ML17262A486

Insp Rept 50-244/91-07 on 910312-0415.One Violation Noted. Major Areas Inspected:Plant Operations,Radiological Control, Maint/Surveillance,Emergency Preparedness,Security, Engineering/Technical Support & Safety Assessment

ML17262A486
Person / Time
Site:	Ginna
Issue date:	04/29/1991
From:	Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML17262A484	List: ML17262A483 ML17262A485 ML17262A486
References
50-244-91-07, NUDOCS 9105220120
Download: ML17262A486 (19)

See also: IR 05000244/1991007

Text

U. S. NUCLEARREGULATORY COMMISSION

REGION I

Inspection Report 50-244/91-07

License: DPR-18

Licensee:

Facility:

Inspection:

Inspectors:

Approved by:

Rochester Gas and Electric Corporation (RG&E)

R. E. Ginna Nuclear Power Plant

March 12 through April 15, 1991

T. A. Moslak, Senior Resident Inspector, Ginna

N. S. Perry, Resident Inspector, Ginna

P. P. Sena, Reactor Engineer, PB3, DRP

E. C. McCabe, Chief, Reac'tor Projects Section 3B

INSPECTION SCOPE

wjell>

Date

Plant operations, radiological controls, maintenance/surveillance,

emergency preparedness,

security, engineering/technical

support, and safety assessment/quality

verification.

OVERVIEW

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from a leaking secondary neutron source.

Mid-loop operations were rigidly controlled.

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outage activities to minimize personnel exposures

and contaminations.

Maintenance/Surveillance:

Improper coordination between the operations and maintenance

departments

resulted in the temporary loss of the Component Cooling Water System.

Emer enc

Pre aredness:

Guidance has been issued on the classification and notification

actions for already terminated events.

~ec i~rit: No discrepancies

were identified during routine security checks.

En ineerin /Technical u:

Relevant engineering procedures

have been revised to assure

timely updating of as-built drawings.

9105220120

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PDR

ADOCy, 05000244

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TABLEOF CONTENTS

OVERVIEW

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

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1.0

PLANT OPERATIONS

1.1

Operational Experiences.........

1.2

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

1.3

Fire Protection

1.4

Valve Found Out of Required Position

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2.0

RADIOLOGICALCONTROLS

2.1

Routine Observations

2.2

ALARA(As Low As Reasonably Achievable) Program ..

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3,0

MAINTENANCE/SURVEILLANCE

3.1

Corrective Maintenance...... ~..............

3.1.1

Service Water Pump Expansion Joint Replacement

3.1.2

Valve Repacking...... -...............

3.2

Surveillance Observations............ ~.......

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4.0

EMERGENCY PREPAREDNESS

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4.1

(Closed) Unresolved Item (50-244/90-31-02) EPIP Classification for SI

D1sabled

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5.0

SECURITY

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5.1

Routine Observations

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6.0

ENGINEERING/TECHNICALSUPPORT ..;..........

6.1

(Closed) Violation (50-244/90-80-02) Failure to Maintain

Drawings As Required

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7.0

SAFETY ASSESSMENT/QUALITY VERIFICATION

7.1

Periodic Reports

7.2

Written Reports of Nonroutine Events

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8.0

ADMINISTRATIVE.............

8.1

Inspection Hours ...........

8.2

ExitMeetings.....;.......

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DETAILS

1,0

PLANT OPERATIONS

1.1

Operational Experiences

At the start of the inspection, the plant was at approximately 91% power and coasting down

for the annual refueling outage.

The start of the outage was postponed from March 15 to

March 22, 1991 to allow outage support personnel, who worked long hours responding to the

March 3-4 ice storm, to prepare and train for the outage.

Operators began shutting down the

plant early on March 22, and the plant was shut down later that day.

3

After reaching cold shutdown, operations personnel conducted a hydrogen peroxide flush

(superflush) of the Reactor Coolant System (RCS) to aid in crud removal.

Following the

superflush, elevated concentrations of Antimony (Sb) 122 and 124 occurred in the RCS.

The

origin was determined to be one or more leaking Antimony-Beryllium (SbBe) secondary

neutron source assemblies

in the reactor core.

To minimize the spread of contamination and

lower personnel radiation exposures, RG&E management

decided to delay refueling until the

Chemical and Volume Control System (CVCS) could reduce these contaminants.

