ML17262A960

Insp Rept 50-244/92-09 on 920527-0720.No Violations Noted. Major Areas Inspected:Plant Operations,Radiological Controls,Maint/Surveillance,Security,Emergency Preparedness, Engineering/Technical Support & Safety Assessment

ML17262A960
Person / Time
Site:	Ginna
Issue date:	08/14/1992
From:	Lazarus W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML17262A959	List: ML17262A958 ML17262A960
References
50-244-92-09, 50-244-92-9, NUDOCS 9208250074
Download: ML17262A960 (28)

See also: IR 05000244/1992009

Text

U. S. NUCLEAR REGULATORY COMVHSSION

REGION I

Inspection Report 50-244/92-09

License: DPR-18

Facility:

R. E. Ginna Nuclear Power Plant

Rochester Gas and Electric Corporation (RG&E)

Inspection:

Inspectors:

May 27 through July 20, 1992

T. A. Moslak, Senior Resident Inspector, Ginna

E. C. Knutson, Resident Inspector, Ginna

H. Kaplan, Senior Reactor Engineer, Region I

A. Loh ', Senior Reactor Engineer, Region I

Approved by:

W.

s, Chief, Reactor Projects Section 3B

INSPECTION SCOPE

Date

Plant operations, radiological controls, maintenance/surveillance,

security, emergency

preparedness,

engineering/technical

support, and safety assessment/quality

verification.

INSPECTION OVERVIEW

Oy

y

'Mly&

Ip

dMlyllMU*pl

hot shutdown condition following the rupture of a preseparator drain tank.

RG&E

management's

verification that auxiliary operator logkeeping records were accurately

maintained was limited in scope and depth.

dchldl

1: Rd 'vp

i 'yi pl

H

d

personnel exposure was minimized during the transfer of spent resin.

Mainten nce/ urveillance:

Corrective maintenance

was expeditiously performed on a service

water leak in a containment air cooler.

~ecurit:

Site security is provided appropriate coverage to support on-going upgrades to

perimeter security systems.

Emer enc

Pr

redn:

A simulator-driven mini-drillwas carried out in preparation for

the annual exercise.

En ineerin /Techni

1

u

rt; Limitations were identified in the engineering process that

controlled the temporary repairs made to a ruptured preseparator

drain tank.

Safet

A sessment/

lit V rifi ti n:

Senior corporate management

was provided a

detailed briefing by the Quality Performance Department on the status of findings identified

by internal/external organizations.

9208250074

920814

PDR

ADOCK 05000244

8

PDR

TABLEOF CONTENTS

OVERVIEW

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TABLE OF CONTENTS.................................

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1.0

PLANT OPERATIONS (71707) ...................

1.1

Operational Experiences....................

1.2

Control of Operations .....................

1.3

Inspection of Plant Operator Activities (RI TI 92-01) ..

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2.0

RADIOLOGICALCONTROLS (71707)

2.1

Routine Observations

2.2

Primary Deionizing Resin Disposal..............

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3.0

MAINTENANCE/SURVEILLANCE(62703, 61726)

3.1

Corrective Maintenance.........................

3.1.1

"A" Steam Generator Wide Range Level Detector Sensing

Leak

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3.1.2

"C" Containment Recirculation Fan Cooling Water Leak

3.2

Surveillance Observations........................

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Security (71707)

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4.1

Routine Observations .... ~............ ~..............

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5.0

EMERGENCY PREPAREDNESS (71707) ............... ~.......

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5.1

Simulator-Driven Mini-Drill...... ~.....................

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6.0

ENGINEERING/TECHNICALSUPPORT (71707, 92701)...........

6.1

"A" Preseparator

Drain Tank Rupture ...................

6.1.1

Event Description ...........................

6.1.2

Equipment Description ........................

6.1.3

Licensee Response

6.1.4

Inspector Findings........

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Feedwater Flow Oscillations .........................

Licensee Action on Previous Inspection Findings

6.3.1

(Closed) Unresolved Item (50-244/90-10-02) Licensee to verify

separation of AMSAC Cable Run in Cable Tray No. 372 from

Cable Tray No. 23.

