IR 05000244/1991014
| ML17262A564 | |
| Person / Time | |
|---|---|
| Site: | Ginna  |
| Issue date: | 07/16/1991 |
| From: | Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17262A563 | List: |
| References | |
| 50-244-91-14, NUDOCS 9107240211 | |
| Download: ML17262A564 (25) | |
Text
U. S. NUCLEAR REGULATORY COINKOSSION
REGION I
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Inspection Report 50-244/91-14 License: DPR-1S Facility:
R. E. Ginna Nuclear Power Plant Rochester Gas and Electric Corporation (RGAE)
Inspection:
Inspectors:
May 21 through June 24, 1991 T. A. Moslak, Senior Resident Inspector, Ginna N. S. Perry, Resident Inspector Ginna A. R. Johnson, Project Mana r, NRR Approved by:
cCabe, Chief, eactor Pro ection 3B INSPECTION SCOPE at s
Plant operations, radiological controls, maintenance/surveillance, emergency preparedness, security, engineering/technical support, and safety assessment/quality verification.
INSPECTION OVERVIEW GGD'i,: GP,,p dK II I
ly ldpp,,e; d
G;I d turbine control valve controller, to a T-avg channel deviation, and to two rod control system abnormal responses.
However, operators did not assure that the Overpressure Protection System remained in service during a plant start-up.
~di i:G I
d ill I I
<<lylpl Maintenance/Surveillance:
Response to cooler fouling by zebra mussels was timely and appropriate.
A poor surveillance practice was corrected.
Emer enc Pre arednes:
An Emergency Medical Drilland a simulator-driven, practice Emergency Drillwere conducted with no major deficiencies identified.
~ecurit:
Security personnel performance and equipment conditions were acceplabie.
En ineerin /Technical u
r: Support for replacing cut control power lines for a standby auxiliary feedwater recirculation valve was adequate.
Control over wooden scaffolding was weak.
Safet Assessment/
ualit Verification: Surveillances and audits of control room activities were satisfactorily performed and effective.
9l07240 ll 9107l6 PDR AD8CK v5000244
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TABLEOF CONTENTS INSPECTION OVERVIEW......................,.............,
TABLE OF CONTENTS................................
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1.0 PLANT OPERATIONS 1.1 Operational Experiences............. ~........
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1.2 Control, of Operations.......'...............
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1.3 Reactor Coolant Average Temperature Deviation.............
1.4 Rod Control System Abnormal Response 1.5 Overpressure Protection System Operability......... ~....,
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1.6 (Closed) Unresolved Item (50-244/91-10-01) Missed Physical Examination.........,.......,..........
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1.7 (Closed) Unresolved Item (50-244/89-80-03) Accessibility Of Valves 1.8 (Closed) Violation (50-244/90-31-01) Inadequate Procedure M48.14
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2.0 RADIOLOGICALCONTROLS 2.1 Routine Observations 2.2 Organizational Change
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3.0 MAINTENANCE/SURVEILLANCE 3.1 Corrective Maintenance.........................
3.1.1 Zebra Mussel Shells In Service Water Coolers.......
3.1.2 (Closed) Violation (50-244/91-07-03) Failure To Properly Preplan And Coordinate Valve Repacking 3.2 Surveillance Observations.................
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7 4.0 EMERGENCY PREPAREDNESS................ ~........
4.1 Medical Drill................. ~...............
4.2 Emergency Mini-drill
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5.0 SECURITY 5.1 Routine Observations
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8 6.0 ENGINEERING/TECHNICALSUPPORT.............;......
6.1 Battery Room Scaffold 6.2 Standby Auxiliary Feedwater Recirculation Valve Modification...
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7.0 SAFETY ASSESSMENT/QUALITY VERIFICATION 7.1 QA Surveillance and AuditReports....................
7.2 Quality Assurance/Quality Control (QA/QC) Subcommittee Meeting 7.3 Periodic Reports
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Table of Contents 8.0 ADMINISTRATIVE ~....,...
8,1 Inspection Hours......
8.2 Exit Meetings......
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8.3 NRC Chairman Carr Visit 8.4 Management Changes...
