IR 05000244/1991029

Insp Rept 50-244/91-29 on 911210-920118.No Violations Noted. Major Areas Inspected:Plant Operations,Radiological Controls,Maint/Surveillance,Emergency Preparedness,Security, Engineering/Technical Support & Safety Assessment

ML17262A746
Person / Time
Site:	Ginna
Issue date:	02/04/1992
From:	Lazarus W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML17262A745	List: IR 05000244/1991029 ML17262A744
References
50-244-91-29, NUDOCS 9202180038
Download: ML17262A746 (18)

Text

U. S. NUCLEAR REGULATORY COMMSSION

REGION I

Inspection Report 50-244/91-29 License: DPR-18 Facility:

R. E, Ginna Nuclear Power Plant Rochester Gas and Electric Corporation (RG&E)

Inspection:

Inspectors:

December 10, 1991 through January 18, 1992 T. A. Moslak, Senior Resident Inspector, Ginna E. C. Knu n, Resident Inspector, Ginna Approved by:

, Chief, Reactor Projects Section 3B INSPECTION SCOPE Date Plant operations, radiological controls, maintenance/surveillance, emergency preparedness, security, engineering/technical support, and safety assessment/quality verification.

INSPECTION OVERVIEW Th pl p

H pp ly97%p

h gh h*

p period.

A computer malfunction existed for ten days resulting in an invalid value of feedwater flow being used in the calorimetric calibrations of the power range nuclear instruments.

Main n n rveill n:

Strong management and technical support were observed during corrective maintenance on a service water pump motor and a safety injection pump breaker.

Efforts to correct an intermittent problem with the automatic rod control system were unsuccessful; troubleshooting continues.

The decision to replace the containment particulate radiation monitor following a one-time microprocessor-related failure demonstrated a

conservative approach to dealing with microprocessor-based equipment malfunctions.

A minor deficiency was identified in the procedure for calorimetric calibration of the power range nuclear instruments.

Emer en Pre redn:

Fire alarm system testing produced a false alarm and halon fire suppression system actuation in the computer room.

Fire brigade response was prompt.

Adequate compensatory measures were taken while the fire suppression system was out of service.

En ineerin /Technical Su rt: Engineering evaluation that the sensing line isolation valves

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for a containment recirculation fan service water flow indicator must be treated as containment boundaries was conservative.

Close technical support minimized delay when a procedure modification was required.

9202180038 920204 PDR ADOCK 05000244

PDR

TABLEOF CONTE%IS VERVIEW

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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 Feedwater System Leading

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Edge Flow Meter

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Computer Malfunction

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2.0 RADIOLOGICALCONTROLS...............................

2.1 Routine Observations.................................

3 3.0 MAINTENANCE/SURVEILLANCE 3.1 Corrective Maintenance 3.1.1

"A" Service Water Pump Motor 3.1.2

"C" Safety Injection Pump Bus 14 Breaker 3.1.3 Automatic Rod Control System 3.1.4 Containment Particulate Radiation Monitor 3.2 Surveillance Observations 3.2.1 Calorimetric Calibration...........

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6 EMERGENCY PREPAREDNESS 4.1 Halon Fire Suppression System Discharge 5.0 SECURITY

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5.1 Routine Observations

8 6.0 ENGINEERING/TECHNICALSUPPORT 6.1 Containment Recirculation Fan Service Water Flow Indicator 7.0 SAFETY ASSESSMENT/QUALITY VERIFICATION 7.1 Periodic Reports...................

7.2 Licensee Event Report (LER)...........

7.3 Plant Operations Review Committee Meetings

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8.0 ADMINISTRATIVE e

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8.1 Backshift and Deep Backshift Inspection 8@2 Exit Meetings

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DETAILS 1.0 PLANT OPERATIONS 1.1 Operational Experiences The plant operated at approximately 97% power throughout the period of this report, There were no challenges posed to the plant which produced or required reduction in power.

An intermittent problem in the automatic rod control system once produced unnecessary inward rod motion, but prompt operator action precluded any effect on plant power.