6.4

Erosion/Corrosion (E/C) Integrated Management Team Meeting

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Table of Contents

7.0

SAFETY ASSESSMENT/QUALITY VERIFICATION(71707, 90712, 90713,

92701, 40500) .............,, ......................

7..1

Periodic Reports

7.2.

Licensee Event Reports (LERs) and Special Report

7.3

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

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8.0

ADMINISTRATIVE(71707, 30702, 94600)

8.1

Backshift and Deep Backshift Inspection...............

8.~2

Exit Meetings

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DETAILS

1.0

PLANT OPERATIONS (71707)

1.1

Operational Experiences

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

On June

9, 1992, the plant was taken off-line and the reactor placed in hot shutdown to support

repairs to a ruptured preseparator

drain tank.

The "A" preseparator

drain tank had failed as a

result of steam impingement on the tank wall. With repairs completed,

the plant was

restarted on June 11, 1992.

Power operations continued through July 2, 1992 at which time

power was reduced to about 74% to support repairs to an off-site transmission substation.

1.2

Control of Operations

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

The control room was staffed as required,

Operators exercised appropriate control over

access to the control room.

Shift supervisors consistently maintained authority over activities

and provided detailed turnover briefings to relief crews.

Power reduction and escalation were

well controlled.

Operators adhered to approved procedures

and understood the reasons for

lighted annunciators.

The inspectors reviewed control room log books for activities and

trends, observed recorder traces for abnormalities,

assessed

compliance with Technical

Specifications, and verified that equipment availability was consistent with the requirements

for existing plant conditions.

During normal work hours and on backshifts, accessible

areas

of the plant were toured.

No inadequacies

were identified.

1.3

Inspection of Plant Operator Activities (RI TI 92-01)

In response to NRC Information Notice 92-30, "Falsification of Plant Records," licensee site

operations management

conducted a selective review of plant records.

The review was

limited to examining security computer vital area entry/exit data compiled during a one week

period in February 1992.

This review was to verify that unlicensed auxiliary operators were

present in various vital areas, indicating that the operators were performing their assigned

duties.

Site management

found no evidence that operators were not making the appointed

rounds for the period examined.

Through examination of the review process and discussions with site management,

the

inspector concluded that the review was too limited in scope and depth to accurately assess if

all auxiliary operators were conscientiously performing their assigned duties, since individuals

not on site during the review period were not subject to this verification. Additionally, due

to the narrow scope of the review, site management

could not determine whether plant logs

and records were accurately maintained by the individuals entering vital areas during that

period.

Site management

acknowledged the inspector's concerns regarding the inadequacy of this

review.

Management stated that additional attention willbe given this matter, including

integrating other departments into the verification process.

To date, no firm action plan with

implementation dates for a comprehensive self-monitoring program has been established.

As an independent check of auxiliary operator performance,

the inspector accompanied

an

unlicensed operator during the conduct of a set of rounds.

Prior to conducting this tour, the

inspector reviewed applicable operating procedures/technical

specifications and interviewed

plant operations management

on their staff expectations.

Through this spot checking, the

inspector did not identify inconsistencies in the completeness or accuracy of recorded data.

Additional inspection of auxiliary operator on-watch practices by the resident staff will

continue.

2.0

RADIOLOGICALCONTROLS (71707)

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

Primary Deionizing Resin Disposal

On June 3, 1992, the inspector observed the transfer of spent charging and volume control

system deionizing resin to a shipping cask in preparation for transport for disposal.

The resin

transfer was performed in accordance with the licensee's radioactive discharge (RD)

procedure, RD-10.14, "Handling, Loading and Unloading of Chem-Nuclear 8-120A or B(U)

Transport Cask."

The inspector noted no procedural or operational deficiencies during the

conduct of the discharge.

The inspector also reviewed the ALARApackage (ALARA

number 920105) and associated

special work permits and noted no deficiencies.

Contact and

area radiation levels were appropriately monitored, as was local airborne radioactivity.

There

were no unexpected radiation levels or uncontrolled releases of radioactive materials

associated with the transfer.

3.0

MAINTENANCE/SURVEILLANCE(62703, 61726}

3.1

Corrective Maintenance

3.1

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"A" Steam Generator Wide Range Level Detector Sensing Line Leak

While observing the containment video monitor on June 23, 1992, the Shift Technical

Advisor noted steam/water leakage from a small diameter pipe in the vicinityof the "A"

reactor coolant pump.