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1.0 PLANT OPERATIONS DETAILS 1.1 Operational Experiences Throughout the inspection period, the plant operated at approximately 97% power with one exception.
On May 25, the Number 2 Turbine Control Valve failed closed, causing a power reduction of approximately 10%. A failed circuit card was replaced and the plant was returned to about 97% power six hours later.
1.2 Control of Operations Overall, the inspectors found the R. E. Ginna Nuclear Power Plant was 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.
No inadequacies were identified.
1.3 Reactor Coolant Average Temperature Deviation On June 5, the inspectors were informed of a deviation of greater than 5% between the highest and lowest main control board indications for Reactor Coolant System (RCS) average
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temperatures.
Instrumentation and Control (I&C) personnel found that an amplifier associated with the lowest indicating channel (401) needed to be rescaled.
The amplifier was rescaled and returned to service.
It was later determined that, prior to the turbine control valve failure on May 25, Channel 401 was indicating higher than the other channel for the same RCS loop and that, after the turbine control valve failure, the indication for Channel 401 decreased approximately 1.5'F.
I&C personnel have not been able to explain the decrease in indication, but did conclude that the output of the RTDs was not at fault.
Plans are to simulate a temperature change comparable to that which occurred to the suspect amplifier on June 5 to see ifthe temperature shift recurs and to correct any identified deficiencies.
The inspectors concluded that actions taken have been conservative and appropriate.
1.4 Rod Control System Abnormal Response On June 7, operators were attempting to manually move the control rods to adjust reactor coolant temperature when it was noted that the two Bank D group step counters had a two step deviation.
Operators immediately entered the abnormal procedure for control rod malfunctions and contacted Instrumentation and Control (I&C) personnel.
Operators and I&C technicians verified that the rods were moving, then performed the surveillance test
twice to confirm operability.
Plant management instructed that the frequency of the monthly surveillance be increased.to weekly. INC personnel suspected that the problem was in the power cabinet for Bank D. They prepared a maintenance work package to monitor various test points associated with that bank.-
During performance of the control rod surveillance ori June 24, operators observed a similar problem with a shutdown bank group.
Since the shutdown banks are controlled by a different power cabinet, IAC personnel deduced that the problem may be associated with the master cycler in the logic cabinet.
The master cycler sequences the groups within a rod bank to insure that those rod groups remain within one step of each other.
At the end of the inspection, ISAAC personnel were investigating various monitoring points within the logic cabinet.
Through discussions with maintenance management, the inspectors concluded that the control rods were operable at all times in that they would fall into the core upon a reactor trip. The f'ctual rod position indicating system was also operable at all times.
The significance of th ailure of a group of rods to properly move when demanded is that a reactor trip might not be c
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avoided during certain load loss conditions.
The inspectors concluded that the actions taken and planned by 'plant personnel were appropriate and well thought out.
"1.5 Overpressure Protection System Operability During plant heat-up activities on May 7, 1991, control room operators were to maintain reactor coolant cold leg temperatures within the operating band of greater than 330'F and less than 350'F when the Overpressure Protection System (OPS) was removed from service.
Temperatures were to be maintained within this range until various surveillance tests were
.performed on the Auxiliary Feedwater (AFW) System and the Standby AFW System.
Upon successful completion of these tests, heat-up above 350'F could be resumed.
Upon reviewing cold leg temperature data during shift turnover; the oncoming Head Coritrol Operator determined that the RCS 'A'oop Cold Leg Temperature recorded on the Control Rod Shutdown Log Sheets was 329'F or 330'F at various times between about 2:48 PM and 10:00 PM when the OPS was removed from service.
This was contrary to Operating Procedure 0-1.1, "Plant Heat-up from Cold Shutdown or Refueling Shutdown to Hot Shutdown," Revision 104, effective May 2, 1991, which does not permit cold leg temperatures at or below 330'F unless the OPS was in service.
Technical Specification (TS) 3.15.1 states that, ifthe cold leg temperature is less than or equal to 330'F, the OPS is to be operable or, within eight (8) hours, the RCS is to be depressurized and vented until the OPS has been made operable.