Allfour

secondary source assemblies were subsequently

removed 'during refueling operations and

placed in storage.

On April 3, 1991, an Unusual Event was conservatively declared when operators terminated

refueling operations and removed the Residual Heat Removal (RHR) System and the

Component Cooling Water (CCW) System from service,

This was done to stop a CCW

valve packing leak which developed during valve maintenance.

When the CCW system was

unavailable, the RHR system was started every five minutes and run for two minutes to

recirculate the coolant and trend any temperature increase.

The leak was stopped by

manually backseating

the leaking valve.

The CCW and" RHR systems were restarted

approximately 24 minutes after being removed from service, and the Unusual Event was

terminated about one hour and nineteen minutes after declaration; all required notifications

were made.

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.

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 audited selected safety-related

tagouts.

During

normal work hours and on backshifts, accessible

areas of the plant were toured.

No

inadequacies

were identified.

Cl

The inspectors monitored the plant's entry into a reduced inventory (mid-loop) condition and

subsequent

operation in this mode in preparation for removing the reactor vessel head.

The

licensee's controlling document for this condition is Operating Procedure (O)-2.3.1, Draining

and Operation at Reduced Inventory of the Reactor. Coolant System, Revision 39.

Prior to

entry into mid-loop conditions, the inspectors verified the licensee's controls assuring

containment closure capability.

Licensee 24-hour quality control coverage of plant operations

was provided while in a reduced inventory condition.

The inspector determined that the

licensee demonstrated

a conservative approach to the drain-down evolution and resulting

reduced inventory operation.

This was evident when operations personnel secured the

draining of the Reactor Coolant System (RCS) due to a discrepancy between Loop A and

Loop B hot leg level indicators LT-432A and LT-432B. Instrumentation and 'Control (1&C)

personnel vented and restored the detectors to resolve the differences.

In addition, operations

personnel manually started the "B" Emergency Diesel Generator when high wind conditions

'osed a threat to the offsite power supply during mid-loop operation.

Although no loss of

offsite power occurred, this was assessed

as a prudent licensee-initiated action to assure

continuity of power.

The licensee is issuing a voluntary LER describing these actions.

A questioning attitude was demonstrated

by licensee personnel while lowering the RCS water

level.

Errors in the draining procedure were identified by operators and resolved prior to

proceeding.

For example, Step 5.6.2 required Residual Heat Removal (RHR) Pressure

Transmitter PT-682B to be placed in service by opening Valve V-'712E.

The operator

performing the line-up noted this was a drain valve and that it should be closed.

Additionally, Step 5.11.1 required remote loop level indication to be available in the Control

Room via LT-432A and LT-432B. However, the valve lineup to place LT-432A in service

was omitted from the procedure.

Both of these discrepancies

were properly resolved with the

draining secured and RCS level available on the loop level indicators.

The inspectors determined that licensee personnel were aware of on-going plant activities and

avoided operations that could lead to perturbations to the RCS or to systems necessary

to

maintain the RCS in a stable mode during mid-loop conditions.

The Outage Coordinator

briefed site personnel during daily task planning meetings on NRC Information Notice 91-22

to sensitize them to recent industry events during mid-loop conditions.

Additionally, the

Outage Coordinator specified what tasks were stopped or rescheduled

to reduce the possibility

that on-going jobs could impact safety equipment operation.

For example, in light of recent

industry events, the access road to the 13B offsite plant switchyard was closed and the gate

locked while the plant was in a reduced inventory condition.

In addition, all maintenance

within the switchyard was prohibited by the Plant Manager to avoid any disturbances

to the

site's electrical power supplies.

The inspectors concluded that the licensee was appropriately

aware of the risks associated with the RCS being partially drained and performed the draining

evolution in a safe and conservative manner.

1.3

Fire Protection

On March 14, 1991, a continuous fire watch with backup suppression

was not established

when an auxiliary building sprinkler system was removed from service.

Prior to initiating

work, maintenance personnel notified Fire and Safety Department personnel and control room

operators as required.

Control room personnel erroneously believed that maintenance

personnel had arranged for the required fire watch.

No fire watch was established

since Fire

and Safety Department personnel were waiting for formal'notification from control room

personnel.

Operators declared the fire system inoperable, initiated the appropriate paperwork

for tracking, and disabled the system by closing and tagging an isolation valve. -After

maintenance completed work, an auxiliary operator was notified by radio to restore the

system to service.