Based on plant arrangement drawings and operator knowledge, the

leaking line was tentatively identified as either the "A" steam generator (SG) wide range level

detector variable leg sensing line, or the "A" SG bottom blowdown sample line. Normal

containment process and radiation monitor levels further supported that the leak was from a

secondary plant system rather than reactor coolant system leakage.

Operators entered

containment later that day to positively identify the source of the leak.

Although successful

in confirming that it was secondary

system leakage, operators were not able to identify the

exact source; the label on the valve closest to the leak (from a compression fitting) was not

legible, and the high area radiation field (approximately 40 rem per hour) precluded

conducting a detailed walkdown.

The operator tightened the fitting and temporarily stopped

the leak.

However, the fitting resumed leaking within several hours.

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The following day, the licensee developed a plan to positively identify the location of the leak

within the "A" SG system and to attempt further repair.

From position information gained in

the previous day's attempt, operators considered that the leak was most likely from the wide

range level detector.

To verify this, the wide range level detector would first be equalized

and isolated, thus cutting offpressure to one side of the leak; the leak would then stop once

the adjacent isolation valve was closed.

The operator who had tightened the fitting had used

only sufficient torque to stop the leak, and thought that additional tightening was possible.

Therefore, the first attempt at repair would be to further tighten the fitting. Ifthis was

effective in stopping the leak, as demonstrated by zero leakage for approximately one day

with the adjacent isolation valve open, the repair would be considered successful and the level

detector would be placed back in service.

The leak was found to be from the "A" SG wide range level detector sensing line, and

tightening the fitting stopped the leak.

The inspector concluded that the licensee's actions to

identify and correct the problem were conservative and well planned.

The inspector had no

further concerns on this matter.

3.1.2

"C" Containment Recirculation Fan Cooling Water Leak

On the afternoon of July 2, 1992, operators observed a 55% increase in automatic pumpdown

frequency of the "A" containment sump.

This translated to an increased inflow to the sump

of approximately 0.25 gallons per minute.

Based on the fact that routine monthly service

water system testing had been completed several hours earlier, operators immediately

suspected

the source to be a service water leak from one of the four containment fan coolers.

Operators entered containment that evening and identified the source of leakage to be a

service water heat exchanger leak on the "C" containment recirculation fan cooler unit.

Technical specification action statement 3.3.2.2.a allows one recirculation fan cooler unit to

be inoperable for a period of no more than seven days.

This action statement was entered at

8:10 PM, July 2, 1992, when service water to the unit was isolated to stop the leak.

An attempt was made to repair the pinhole leak in the fan cooler unit heat exchanger by

brazing.

When this was unsuccessful,

the tube was cut and plugged.

Although this stopped

the original leak, a second leak had developed from an adjacent tube, apparently due to its

close proximity to the repair area.

Following the successful braze repair of the second leak,

the access panel was reinstalled with a gasket seal.

The "C" recirculation fan cooler unit was

declared operable on July 7, 1992.

The inspector assessed

that the actions to repair the "C" recirculation fan cooler unit were

proper.

NRC notification of the service water leak in containment was made within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />

as required by IE Bulletin No. 80-24, "Prevention of Damage Due to Water Leakage Inside

Containment."

Management attention and use of overtime through the holiday weekend were

appropriate.

Engineering support was readily available and provided timely development of

repair techniques.

The inspector had no further concerns on this matter.

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 surveillances were observed:

Performance Test (PT)-32-A, Reactor Trip Breaker Testing - "A" Train, revision 12,

dated April2, 1992, observed June 23, 1992

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PT-12.1, Emergency Diesel Generator 1A, revision 68, dated April 9, 1992, observed

July 10, 1992

No unacceptable

conditions were identified.

4.0

Security (71707)

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.

Adequate compensatory

measures

were provided to support ongoing site security upgrade modifications.

No

unacceptable conditions were identified.

5.0

EMERGENCY PREPAREDNESS

(71707)

5.1

Simulator-Driven Mini-Drill

On June 17, 1992, a simulator-driven mini-drillwas conducted to internally assess

emergency

preparedness

capabilities of plant operators and the site technical staff.