Upon discovery of this condition, the Control Room operators raised cold leg temperature above 330'F and notified plant management.
Plant management expeditiously initiated a Human Performance Enhancement System (HPES) evaluation to determine causes, develop corrective actions, and assess safety significanc y4
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Based on the HPES evaluation, the underlying cause was that Control Room operators focused their attention on maintaining a cold leg temperature of less than 350'F and did not remain cognizant of the minimum temperature requirement.
The relevant operating procedure, 0-1.1, was found to lack clear guidance in precautionary statements and in the operating instructions to ensure that the operating shift is fully aware of the 330'F lower limit. 0-1.1 is being revised to include definitive precautionary information and an operator sign-off step in the instructions to ensure that cold leg temperatures are maintained greater than 330'F with the OPS removed from service.
Site management concluded that there were no safety consequences resulting from operating at or slightly below 330'F for a restricted time (approximately 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and 12 minutes)
because plant conditions were such that the OPS was not needed.
The OPS is designed to mitigate pressure transients when the Reactor Coolant System (RCS) is water solid, i.e.
without a steam bubble in the pressurizer, and to ensure that no overpressurization of the Residual Heat Removal (RHR) System could occur, when the RHR System is unisolated.
None of these conditions were present.
The RCS was not water solid. A bubble was formed in the pressurizer and RCS pressure was being controlled at 325 psig by use of Pressurizer heaters or sprays.
Both reactor coolant pumps were running and the RHR System was isolated.
Since RCS pressure was being controlled and the PORVs were at their operational setpoint (2235 psig), RG&E management will evaluate revising TS 3.15 to clarify the suitability of placing the OPS in service should RCS cold leg temperature be less than or equal to 330'F with a steam bubble in the pressurizer.
TS 3.15 requires that at least one of the following overpressure protection systems be operable whenever the temperature of one or more of the RCS cold legs is less than or equal to 330'F:
Two pressurizer power operated relief valves (PORVs) with a liftsetting of < 435 psig, or A reactor coolant system vent of > 1.1 square inches.
The about 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and 12 minutes during which the OPS was not in service was within the eight (8) hour limit specified in TS 3.15.1.2 which states, "With both PORVs inoperable, depressurize and vent the RCS through a 1.1 square inch vent(s) within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />; maintai'n the RCS in a vented condition until both PORVs have been restored to operable status."
Accordingly, the Technical Specification specified action point was not reached.
The inspectors reviewed the circumstances resulting in this incident and the licensee's response.
Through examination of 0-1.1, the inspectors concluded that the procedure, in the
"PRECAUTIONS" and in the operational "INSTRUCTIONS" sections, contained confusing information and lacked clear statements informing the operators that Cold Leg temperatures were not to be equal to or less than 330'F with the OPS removed from servic The inspectors concluded that this procedure inadequacy contributed to operators not being cognizant of this-requirement.
Through observation of the licensee's response to this incident, the inspectors also concluded that the situation was identified by the licensee in a timely manner and that a comprehensive evaluation was expeditiously performed.
To prevent recurrence, procedure change notices to 0-1.1 are being reviewed by the licensee's staff and revisions to TS 3.15 are under evaluation.
There is minor safety significance to not maintaining cold leg temperatures greater than 330'F for a limited time period since the plant was configured for normal pressure control using the pressurizer.
Under 10 CFR 2, Appendix C, Article V.G.1, a violation. was not cited because the incident was licensee identified, of moor safety significance, evaluated for reportability, immediate corrective measures and actions to prevent recurrence were appropriate, and the occurrence was not identified as willfulor as preventable through corrective action on a prior violation (50-244/91-14-01).
1.6 (Closed) Unresolved Item (50-244/91-10-01) Missed Physical Examination This item remained unresolved pending implementation of actions to prevent recurrence.
Actions taken included setting up a data base to issue reminders two months and one month prior to the exam due date to serve as a check to ensure all physicals are scheduled.
These reminders will be distributed to several managers, who will also be notified when an, individual completes the physical examination.