Failure of the containment particulate radiation monitor produced a containment ventilation Engineered Safety Features actuation signal but had no effect on plant operations.

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, verified compliance with Technical Specifications, and audited selected safety-related tagouts.

During normal work hours and on backshifts, accessible areas of the plant were toured.

Except as noted below, no inadequacies were identified.

1.3 Feedwater System Leading Edge Flow Meter Computer Malfunction The Leading Edge Flow Meter (LEFM) is the most accurate of several installed feedwater flow measuring instruments and is used in performing secondary heat balance determinations (calorimetrics) for measurement of reactor power.

Feedwater flowrate from the LEFM computer, along with numerous other plant parameters, are automatically sampled by the plant computer, which then performs the calculations to determine reactor power.

The power range nuclear instruments are then adjusted to indicate calculated power.

This instrumentation is safety significant in that it provides overpower trip points for the reactor protection system.

Although Technical Specification 4.1.1 only requires daily calorimetric calibration of the power range nuclear instruments, RG&E performs this determination once every eight hours.

During a review of logs on December 30, 1991, an operator noted that confidence values for feedwater flow had been essentially constant at 100% for the previous 10 days.

Under steady-state conditions, the confidence value for this parameter is normally very high ()99.5%), but it is seldom 100%; this, along with the lack of variation over so long a period of time, led the operator to suspect a problem.

Investigation revealed that the LEFM computer had experienced an anomalous processing interruption on December 20.

The computed value of feedwater flow had not updated since then; however, confidence values, which are calculated by the plant computer, had continued to generate using the locked-in

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value of feedwater flow. Since the confidence value is based on the amount of variation in feedwater flow over time, this resulted in a 100% confidence value being generated.

At the same time, this locked-in value of feedwater flow was also transmitted to the plant computer for use in calorimetric calibrations.

Consequently, the calorimetric calibrations which had been performed since December 20 were not v'alid.

Upon making this determination, a calorimetric calibration was expeditiously performed using manually input feedwater flow data obtained from the Barton flowmeters.

The result indicated that reactor power was 0.17% higher than had been obtained using the erroneous LEFM computer value for feedwater flow. The LEFM computer program was reinitiated and appeared to operate normally.

Troubleshooting revealed no hardware or software problems.

After discussions with the vendor, RG&E concluded that the most likely cause of the failure was either a short duration power spike or an intermittent failure of the LEFM computer.

The Barton flow meters continued to be used as the source of feedwater flow data pending changes to the procedure which would ensure that the LEFM computer was operating properly prior to using it as an input to calorimetric calibrations.

r Using values of feedwater flow, which were generated by separate instrumentation and were routinely recorded by the plant computer, along with the fact that reactor power had remained essentially constant throughout the period in question, it was possible to evaluate what would have been the worst case deviation between actual and indicated reactor power.

This was done by comparing the regenerated calorimetric result which used the highest recorded feedwater flow against the lowest calculated value of reactor power generated using the erroneous LEFM feedwater flow value.

Through this analysis, it was concluded that at any time during the 10 day period, actual reactor power never exceeded 98.7%, in the worst case.

This would have been 1.6% greater than indicated reactor power.

Since the precision of the calorimetric calibration is + 2%, it was further concluded that no violation of technical specification limits for reactor power or reactor protection system trip setpoints had occurred.

In accordance with the guidance of NUREG 1022, RG&E evaluated this problem as not requiring a Licensee Event Report (LER) per 10 CFR 50.73; however, in light of its significance to other plants which use LEFMs for calorimetric calibrations, a voluntary LER willbe submitted (LER 91-010).

10 CFR 50, Appendix B, Criterion 16 states, in part, that "Measures shall be established to assure that conditions adverse to quality, such as...malfunctions...are promptly identified and corrected."

While RG&E's actions in response to the LEFM problem were conservative and thorough, the fact that the problem went undetected for 10 days indicated that existing measures to assure prompt identification of such conditions were inadequate.