The inspector verified

that the on-going drill did not adversely impact control room operations or associated

equipment.

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ENGINEERING/TECHNICALSUPPORT (71707, 92701)

6.1

"A"Preseparator Drain Tank Rupture

6.1.1

Event Description

On the morning of June 9, 1992, a shift supervisor (SS) noticed a small puddle of water

under the "A" preseparator drain tank (PDT) while conducting a routine plant tour.

Through

comparison by touch, the SS found the "A" PDT lagging to be significantly hotter than that

of the "B" PDT.

He then returned directly to the control room.

As he entered the control

room, he heard a loud roaring noise in the turbine building and saw steam fillingthe

building. Auxiliary operators were dispatched to investigate.

Upon reporting that steam was

emanating from the area where the PDTs and feedwater heaters are located, control room

operators commenced

a 1%/minute load reduction at 4:49 A.M. As a result of the turbine

building steam environment, an erroneous fire alarm on Z-32 (turbine building basement

north) and intermittent 480 volt non-vital bus ground fault alarms were received (and rapidly

cleared) in the control room.

In response to these indications of degrading conditions, the

load reduction rate was increased to 2%/minute.

The main generator output breakers were

opened at 6:12 A.M. and the turbine manually tripped one minute later.

Shutting the turbine

stop and intercept valves isolated the leak.

Subsequent

inspection of the "A" PDT revealed a

wall failure in the form of a fish mouth rupture on the north side of the PDT.

The fish

mouth was approximately 8 inches long with a maximum opening width of about 1/2 inch.

Using the clock location system, the failure area was located at the 3 o'lock position when

viewed from the east end of the "A" PDT.

There were no personnel injuries and no obvious

damage to surrounding plant equipment.

Examination of the ground fault indicating lights by

the auxiliary operators on all safety and non-safety related 480 volt buses indicated no off-

normal conditions.

6.1.2

Equipment Description

The "A" PDT is of carbon steel (A-53-B) construction measuring 36 inches in diameter by

approximately

11 feet long.

The nominal wall thickness of the shell material is indicated to

be 3/8 inch.

The tank serves as an in-line moisture collection header for extraction steam

being routed to the 4A feedwater heater.

Steam exhausted from the eleventh stage of the

high pressure turbine is extracted at two points and directed through separate 31-inch piping

runs to the in-line 1B and 2B preseparators

prior to entering the 1B and 2B moisture separator

reheaters (MSR), respectively.

The saturated steam/water mixture captured in the

preseparators

is channeled initiallythrough two 14-inch lines, then through 16-inch lines to

the PDTs.

Steam/water enters the "A"PDT through two inlet nozzles at the east end.

Elbows installed on the inlet nozzles inside the vessel direct the flow axially along the length

of the vessel.

Through impingement, flow direction changes,

and volumetric expansion,

water is removed from the flow stream.

At full power, the PDTs collect saturated water at

150 psig and 350'F.

Steam with improved quality is directed from the vessels to the 4A and

4B feedwater heaters.

Water is discharged to the heater drain tank or, on high PDT level,

dumped to the main condenser.

The PDTs were originally installed in 1983 as part of the Engineering Work Request (EWR)

3100 MSR Upgrade Project.

The vessel was designed by the Brown Boveri Corporation and

manufactured by Conring Fabricators.

The internal nozzles and baffles were modified in

1984 to correct level control problems.

At that time, due to space limitations in the "A"

PDT, one of the internal elbows was orientated at an angle with respect to the vessel axis,

directing the flow toward the north vessel wall.

The rupture occurred in this area of the "A" PDT vessel wall, which had been extensively

thinned by an erosion/corrosion (E/C) mechanism.

6.1.3

Licensee Response

Following the rupture at 4:49 A.M., operations personnel initially reduced electrical

generation at 1%/minute.

Upon receiving intermittent alarms for ground faults on the plants

480 volt buses, indicating that the turbine building steam environment could be potentially

degrading balance-of-plant electrical supplies, the rate of power reduction was increased to

2%/minute.

Plant equipment functioned as required.