Additionally, operators will be sent a printout, at the beginning of each year, specifying when their physical is due for the year.
The inspectors concluded that the corrective actions were appropriate and sufficient.
Under 10 CFR 2, Appendix C, Article V.G.1, no violation was cited since this event was identified and reported by the licensee, is a minor (Severity V) violation, was promptly corrected, was not found to be willfulor preventable through corrective action on a prior violation, as detailed in NRC Inspection Report 50-244/91-10, and actions to prevent recurrence were appropriate.
1.7 (Closed) Unresolved Item (50-244/89-80-03) Accessibility Of Valves This item remained open pending the establishment of documentation by RGAE concerning the installation of platforms to allow easy access to the steam generator atmospheric relief valves and the steam supply valves for the turbine-driven auxiliary feedwater pump.
RG8cE has initiated Engineering Work Request EWR ¹5277 for the installation of a permanent steel platform allowing access to the steam supply valve for the turbine-driven auxiliary feedwater pump, and a steel platform safety ladder anchored to the floor to access the steam generator atmospheric relief valve.
The instal]ations are scheduled to be complete by May 1992.
The inspectors had no further concern '
1.8 (Closed) Violation (50-244/90-31-01) Inadequate Procedure M48.14 In December 1990, Procedure M48.14, "Isolation of Bus 14 Undervoltage System for Maintenance, Troubleshooting, Rework, and Testing," Revision 8, was implemented as written, disabling Engineered Safety Feature Actuation System (ESFAS) instrumentation for twenty minutes while the reactor was at 3% -power, and resulting in a reactor trip.
Subsequently, the Operations and Maintenance Departments extensively revised M48.14 to correct the inadequacies.
Following review and approval by the Plant Operations Review Committee, Revision 9, was issued for use effective May 17, 1991.
The inspector reviewed this revision and determined that the procedural steps resulting in the disabling of ESFAS instrumentation (directing personnel to "Open DC circuit breakers for
'A'nd 'B'afeguard logic trains") were removed.
Detailed guidance was also provided to Control Room Operators on actions to preclude a reactor trip when transferring the
'B'nstrument bus to a maintenance power supply.
The inspector reviewed the maintenance procedure for redundant bus 16, M48.13, "Isolation of Bus 16 Undervoltage System for Maintenance Troubleshooting, Rework, and Testing,"
Revision 11, effective May 17, 1991.
Through this review, the inspector determined that this procedure was revised in parallel with M48.14, had an increased level of detail, and reflected the upgrades made to M48.14.
Although M48.13 did not contain the inadequacies found in M48.14, the actions taken by the licensee to improve its content in parallel with revision of M48.14 were assessed as prudent.
The inspector had no additional concerns on this item.
2.0 RADIOLOGICALCONTROLS 2.1 Routin'e Observations The resident inspectors periodically confirmed that radiation work permits were effectively implemented, dosimetry was correctly worn in controlled areas, dosimeter readings were accurately recorded, access to high radiation areas was adequately controlled, and postings and labeling complied 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 Organizational Change On June 1, 1991, Mr. Andrew Harhay was assigned as the Manager, Health Physics and Chemistry replacing Mr. Duane Filkin '
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3.0 MAINTENANCE/SURVEILLANCE 3.1 Corrective Maintenance 3.1.1 Zebra Mussel Shells In Service Water Coolers On June 20, 1991, R.E. Ginna experienced its first operational impact due to the presence of zebra mussels.
Operators removed Emergency Diesel Generator EDG-B from service for maintenance personnel to investigate the cause of a high differential pressure across the diesel service water coolers.:Each EDG has two service water coolers in series, one for the lube oil system and one for the jacket water cooling system.
The jacket water cooler is second and has smaller diameter tubes, through which the service water flows. When the coolers were opened, numerous apparently dead zebra mussel shells were found in the jacket water cooler.
Plant personnel suspect that the tubes in the lube oil cooler are large enough to permit passage of the shells, but that the tubes in the jacket water cooler are not.
The cause of the shells was attributed to recent chlorination of the service water system.