Fire and Safety Department personnel heard the radio transmission and

contacted the shift supervisor, informing him that the required fire watch had not been

established.

A fire watch was then established,

the tags were removed and the system was

restored.

Control room personnel made the appropriate notifications and initiated a Ginna

Station Event Report.

The inspectors reviewed the circumstances

leading to this incident and determined that,

normally, after maintenance personnel request that operators hold the system, control room

personnel contact Fire and Safety personnel to arrange for the appropriate compensatory

actions.

In this instance, that did not occur.

Plant management

determined that the controlling procedures were vague concerning how the

appropriate compensatory

actions were to be arranged.

The governing Administrative

Procedure [(A)-52.4.1, Control of Limiting Conditions for Operation of Fire Spray/Sprinkler,

Fire Detection Equipment and Fire Barriers, Revision 27, effective February 13, 1991], states

that Site Contingency Procedure (SC)-3.15.17 provides instructions for posting fire watches.

SC-3.15.17 does not clearly define who is responsible, for notifying Fire and Safety personnel

to establish the required fire watch.

In this instance, the procedure used by the maintenance

personnel did have a step addressing

the establishing of a fire watch.

This maintenance

procedure [(M)-67.3, Flood Valve System Maintenance SO4 V-9242D WO9024072, Revision

11, effective January 26, 1991], requires in step 5.2 that personnel ensure that there is fire

watch coverage of the affected area in place.

Maintenance personnel signed this step,

signifying that a fire watch would be posted.

For the incident on March 14, plant management

determined that Technical Specification 3.14.3.1 was violated due to inadequate adherence

to procedures

and erroneous assumptions

made by personnel involved.

Corrective'actions included making personnel involved aware

of management

expectations,

and the appropriate procedures were changed to require formal

notifications and the posting of a fire watch prior to the removal of the system from service.

Additionally, Licensee Event Report (LER)91-003 was submitted for this event at the end of

the inspection period.

The LER willbe reviewed in a future inspection report.

The inspectors determined that formal communications between maintenance and control

room personnel on March 14 resulted in a continuous fire watch with backup fire suppression

equipment not being established within one hour as required by Technical Specification 3.14.3.1.

The violation was identified by plant personnel.,

Immediate correction was

achieved by establishing the fire watch and restoring system operability.

To prevent

recurrence,

the appropriate procedures were changed.

There is minor safety significance to

this event since the fire detection system, which alarms in the main control room, was

operable, the spray system was inoperable for a short duration, and there were personnel in

the area while the system was inoperable.

Under Section V.G.1 of 10 CFR 2, Appendix C,

no violation was cited since this event was licensee identified, of minor safety significance,

properly reported, immediate corrective measures

and actions to prevent recurrence were

appropriate, and the event was not identified as willfulor as preventable through corrective

action on a prior violation (50-244/91-.07-01).

1.4

Valve Found Out of Required Position

On March 21, 1991, Residual Heat Removal (RHR) Heat Exchanger Bypass Valve V-712A

was found out of its required (closed) position by operators during monthly surveillance (S)-

30.2, RHR System Valve and Breaker Position Verification. Subsequently,

operators closed

the valve and completed S-30.2 with no further discrepancies

noted.

As required, operators

verified that all other safeguards

systems were properly aligned by completing each system's

appropriate position verification procedure..

Plant management

determined that there was minor safety significance to this particular valve

being out of position since the valve was a manual valve in series with two other closed

valves.

Plant personnel determined that, when the system was aligned by operators after

V-712A maintenance,

V-712A was inadvertently omitted from the alignment sheet developed

from the tagging order and was therefore not checked for proper positioning.

As a corrective action, plant management

directed Operations to verify the position of all

'alves,

whether manipulated or not, within the boundaries of a tagout when restoring system

operability.

Additionally, Administrative Procedure (A)-1408, Independent Verification, was

revised to require two independent signoffs on the alignment worksheet for all valves inside

the tagging boundary.

The inspectors concluded that the alignment error was identified in a timely manner and that

the corrective actions taken were comprehensive.

Plant management

became involved shortly

after discovery and exhibited an appropriate level of concern.

Administrative procedure (A)-1408, Independent Verification, Revision 5, effective October

11, 1990, requires an independent verification whenever valves in safety-related

systems are

manipulated for maintenance.

On March 20, 1991, V-712A was not independently verified

to be in the required position after maintenance.