Although this constitutes a violation, the licensee has not been cited because the criteria of 10CFR Part 2, Appendix C, Paragraph V.G.1, were met. Specifically, the violation: a) was identified by the licensee; b) was severity level IV or V; c) did not require reporting; d) was corrected, including measures to prevent recurrence, within a reasonable time; and e) was not a willful violation or a violation that could reasonably be expected to have been prevented by the licensee's corrective action for a previous violation.

(NV5 91-29-01)

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 properly implemented.

No inadequacies were identified.

3.0 MAINTENANCE/SURVEILLANCE 3.1 Corrective Maintenance 3.1.1

"A" Service Water Pump Motor On December 20, 1991, operators noted what they considered excessive noise from the "A" service water pump motor, as compared to the other operating service water pump.

Although investigation revealed no abnormal pump vibration, the oil in the upper thrust bearing reservoir was abnormally dark.

On this basis, the motor was removed and disassembled for inspection.

In the course of this inspection, a technician noted a darkened area on the stator winding insulation.

Cleaning and insulation removal revealed the cause to be two broken conductors in one of the winding coils. Typically with large motors, the individual stator windings are not single wires, but consist of several wires connected in parallel to provide the required cross-sectional area.

In this case, the stator winding conductors consisted of six wires.

The standard electrical checks (coil resistance and insulation-to-ground resistance)

performed earlier in the inspection had not revealed the existence of the two broken wires because they were in parallel with four other intact conductors.

The broken wires were spliced back together as a temporary repair.

The motor was reassembled and reinstalled on the "A" service water pump.

Immediately after the third motor start during post-maintenance testing, smoke was observed coming from the motor and breaker.

Investigation revealed the cause to be another, previously undiscovered, short circuit in the stator windings.

The breaker was inspected and found to be undamaged.

The motor was sent to a repair vendor for refurbishment.

I The refurbished motor was returned to the site on December 31, 1991 and reinstallation and acceptance testing was completed, and the pump was declared operable on January 4, 1992.

In light of the fact that all four service water pump motors were refurbished in 1977, and that the "D" pump motor also required refurbishment approximately one year ago, RG&E is scheduling refurbishing the two remaining pump motors during the upcoming outage.

In addition, a detailed analysis is being conducted to establish the root cause of the motor failur In summary, through in-depth troubleshooting of an apparently unrelated problem, the licensee identified a significant problem with the "A" service water pump motor.

The problem was promptly corrected, and strong management and technical support were evident throughout the effort. Through observation of the maintenance and testing, interviews with licensee personnel, and review of associated documentation, the inspector noted no deficiencies in this maintenance action.

3.1.2

"C" Safety Iqjection Pump Bus 14 Breaker As discussed in Inspection Report 91-23, Safety Injection (SI) accumulator relief valve 887 has been leaking.

Although this leak rate can be accommodated without compromising plant safety, this has increased the frequency at which water must be added to the SI accumulators.

Refilling the accumulators is accomplished using one SI pump for a short duration.

Consequently, an SI pump is being operated significantly more frequently than would normally be required.

The SI system has three pumps; a minimum of two pumps are required for the design basis accident.

To satisfy single failure criteria for loss of one of the 480V safety buses, the "C" SI pump motor can be powered from either bus 14 (breaker 1C2) or bus 16 (breaker 1C1).

The breakers are interlocked to prevent application of power from both buses simultaneously, as well as to prevent cross-connecting the buses.

The interlock functions through a relay which mechanically holds the breaker trip bar in the trip position while the breaker is open; ifthe interlock conditions are satisfied, this lockout relay willenergize and remove the mechanical hold on the trip bar when a breaker close signal is applied to the control circuitry. As the trip bar drops into the standby position, its position is mechanically sensed by a microswitch.

Once the trip bar has dropped sufficiently to avoid tripping the breaker, this microswitch closes, completing the circuitry to energize the breaker closing coil.

On January 16, 1992, when attempting to add water to the SI accumulators using the "C" SI pump powered from bus 14, the pump failed to start.