It is estimated that zebra mussels can survive for 8-10 days in chlorinated water.
The chlorination process was begun 9 days before the observed high differential pressure.
Service water pumps were rotated just prior to the observed high differential pressure and that action could have accelerated the dislodging of the shells.
After the EDG-B coolers were cleaned and the EDG was returned to service, EDG-A was removed from service to check its service water coolers.
A similar problem was observed and the same actions were taken.
Plant personnel immediately initiated a surveillance of all service water system coolers for indications of high differential pressures.
Differential pressure readings were recorded twice per eight-hour shift and data was trended.
Maintenance personnel prepared work packages for service water coolers to expedite any necessary work.
High differential pressure was observed again on June 21 for EDG-A. The inspectors observed the cleaning of the jacket water cooler and estimated that about 2-3 cups of shells were present.
Normal differential pressure is 15-20 psi; action is taken when the differential pressure reaches approximately 25 psi.
The highest differential pressure recorded was 45 psi for EDG-B on June 20.
RG&E engineering began evaluating the maximum allowable differential pressure across the service water coolers for EDG operability.
Long term plans are to continue monitoring the service water system differential pressures closely and to evaluate the present method of continuously chlorinating the circulating water and service water systems for 18 days, four times a year.. RGB's negotiating with the New York Department of Environment Conservation to allow full time chlorination of at least the
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service water syste '
I The inspectors concluded that the actions taken in response to the high service water differential pressures were timely and appropriate.
Very good upper and middle plant management involvement was observed.
Action taken to monitor and prepare for problems were assessed as conservative and comprehensive.
3.1.2 (Closed) Violation (50-244/91-07-03) Failure To Properly Preplan And Coordinate Valve Repacking This violation concerned maintenance that could affect safety-related equipment performance not being properly procedurally established and implemented.
Component Cooling Water Valve V-738B was not properly isolated prior to maintenance.
The inspectors reviewed associated procedural changes and concluded that the concerns were adequately addressed.
Additionally, a licensee task force was organized to reduce potential isolation boundary problems.
The inspectors had no further concerns.
3.2 SurveBlance Observations Inspectors observed portions of surveillances for proper calibration of test instrumentation,
'se of approved procedures, performance of work by qualified personnel, conformance to Limiting Conditions for Operation (LCOs), and correct system restoration following testing.
The followin surveillances were observed:
g Periodic Test (PT)-16Q, Auxiliary Feedwater System - Quarterly, Revision 9,
effective April 12, 1991, observed June 6, 1991 No safety significant discrepancies were noted; however, the inspectors observed a
poor practice while personnel were verifying a check valve position.
The indicator had been bent previously, and the technician performing the verification relied on past experience with the direction the position indicator-was pointing.
When questioned by the inspector, the technician stopped the surveillance and notified management.
Management instructed the technicians to positively verify the position of the check valve by manipulating it before continuing with the surveillance.
Management stated that the position indicator would be corrected and that the surveillance procedure would be strengthened, prior to its next scheduled use, to be more specific concerning how to verify the position of the check valve.
The inspectors had no further questions.
PT-1, Rod Control System, Revision 28, effective October 20, 1989, observed June 7, 1991 and June 24, 1991 No unacceptable conditions were identifie.0 EMI<MGENCYPREPAREDNESS 4.1 Medical Drill On June 5, 1991, RGB'onducted the annual Emergency Medical Drill, which was observed by FEMA. Part One of the drill simulated transporting two injured, contaminated workers from the Ginna site to a hospital.
Part Two simulated an individual entering an off-site monitoring radiological point at a local high school who was contaminated and injured.
No major deficiencies were noted.
4.2 Emergency Mini-drill A simulator-driven, practice Emergency Drillwas conducted on June 19, 1991.
This was first Ginna'simulator use as a real-time interface for an emergency drill. Operations personnel found the drill to be more realistic. Allmajor drill objectives were met.
The inspectors observed portions of the drill and identified no major difficulties.