The out-of-position condition was identified

by plant personnel,

and immediate corrective actions were taken by properly positioning the

valve.

To prevent recurrence,

a procedure change was made requiring independent signoffs

on the alignment worksheet for all valves inside the tagging hold boundary.

There is minor

safety significance to this valve being out of position, since the valve was in series with two

other closed valves.

Under 10 CFR 2, Appendix C, Article V.G.1, a violation was not cited

since this event was licensee-identified, of minor'safety significance, properly reported,

immediate corrective measures

and action to prevent recurrence were appropriate,

and the

occurrence was not identified as willfulor as preventable through corrective action on a prior

violation (50-244/91-07-02).

2.0

RADIOLOGICALCONTROLS

2.1

Routine Observations

The resident 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.

2.2

ALARA(As Low As Reasonably Achievable) Program

As described in Paragraph

1.2, following plant shutdown, plant management

anticipated

potential contamination and personnel exposure control problems arising from elevated

concentrations of Sb 122/124 in the RCS.

The RG&E staff consulted with another utility that

has experienced similar conditions and determined that it was prudent to delay head removal

until the Sb was substantially reduced.

Through use of CVCS ion exchangers,

the total RCS

activity was reduced from about 0.5 uC/ml to less'han 0.05 uC/ml in about 3 days.

From these actions, the inspectors concluded that licensee management

demonstrated

a strong

commitment to the ALARAprinciple.

This commitment was further demonstrated

by the

high frequency of ALARAcommittee meetings designed to review forthcoming tasks from an

ALARAperspective and to critique mock-up training to better assess radiological controls.

Additionally, Health Physics personnel actively participated in daily task planning meetings to

direct attention to contamination control concerns.

3.0

MAINTENANCE/SURVEILLANCE

3.1

Corrective Maintenance

3.1.1

Service Water Pump Expansion Joint Replacement

On March 20, 1991, the discharge expansion joint on the "D" Service Water Pump was

replaced.

Operators had noticed a deformation in the joint and requested

the replacement.

The spare expansion joint in stock appeared old, so maintenance personnel ordered new joints

and had a hydrostatic test performed prior to installation.

Maintenance management

stated

that the old expansion joint would be removed from stock.

The inspectors observed portions of the expansion joint 'replacement

and the post-maintenance

test including the leak inspection.

A quality control inspector performed a thorough leak

examination, and there appeared to be good coordination between the working groups

involved. No inadequacies

were identified.

3.1.2

Valve Repacking

On April 2, 1991, maintenance personnel began repacking Component Cooling Water (CCW)

Motor-Operated Inlet Valve V-738B to the "B" Residual Heat Removal (RHR) heat

exchanger.

Maintenance planners had prepared

a package for the activity, and operators had

held the system for the maintenance.

The valve was to be repacked with the valve backseated

since V-738B could not be completely isolated due to the CCW system configuration.

While

the old packing was being removed, a leak. developed through the remaining packing.

The

activity was immediately stopped and the control room was notified. The valve was in

mid-position.

Operators attempted to stop the leak by electrically opening {backseating) the

valve.

However, the leak rate did not decrease

since opening V-738B electrically willnot

fully backseat it.

Operators decided that they would have to stop the running CCW pump in order to access

the

valve to manually backseat it. Reactor refueling was in progress,

so that activity was

terminated first, and the running RHR pump was stopped prior to stopping the running CCW

pump.

Operators conservatively declared an Unusual Event due to the loss of CCW cooling

to the RHR system.

The leaking valve was manually placed on its backseat and the leak was

stopped.

During the loss of CCW, the RHR pump was run for two of every five minutes in

order to recirculate the coolant and trend any temperature increase.

When the plant was

returned to pre-event conditions after one hour and nineteen minutes, the Unusual Event was

terminated.

Plant management

had a Human Performance Enhancement

System (HPES) evaluation

performed to identify the root causes

and recommend corrective actions,

As corrective

action, plant management

distributed inter-office correspondence

re-emphasizing

the

requirements for checks and verifications to ensure personnel and equipment safety during

work.

Repacking valves on the backseat was highlighted, and appiopriate procedure

revisions were made or initiated.

Other corrective actions willbe tracked by the corrective

action report system.

Additionally, the Operations Manager distributed inter-office

correspondence

to operations personnel, providing information and guidance concerning valve

backseating.