The main generator output breakers

were opened at 6:12 AM and the turbine was manually tripped one minute later.

Shutting the stop and intercept valves effectively isolated the leaking "A" PDT, permitting

inspection of the wall failure and assessment of repair strategies.

The reactor was maintained

at about 1% power until 9:28 A.M., at which time site management directed that it be placed

in hot shutdown conditions pending completion of PDT repairs.

Earlier, site management

convened a series of planning meetings to identify specific tasks to be completed to affect the

repairs, and additional tasks that could be facilitated during the outage.

A team of corporate

mechanical engineers was assigned to provide continuous on-site coverage to support repair

activities.

Initially, the licensee's Materials Engineering and Inspection Services Group completed a

100% volumetric examination, using ultrasonic techniques, of both PDTs, in order to

determine ifadditional areas of these vessels were at or near the minimum wall thickness.

This inspection revealed that other areas were below the minimum wall thickness

requirements.

Accordingly, repairs were extended to include those areas.

The repair

technique to be used was to provide reinforcing material to the thinned areas through either

the use of 3/8-inch A-36 carbon steel plate overlay, or the use of weld buildup.

The

actual

technique used would depend on the size/location of the area requiring repair.

Following

these UT examinations,

a section of the "A" PDT wall (approximately 3-inches wide by 8-

inches long) containing the rupture was cut out and taken to the RG&E Materials Engineering

Laboratory for examination, verification of material specifications, and determination of the

failure cause.

Final repairs to the "A" PDT consisted of welding three two-foot wide, 3/8-inch thick, rolled

A-36 carbon steel plates to the outside of the tank.

Full penetration welds were provided

between plates.

These plates, extend 180 degrees around the tank, encompassing

the rupture

as well as areas identified to be less than minimum acceptable thickness.

Additionally, two

smaller 3/8-inch thick plate overlays were welded to the tank exterior opposite the rupture to

complete reinforcement of thinned portions of the tank.

Thinned wall areas in the "B" PDT were reinforced through weld buildup in two internal

locations and by installing a 19-inch wide by 26-inch long, 3/8-inch thick, rolled A-36 carbon

steel plate at one external location.

Following weld inspections, integrity of the "A" PDT was tested under operational conditions

in accordance with Power Piping Code B-31.1.

Specifically, with the insulation off, after the

first delivery of steam, a visual leak check was performed for 10 minutes in the vicinity of

the rupture.

Additionally, with the insulation on, a visual leak check was performed over a 4

hour period after full power and maximum pressure were achieved.

No leakage was

detected.

The justification that these repairs provided an adequate margin of safety was documented by

RG&E corporate engineering in the following design analysis reports:

Preseparator

Tanks A & B, Evaluation of required minimum wall thickness, EWR

3100, DA-ME-92-001-01, June 10, 1992

Preseparator

Headers A & B Basis for Repair Methodology, EWR 3100, DA-ME-92-

002-02, June II, 1992.

These design analyses give predicted values for minimum wall thickness,

based on the actual

erosion rates, that can be used in periodic inspections.

The PDTs are scheduled for a

complete reinspection against these predicted values during the 1993 refueling outage.

Until

then, the licensee plans to conduct routine UT examinations over limited areas of the PDTs.

As part of their review of the failure of the "A" PDT, the corporate engineering team

identified several components in balance-of-plant systems that could be susceptible to similar

E/C failures which were not included in the E/C inspection program because they were not

considered piping.

These components,

which included the heater drain tank, house heating

steam condensate

return tank, steam generator blowdown tank, and 2nd and 4th pass MSR

drain tank, willbe examined for wall thinning during the 1993 outage.

6.1.4

Inspector Findings

The NRC resident and regional staff reviewed the licensee's engineering response in

evaluating the failure mode of the PDT and its associated

repair.

The inspectors agreed with

the conclusion of the licensee's metallurgical report that covered the analysis of the ruptured

tank wall. This analysis verified that the failure occurred in an area of the tank that had been

significantly thinned by erosion/corrosion

as a result of water and steam impingement.

The

failure was of a ductile nature and originated in an area of the tank in which the wall

thickness was reduced from a nominal 0.375 inch to 0.014 inch.