Upon releasing the pump control switch, the "C" SI pump breaker disagreement light on the main control board energized, indicating that the 1C2 breaker was open.

Investigation by the Auxiliary Operator revealed no obvious problems with the 1C2 breaker.

A second attempt was then made to start the pump from bus 14, and this time the pump started.

The 1C2 breaker was removed from bus 14 for troubleshooting on January 16.

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"C" SI pump could still be powered from bus 16, it nonetheless was considered inoperable because it no longer satisfied the single failure criteria for loss of bus 16.

Technical Specification 3.3.1.4 allows one SI pump to be inoperable for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> before requiring the reactor to be shut down.

Bench testing of the 1C2 breaker demonstrated an intermittent problem associated with the 1C1-1C2 breaker interlock.

Specifically, the microswitch which senses the position of the breaker trip bar was closing too soon to ensure that the trip bar would always be sufficiently

withdrawn to prevent it from tripping the breaker when the closing coil energized.

The tolerances in timing of the closing sequence were such that incomplete trip bar withdrawal was only infrequently a problem.

Technicians adjusted the mechanical linkage between the microswitch and the trip bar to slightly increase the amount of trip bar withdrawal required to close the microswitch.

Although bench and operational testing initiallyindicated that this had corrected the problem, the 1C2 breaker again failed to shut while attempting to add

'ater to the SI:accumulators on January 17.

Although the problem was known still to be with the 1C1-1C2 interlock, it could not be conclusively demonstrated that individual components were either operating properly or were defective, because of the lack of technical information in the vendor's manual.

Consequently, the subsequent corrective action consisted of replacing both the lockout coil and the trip bar microswitch.

Additionally, technicians adjusted the microswitch linkage to significantly increase the amount of trip bar withdrawal required to close the microswitch.

Bench and operational testing were completed satisfactorily, and "C" SI pump was declared operable on the evening of January 17.

The inspector observed portions of the breaker maintenance and testing.

Engineering support was immediately available throughout troubleshooting to compensate for the lack of vendor-supplied technical guidance.

No unsatisfactory conditions were noted.

As of the close of the inspection period, RG&E planned to modify a spare DB-50 breaker to replace the 1C2 breaker and to send the original breaker to the vendor for root cause analysis and overhaul.

3.1.3 Automatic Rod Control System As discussed in Inspection Report 91-27, deterioration of capacitors in the automatic rod control system out-motion speed controller prompted the licensee to perform an inspection of the equivalent capacitors in the in-motion speed controller.

Although no obvious degradation was noted, nine capacitors were replaced as a result of this inspection, based on concern for age-related deterioration.

On January 16, 1992, a problem occurred with the automatic rod control system in which control bank "D" was automatically inserted approximately 4.5 inches (7 steps) without valid system actuation inputs.

Operators promptly recognized the abnormal situation and stopped rod motion by placing the rod bank selector switch in the manual position.

Control bank

"D" was then restored to its original position.

The small amount of rod motion and prompt corrective action precluded any significant effect on plant parameters.

Performance Tests (PTs) 6.3.1, 6.3.2, 6.3.3, and 6.3.4, "Power Range Nuclear Instrument System Channels 41-44," had been completed approximately two hours before the problem occurred.

It was noted that the PT-6.3 series had also been completed shortly before the previous occurrence of 'rod motion due to automatic rod control system malfunction.

As of the end of the inspection period, further troubleshooting was planned to be performed in association with the next scheduled conduct of the PT-6.3 serie.1.4 Containment Particulate Radiation Monitor On January 5, 1992, a spurious failure of the containment particulate radiation monitor (radiation monitoring system (RMS) channel R-11) produced an Engineered Safety Features isolation signal to the containment ventilation system.

This had no effect on plant operations, since containment ventilation to the atmosphere was not in progress.

The R-11 failure also produced a radiation monitoring system process monitor high activity alarm.

The operators verified that containment radiation levels were normal by checking the remaining three containment RMS channels.