5.0 SECURITY 5.1 Routine Observations During this inspection, the resident inspectors found 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 Battery Room Scaffold During routine plant tours during the week of June 3, the inspectors noticed degradation of the scaffolding in Battery Room A. Scaffolding above the batteries is constructed of wood held together by nails.
The inspectors noted that some of the boards had started to split and others were starting to pull apart.
The original installation of the scaffolding was estimated to be for approximately 8 weeks; however, when observed by the inspectors, they had been in place for about 4 months.
After installation in early February 1991, the scaffolding was inspected as required.
The inspectors were concerned that no inspections had been performed since installation and deterioration was apparent.
This scaffolding is required to be installed in accordance with engineering-specified seismic guidelines because of its location over the vital batterie Plant management stated that the controls for scaffolding willbe changed in the near future.
Currently the controls are covered by an Administrative Procedure for temporary structural features.
Plans are to have the controls for scaffolding separated from this'procedure.
During this process, management willevaluate how periodic inspection of the installed scaffolding willbe handled.
The inspectors concluded that the lack of periodic inspection of installed scaffolding was a weakness in the program for the control of temporary scaffolding.
Immediate corrective action of inspecting the installed wood scaffolding and determining that it still met seismic criteria were adequate, and long-term plans of transferring control of scaffolding to its own procedure appear appropriate.
Pending further review of facility controls over temporary structures which could fail and adversely affect safety equipment, this item is unresolved (UNR 91-14-02).
6.2 Standby Auxiliary Feedwater Recirculation Valve Modification On June 3, while core drilling for an alternate cooling modification near Standby Auxiliary Feedwater Pump C, a conduit containing control power lines for the pump's recirculation valve was inadvertently cut.
The valve and pump were declared inoperable, a
nonconformance report was generated, and engineering evaluation for repairs was initiated.
The existing cable was pulled from the existing conduit; a new conduit with cable was seismically installed and connected to the cabinet and terminal box.
The final installation was properly tested prior to returning the pump and valve to an operable status.
The inspectors reviewed the closeout of the nonconformance report and the final installation of the seismically supported conduit and identified no unacceptable conditions.
7.0 SAFETY ASSESSMENT/QUALITY VERIFICATION 7.1 QA Surveillance and Audit Reports The inspector reviewed several QA surveillance and audit reports of surveillance/audits by the licensee of control room operational activities and effectiveness in implementing QA Program requirements.
The inspector reviewed reports/audits performed on 1) operator performance during low loop level conditions; 2) low power physics testing (1991 refueling outage);
3) diesel-generator load and safeguards sequence testing; 4) RHR system check valves full flow operability verification, and 5) proper controls being administered during station QA audits/surveillances of control room operations.
The following documents were reviewe BATE Re rt No.
Date Performed 91-023 TLA 91-014 JWO 91-038 LEO 91-044 FFR 91-042 FFR-91-06 GFS 3/26-29/91 4/21-25/91 5/9-10/91 4/29-30/91 3/29/91 4/23/91 The inspector observed that Audit/Surveillance Reports91-014 JWO and 91-024 TLA on operator performance during plant low loop level conditions found good shift turnover and interaction among operators, good response to unanticipated annunciators, and proper handling of conditions during board modifications and processing of procedure change notices (PCNs).
Two concerns resulted in several QA Observation Reports (QAORs) which identified weaknesses in control room notifications and the need for associated procedural changes.
The 91-014 JWO QA audit activity was reinitiated under 91-024 TLA QA Surveillance activity when the second low loop level was entered (1991 refueling outage) on April 21, 1991, and supports the 1991 Outage Audit 91-14 JWO which assessed the control room activities for entering, maintaining, and leaving the first low loop level plant condition on March 26-29. 1991.
All QAORs are, or are in the process, of being adequately dispositioned.
Report 91-038 LEO found that plant operators properly executed the chemistry requirements for RCS sampling and analysis.
Several QAORs were written to track concerns regarding completed steps in procedure PT-34.1 should criticality occur before procedure completion.
Also, a concern was expressed about the temporary recorder location during RK-45 recorder upgrading.
That location required operators to turn their backs to the control board to observe reactor power trends.
