engineer-RG&E

NS&LEngineer-RG&E

NS&LEngineer-RG&E

Operations-RG&E

Corrective Action Coordinator-RG&E

Modification Support Coordinator-RG&E

Planning and Scheduling-RG&E

Health Physicist-RG&E

Radiochemist-RG&E