The installed backup particulate sample filter in the RMS containment sample line was also counted and indicated normal particulate activity. R-11 was then reset and appeared to operate normally.

Applicable portions of PT-17.2, "Process Radiation Monitors R-11 - R-22" were subsequently performed to verify proper operation of the channel and were completed satisfactorily.

RG&E contacted the vendor to pursue further troubleshooting.

The vendor stated that the code which had been displayed after the failure indicated that an anomalous processing condition had developed in the unit's microprocessor.

They further indicated that such a failure would probably not be reproducible, given that the unit operated normally after being reset.

Because R-11 serves a critical safety function, and because the cause of the malfunction could not positively be identified and corrected, a spare drawer was installed in the R-11 channel.

The drawer which experienced the failure willbe sent to the vendor for further troubleshooting.

The inspector concluded that RG&E's action to replace RMS channel R-11 was conservative and indicative of increased sensitivity towards problems associated with microprocessor-controlled equipment as had been established by the LEFM computer malfunction.

3.2 SurveBlance 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:

Undervoltage Protection, 480V Safeguard Buses, PT-9.1.16 and -9.1.17, Rev. 2, effective date December 10, 1991, observed on December 10, 1991 Auxiliary Feedwater Turbine Pump - Monthly, PT-16M-T, Rev, 1, effective date December 28, 1991, observed on January 8, 1992 Emergency Diesel Generator 1B, PT-12.2, Rev. 69, effective date November 26, 1991, observed on January 13, 1992

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3.2.1 Calorimetric Calibration The inspector observed the performance of Procedure 0-6.3, "Maximum Unit Power," Rev.

28, on January 13.

The Barton flowmeters were used as the source of. feedwater flow data.

This data is potentially less accurate than using the LEFM for two reasons:

first, the precision of the data is less than the LEFM; and second, the data is historic by the time the calorimetric is actually performed.

This is because the data must first be collected, then an average value calculated, and finally, this information must be manually entered into the plant computer.

When the calorimetric calibration is performed, the computer uses real-time values for the other parameters, whereas the feedwater flow data is somewhat older; in the observed case, approximately 15 minutes had elapsed from the time the first data point was taken until the calorimetric was performed.

As long as steady-state plant conditions existed between the time that the flow data was collected and when the calorimetric was actually performed, it did not significantly degrade the accuracy of the calibration.

Although the procedure specifies requirements for plant stability, the inspector noted that minimizing the time between collecting feedwater flow data and performing the calibration was not addressed.

This procedural weakness was discussed with RG&E management.

They agreed to clarify the procedure.

No other procedural or operational deficiencies were noted.

4.0 EMERGENCY PREPAREDNESS 4.1 Halon Are Suppression System Discharge At 8:56 AM on January 7, 1992, a fire alarm was received in the control room for the control building computer room.

The alarm also indicated that the associated halon fire suppression'system was discharging.

A plant announcement was made and the fire brigade was called to respond.

Eight minutes later, members of the fire brigade entered the computer room and determined that no fire had existed.

The halon fire suppression system, however, had discharged.

Desmoking equipment was set up to remove the halon and ventilate the room.

Compensatory measures were established until the fire suppression system was recharged with halon, which included a dedicated fire watch.

The false alarm and halon fire suppression system actuation had occurred during testing of an unrelated fire protection system.

The cause is unknown, although a similar event occurred

-. during fire protection system testing in October 1990.

The inspector concluded that the fire brigade response to the fire alarm had been satisfactory and that subsequent actions, including compensatory measures, had been appropriat.0 SECURITY 5.1 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.

6.0 ENGINEERING/TECHNICALSUPPORT 6.1 Containment Recirculation Fan Service Water Flow Indicator The containment building is cooled by four fan cooler units.

As well as maintaining habitability during normal operations, these units serve a safety function in that they would reduce the time that the containment building would be subject to maximum pressurization following the design basis accident.

The containment fan coolers are cooled by the service water system.