The inspector observed that Report 91-044 FFR found that control room operators responded in a timely manner, during diesel generator load and safeguards sequence testing, to annunciators and communications between control room personnel and the plant Results and Test group.
No Audit Finding Corrective Action Reports (AFCARs) or QAORs were identified during this surveillance.
The inspector reviewed Report 91-042 FFR which addressed RHR system check valve (e.g.
testing of seven valves) full flow operability verification testing.
The documented report indicated control room personnel adequately performed. their duties with regard to communications with Results and Test group personnel and annunciator response.
This
'urveillance also supported the 1991 outage Audit 91-014 JWO with regard to these check valves.
No AFCARs or QAORs were identifie '
The inspector reviewed Report 91-06 GFS documenting an April 1991 audit performed on the Ginna Station operations and testing.
Audit results were noted to be satisfactory and indicated proper controls were being administered in the areas of operations and test.
Two AFCARs and two QAOR's were identified.
Significant was the AFCAR which identified insufficient. technical and human factor content in Procedure T-41A/47 with regard to AFW system alignment and procedure S30.4/42 AFW system valve and breaker position verification.
Corrective action is currently being finalized by corrected procedures.
The NRC inspector concluded that the above noted QA surveillances and audits of the Ginna Station control room activities:
1) are being performed satisfactorily in a manner which supports quality, safety, and reliability; and 2) show proper controls are being administered during QA surveillance/audits and are effective in implementing QA program requirements.
7.2-Quality Assurance/Quality Control (QA/QC) Subcommittee Meeting On May 22, 1991, the inspector attended the quarterly meeting of the RG&E corporate QA/QC subcommittee.
The inspector observed that the meeting was well attended by plant and corporate management.
Discussions were open and candid on the nature and status of audit findings, with good participation by all members.
Corporate management identified particular weaknesses in the methodology used for trending quality performance indicators; i.e. the'number of Audit Finding Corrective Action Reports (AFCARs) and Non-
'onformance Reports (NCRs).
Actions were assigned to responsible individuals to provide a more meaningful technique of interpreting this information to make it a more effective.
management tool.
The inspector had no further questions on these matters.
7.3 Periodic Reports Periodic reports submitted by the licensee pursuant to Technical Specifications 6.9.1 and 6.9.3 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 report was reviewed:
Monthly Operating Report for May 1991.
No unacceptable conditions were identified.
8.0 ADMINISTRATIVE 8.1 hispection Hours This inspection included 7 backshift and 3 deep backshift hour '
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, an NRC exit meeting on June 'f, 1991 was held for Inspection 50-244/91-80, Electrical Distribution System Functional Insertion.
The exit meeting for this Inspection Report, 50-244/91-14, was held on J'une 26, 1991 with the following individuals attending:
Name Title Thomas Moslak Neil Perry Clair Edgar Paul Gorski John St. Martin Terry Schuler Joseph Widay Senior Resident Inspector-NRC Resident Inspector-NRC Mgr. Electrical/I&C-RG&E Mgr. Mech. Maintenance-RG&E Corrective Action Coordinator-RG&E Operations Manager-RG&E Plant Manager-RG&E 8.3 NRC Chairman Carr Visit
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On June 5, 1991, U.S. Nuclear Regulatory Commission Chairman Carr met with plant management and staff and toured the Ginna facility.
8.4 Management Changes Effective June 13, Mr. Joseph Widay was promoted to Plant Manager-Ginna Station.
He replaced Mr. Stanley Spector, who became Director-Gas & Electric Emergency Coordination.
Mr. Thomas Marlow became Superintendent-Ginna Production, replacing Mr. Widay, and Mr. Richard Marchionda was promoted to Superintendent-Support Services, replacing Mr. Marlow.
On June 19, RG&E announced the immediate resignation of Mr. Harry Saddock as Chief Executive Officer due to poor health.
Mr. Roger Kober, President and Chief Operating Officer, assumed the duties of Chief Executive Officer.
Mr. Saddock will remain Chairman of the Board until the end of the yea ~ ~
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