Copies were also distributed to maintenance and training management for

incorporation'nto their programs.

Through interviews and document review, the inspectors determined that the hold request did:

not specify that the valve should be backseated,

the Holding Authority (Shift Supervisor) did

not properly verify the adequacy of the isolated work area as required by Administrative

Procedure (A)-1401, Station Hold Rules, Revision 25, and the Authorized Person (Hold

Requester) for the hold did not properly assure that the equipmen< was properly isolated and

it was safe to proceed with the work as required by A-1401.

Communications between

maintenance personnel and control room personnel were informal and inadequate,

in that

control room personnel did not understand

that the valve needed to be manually backseated

in

order to perform the activity, and the personnel performing the maintenance did not

understand

the condition of the equipment prior to the start of their work.

Additionally, the inspectors determined that the analogous valve in the other train of CCW

had been successfully repacked earlier on March 31, 1991, without the same problems.

In

that case, the system was also inade'quately held, but the maintenance person performing the

w'ork backseated

the valve prior to repacking it. This individual did not point out the

inadequate hold to management,

and this problem was not corrected prior to April 2.

The

inspectors noted that the lack of feedback on the first inadequate hold contributed to the

April2 event.

Technical Specification 6.8.1 requires establishment of the applicable procedures

recommended in Appendix A of Regulatory Guide 1.33, November 1972 (Safety Guide 33).

Regulatory Guide 1.33, November 1972, Appendix A,Section I, specifies that maintenance

which can affect the performance of safety-related equipment should be properly preplanned

and performed in accordance with written procedures,

documented instructions, or drawings

appropriate to the circumstances.

Administrative Procedure (A)-1401, Station Hold Rules,

Revision 25, effective March 25, 1991, requires that the Holding Authority properly verify

the adequacy of the isolated work area and that the Authorized Person for the hold properly.

assure that the equipment is properly isolated and that it is safe to proceed with the work.

Contrary to the above, on April 2, 1991, CCW valve V-738B was not properly isolated,

leading to the shutdown of the CCW and RHR systems and to the declaration of an Unusual

Event.

The maintenance activity was not properly preplanned in that the Hold Request did

not specify that the operators manually backseat the valve.

Additionally, Maintenance

Procedure (M)-37.116.3, Valve Packing, Revision 0, effective March 9, 1991, for repacking

the valve did not require maintenance personnel to verify that the valve was properly

backseated prior to the repacking.

The inadequate hold was identified by plant personnel,

and immediate corrective actions were

t'aken by manually backseating

the valve prior to,resumption of maintenance.

To prevent

recurrence, procedure changes were being reviewed and plant personnel were notified of

management

expectations concerning the establishment of a safe, isolated work area.

There

was minor safety significance to this event since the work was planned for a time during

which the reactor was in a safe condition with more than 23 feet of water above the core.

3.2

Surveillance Observations

Inspectors observed parts 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:

Periodic Test (PT)-2.7, Service Water System, Revision 54, effective August 24,

1990, observed March 21, 1991.

Although there were no safety significant discrepancies

noted, the inspectors observed minor

discrepancies.

Procedure direction from the person controlling the procedure and the-

sequencing through the procedure were weak.

The inspectors pointed out these observations

to Results and Test supervision and were informed that the personnel were counselled about

how they are expected to perform during surveillances.

The inspectors had no further

questions.

PT-22.10, Mechanical Manifold 'C'eakrate Test, Revision 12, effective March 30,

1990.

Activities in the control room during the surveillance were professional, with good

communications between workers.

The containment penetration leak detection test was

conducted per Technical Specification 4.4.2, which ensures

the total leakage from.all

penetrations

and isolation valves does not exceed 0.60La.

La is the maximum allowable

containment leakage rate vessel test atmosphere

at design pressure (Pa).

The surveillance was

conducted by qualified and knowledgeable personnel.

The inspector noted that the procedure

was properly performed at the containment integrated leak rate test pressure of 61 (+1, -0)

psig.

Additionally, the leak test procedure properly conformed to an approved testing method

per 10 CFR 50, Appendix J.

An independent calculation of the leakage by the inspector

verified that the administrative leakage limitof 50cc/min was not exceeded.

No deficiencies

were identified.

Refueling Shutdown Surveillance Procedure (RSSP)-2.3B, 'B'mergency Diesel

Generator Trip Testing, Revision 3, effective March 23, 1991, observed April 10,

1991.