The material properties

were found to correspond to the chemical and metallurgical properties of the specified ASTM

A53 carbon steel.

No metallurgical anomalies were observed in the material specifications of

the failed tank.

Based on a review of the licensee's technical justification for the repair strategy, the

inspectors identified several limitations concerning the long-term integrity of the repair.

These limitations included:

The licensee maintained that, although the MSRs were designed to ASME Boiler and

Pressure

Vessel Code Section VIIIrules, no such designation was given to the PDTs.

They were not considered to formally come under the rules of Section VIIIor the

Power Piping Code (B31.1). RGB'tated that, for the original vessel built by

Brown-Boveri, the fabrication principles were to Section VIII,but that no Code Stamp

was necessary.

The inspector was aware of no precedence

set in either Section VIII

or B31.1 to permit lap weld joints acting as welds for Class A horizontal or

circumferential joints (Reference Section VIII,Table U% 12).

The absence of a Code

stamp on the vessel (pipe) would indicate the possibility that the complete set of rules

for vessel or pipe design were not followed. ASME approval of the design would

provide assurance

that the successful experience of Code vessels would provide a

measure of confidence in the design, materials, and fabrication used.

2.

In reviewing the detailed calculations, the inspector found that some elements of the

analysis were'not clearly shown.

In particular, DA-ME-92-001-01 showed a weld

efficiency factor of 0.7, which, for a single lap welded joint, appears to be high and

provides non-conservative

estimates of erosion progress.

3.

Conceptually, the analysis was not clear as to the participation of the remaining

portion of the burst plate with the patch plate in containment of the pressure load.

The plates, when welded together, both act in pressure load restraint. Ifsuch is the

case, there is concern for long-term progression of the burst mouth.

4.

The licensee explained that, since the patch plate neutral axis is not coplaner with that

of the shell wall, a small bending moment would result.

Discussion with the licensee

indicated that a bending stress of approximately 5000 foot-pounds was present.

The

inspector concluded that this stress level should have been given consideration in

formulating the repair strategy.

5.

The repair was necessitated

because of flow impingement upon a shell wall such that,

over a period of time, the wall had eroded to failure thickness.

This indicated a

design deficiency.

Good design practice would provide for material added to the wall

thickness or a sacrificial plate installed to absorb the erosive effect of the impinging

fluid.

In response to these concerns,

the licensee stated that the repairs are only temporary and that

final corrective action would be implemented during the 1993 outage.

Additionally, the

licensee has contracted an independent consultant to review the appropriateness of the

temporary repair in light of ASME rules.

A more detailed evaluation of this area is planned

in an upcoming inspection of the licensee's erosion/corrosion program.

6.2

Feedwater Flow Oscillations

As described in Inspection Report 50-244/92-08 and Licensee Event Report (LER)92-006,

feedwater flow oscillations contributed to a high "A" steam generator water level and a

subsequent

feedwater isolation on May 18, 1992.

During this inspection period, the licensee

continued investigating possible causes for this incident and took corrective action to mitigate

variations in feedwater flow. Through consultation with Westinghouse, RG&E site

engineering determined that by adjusting the gain on the Advanced Digital Feedwater Control

System (ADFCS), the cycling of the main feedwater control valves could be brought into

phase, thereby lessening flow imbalances.

Following review and approval by the Plant

Operations Review Committee (PORC) of the station modification procedure, SM-4773.33,

and supporting procedures to change the ADFCS setpoints, the gain was adjusted on June 16,

1992.

By observing this evolution, the inspector determined that the activity was well controlled by

plant operations management

and the site engineering staff in accordance with licensee

administrative procedure A-52.15, "Significant Infrequently Performed Evolutions." Prior to

making the setpoint change, control room operators were briefed by the Superintendent-Plant

Operations and the cognizant engineer.

Briefings included a summary of individual

responsibilities, confirmation of lines of communications to various plant areas,

expected

ADFCS response,

and anticipated operator actions should ADFCS response be off-normal.

The procedure controlling the station modification, SM-4773.33, was found to be sufficiently

detailed, requiring verbatim compliance with individual step signoffs.

The changes were

completed without challenging plant stability and effectively corrected the cycling phase for

the main feedwater regulating valves.