Calibration of the 1C containment fan cooler service water flow meter was performed on December 2, 1991.

During restoration from this procedure, it was noted that the meter was slow to respond after being placed back in service.

Work order 9102137 was prepared to clear the blockage in the two meter supply lines.

Because the service water system penetrates the containment building, portions of the system serve as containment isolation boundaries.

A technical evaluation was conducted to examine possible methods for clearing the meter supply line blockages in light of the possible containment isolation implications.

The conclusion of this evaluation was that, even though the meter isolation valves are excluded by Technical Specifications from containment isolation valve leak testing requirements, the valves "must be treated as containment isolation boundaries.

Accordingly, the maintenance procedure was written such that the valves would be leak-tested at greater than peak accident pressure prior to being operated in support of clearing the blockage.

Additionally, the procedure required that a pressure source capable of applying greater than peak accident pressure be connected and available at all times while the valves were being operated.

Additional engineering support was required during this maintenance when the originally specified maximum water'pressure of 150 psig was insufficient to clear one of the blocked lines.

Analysis of the design strength and configuration of the subject line indicated that 500 psig could safely be applied.

The procedure was changed accordingly, and the blockage was cleare The inspector reviewed the technical evaluations and considered them to be thorough and conservative.

The completed work package was also reviewed, with no significant discrepancies noted.

In conclusion, good engineering support was demonstrated for corrective maintenance on the "C" containment fan cooler service water flow meter.

7.0 SAFETY ASSESSMi2FT/QUALITY VERIFICATION 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 Reports for November and December, 1991 No unacceptable conditions were identified.

7.2 Licensee Event Report (LER)

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An LER submitted to the NRC was 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 was reviewed (Note: date indicated is event date):

91-009, Automatic Feedwater Control Perturbations Caused Steam Generator Feedwater Isolation on High Level, November 11, 1991 The inspector concluded that the LER was accurate and met regulatory requirements.

No unacceptable conditions were identified.

7.3 Plant Operations Review Committee Meetings During this inspection period, the inspector attended two Plant Operations Review Committee (PORC) meetings.

Due to holiday leave, one of these meetings was conducted with two members participating via conference telephone.

This meeting was appropriately limited in scope, and, in spite of the potential handicap of not having all members at the meeting in person, was effective and highly productive.

In both cases, the inspector observed that the

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meetings were conducted effectively with priorities established, candid discussions, and adequate resolution of pertinent issues.

Concerns and discussions were appropriately focused on safety-related items.

8.0 ADMINISTRATIVE 8.1 Backshift and Deep Backshift Inspection During this inspection period, backshift inspections were conducted on the following dates:

December 10 and 12, 1991.

Deep backshift inspections were conducted on the following dates:

December 21, 24, 29, and 31, 1991, and January 4, 12, and 18, 1992.

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.

A service water system operational performance inspection (SWSOPI) was conducted December 2-20, 1991 with an exit meeting on December 20. Mr. James Linville, Chief, Projects Branch No. 3 was onsite December 19-20, 1991 and attended the SWSOPI exit meeting.

The exit meeting for inspection report 50-244/91-29 was held on January 22, 1992 with the following individuals attending:

~Nm Title Thomas Moslak Edward Knutson Joe Widay Thomas Marlow Paul Gorski Andy Harhay Kenneth Lang Ron Jaquin Richard Marchionda Jeff Wayland Clair Edgar Terry Schuler Alan Jones Mark Shaw Robert Wood Sr Resident Inspector-NRC Resident Inspector-NRC Plant Manager-RG&E Superintendent, Ginna Production-RG&E Manager, Mechanical Maintenance-RG&E Manager, HP & Chemistry-RG&E Health Physicist-RG&E Engineer NS&L-RG&E Superintendent, Support Services-RG&E Reactor Engineer-RG&E Manager, Electrical Maintenance/I&C-RG&E Operations Manager-RG&E Corrective Action Coordinator-RG&E Manager, Material &Procurement-RG&E Supervisor, Nuclear Security-RG&E

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