S

PT-12.2, Emergency Diesel Generator

1B, Revision 63, effective April 5, 1991,

observed April 11, 1991.

The surveillances on the diesel generator were performed well by plant personnel.

During

the testing the inspectors noted good management oversight of activities at the diesel

generator.

No unacceptable conditions were identified.

4.0

EMERGENCY PREPAID)NESS

4.1

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(Closed) Unresolved Item (50-244/90-31-02) EPIP Classification for SI Disabled

This item concerned the adequacy of EPIP (Emergency Plan Implementing. Procedure)

1-0,

Ginna Station Event Evaluation and Classification, for classification of past events.

RG&E

management clarified their policy to all control room personnel and all plant personnel

qualified to serve as Emergency Coordinators.

The policy states that the NRC willbe

notified by means of the Emergency Notification System (ENS) phone any time conditions

are identified that would have warranted an Emergency Classification, but are no longer in

effect at the time of identification.

Appropriate EPIPs willbe changed

as necessary

to state

this policy.. The inspectors had no further questions.

5.0

SECURITY

5.1

Routine Observations

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.

No unacceptable

conditions were identified.

6.0

ENGINEERING/TECHNICALSUPPORT

6.1

(Closed) Violation (50-244/90-80-02) Failure to Maintain As-built Drawings As

Required

Following identification that procedural direction for processing vendor drawings received as

part of site-originated procurement did not exist, a Nuclear Engineering/Records

Management

Ad Hoc Group was formed to analyze this issue.

As a result, revisions were made to the

Engineering Procedures,

QE-324, Preparation,

Review & Disposition of Drawing Change

Requests,

and QE-704, Review and Approval of Vendor Design and Manufacturing Technical

'ocuments.

Inspector review found that appropriate technical direction is given in the

revised procedures to adequately control vendor drawings.

10

7.0

SAFETY ASSESSMENT/QUALITYVERIFICATION

7.1

Periodic Reports

The Monthly Operating Report for February 1991, submitted by the licensee pursuant to

Technical Specifications 6.9.1 and 6.9.3, was reviewed.

Inspectors verified that the report

contained information required by the NRC and that selected reported information was

accurate.

No unacceptable conditions were identified.

7.2

Written Reports of Nonroutine Events

Written reports 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

had been properly

evaluated, generic implications were indicated, events warranted on-site follow-up, reporting

requirements of 10 CFR 72 were applicable and requirements of 10 CFR 73 had been met.

The following Licensee Event Reports (LERs) were reviewed (Note:

date indicated is event

date):

90-010 (Revision 1), Inadvertent Closure of "A" Steam Generator Main Feedwater

Regulating Valve Due to Controller Malfunction Causes

a Reactor Trip on Low Steam

Generator Water Level, June 9, 1990.91-001, Loss of Safeguards

Bus During Emergency D/G Monthly Load Test Due to Supply

Breakers Tripping, February 2, 1991.91-002, Loss of Offsite Power Circuit 751, Due to Ice Storm, Causes Automatic Actuation of

the ESF and RPS, March 4, 1991.

The event associated with 90-010 was reviewed in NRC Inspection Report 50-244/90-09.

Revision

1 was necessary

to update the root cause identification. The events associated with

91-001 and 91-002 were reviewed in NRC Inspection Report 50-244/91-05.

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

No

unacceptable conditions were identified.

8.0

. ADMINISTRATIVE

8.1

Inspection Hours

This inspection included 6 backshift and 16 deep backshift hours.

Cll

11

8.2

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.

In addition, NRC

exit meetings were held for the following inspections during this inspection period: 50-

244/91-03 on March 14, 1991, 50-244/91-08 on April5, 1991, and 50-244/91-09 on April

12, 1991.

The exit meeting for this inspection report (50-244/91-07) was held on April 17, 1991 with

the following individuals attending:

~me

~Titl

Harry Aurand

John Fischer

Alan Jones

Michael Lilley

Thomas Marlow

Thomas Moslak

Neil Perry

Stanley Spector

Joseph friday

Corrective Action Assistant

Manager, Maintenance Planning & Scheduling

Corrective Action Coordinator

Manager, Nuclear Assurance

Superintendent,

Support Services

Senior Resident Inspector - NRC

Resident Inspector - NRC

Plant Manager

Superintendent,

Ginna Production