The licensee is continuing in its root cause analysis of

feedwater flow oscillations to identify measures

to optimize secondary plant performance.

6.3

Licensee Action on Previous Inspection Findings

6.3.1

(Closed) Unresolved Item (50-244/90-10-02) Licensee to verify separation of

AMSAC Cable Run in Cable Tray No. 372 from Cable Tray No. 23.

In RG&E correspondence

to the NRC dated May 27, 1992, the licensee provided the actions

taken to verify the separation of the ATWS Mitigating System Actuation Circuitry (AMSAC)

cable in cable tray No. 372, a non-safety related tray containing AMSAC cable, and cable

tray No. 23, a safety related cable tray.

The ATWS (Anticipated Transient Without Scram)

Rule, 10 CFR 50.62, and RG&E AMSAC modification Design Criteria (EWR 4230) require

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that a means be provided that is both diverse and independent from the existing reactor

protection system for tripping the main turbine and initiating auxiliary feedwater flow

following an ATWS event.

During the 1992 refueling outage, RG&E performed a field

verification to obtain additional data regarding AMSAC cable separation to address

separation

concerns identified in Inspection Report 50-244/90-10.

Subsequent

to the field verification,

licensee review of field data and electrical engineering circuit schedules for AMSAC cable

trays confirmed that the required separation exists.

Based on a review of licensee actions, the

inspector had no further concerns on this matter.

Accordingly, this item is closed.

6.4

Erosion/Corrosion (E/C) Integrated Management Team Meeting

On June 4, 1992, the inspector attended the quarterly meeting of the RG&E E/C Project

Team.

Management representatives

from the licensee's corporate engineering,

maintenance,

quality assurance,

chemistry, and construction departments

attended.

Agenda topics included

a review of nondestructive examination (NDE) results of components inspected during the

1992 outage, feedback on susceptible small bore piping E/C inspection activities, findings

addressing cost/technical requirements for possible replacement of degraded carbon steel

piping with stainless

steel or chrome-moly materials, and the recent acquisition by the RG&E

Materials Engineering Laboratory of a digitization imaging system that enhances video/film

x-ray resolution.

The inspector determined that the meeting was well coordinated, with

active participation by all members.

In-depth discussions

addressed

areas where the E/C

program could be expanded or enhanced

and optimizing repair/replacement

strategies.

The inspector concluded that the licensee is appropriately and systematically addressing E/C

concerns,

7.0

SAFETY ASSESSMENT/QUALITYVERIFICATION(71707, 90712, 90713,

92701, 40500)

7.1,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:

Monthly Operating Report for May, 1992

Monthly Operating Report for June,

1992

No unacceptable conditions were identified.

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7.2

Licensee Event Reports (LERs) and Special Report

An LER and special report 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 LER and special report were reviewed (Note: date indicated is event date):

LER 92-006, Feedwater Control Perturbations,

Due to a Secondary Side Transient,

Causes

Steam Generator High Level Feedwater Isolation (May 18, 1992)

Special Report addressing

a Service Water Leak in the "C" Containment Recirculation

Fan Cooler (July 2, 1992).

The report was submitted in accordance with IE Bulletin

No. 80-24, "Prevention of Damage Due to Water Leakage Inside Containment."

The inspector concluded that the LER and special report were accurate and met regulatory

requirements.

No unacceptable

conditions were identified.

7.3

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

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On June 3, 1992, the inspector attended a quarterly meeting of the RG&E QA/QC

Subcommittee.

The inspector observed that senior corporate management

was briefed on the

status of audit findings, performance indicator trends, quality performance program status and

plans, and the progress of internal self-assessments.

Areas requiring increased attention were

identified by the participants and action items assigned.

The inspector concluded that licensee

management

was properly informed of the effectiveness of programs designed to enhance site

performance.

The inspector had no concerns on these matters.

8.0

ADMINISTRATIVE(71707, 30702, 94600)

8.1

Backshift and Deep Backshift Inspection

During this inspection period, deep backshift inspections were conducted on the following

dates:

June 13, 29, July 3, and 6.

8.2

Exit Meetings

At periodic intervals meetings were held with station management

to discuss inspection scope

and findings.

The exit meeting for this inspection was held on July 24, 1992.

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