IR 05000244/1991027

Insp Rept 50-244/91-27 on 911105-1209.Vo Violations or Programmatic Weaknesses Identified.Major Areas Inspected: Plant Operations,Radiological Controls,Maint/Surveillance, Ep,Security & Safety Assessment/Quality Verification

ML17262A717
Person / Time
Site:	Ginna
Issue date:	12/23/1991
From:	Lazarus W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML17262A716	List: IR 05000244/1991027 ML17262A715
References
50-244-91-27, NUDOCS 9201070059
Download: ML17262A717 (28)

Text

U. S. NUCLEAR REGULATORY COMMISSION

REGION I

Inspection Report 50-244/91-27 License: DPR-18 Facility:

R. E. Ginna Nuclear Power Plant Rochester Gas and Electric Corporation (RGB')

Inspection:

Inspectors:

November 5, 1991 through December 9, 1991 H

T. A. Moslak, Senior Resident Inspector, Ginna E. C. Knutson, Resident Inspector, Ginna Approved by:

W.

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

INSPECTION OVERVIEW

ll,l lip l

HP R.p.pl R

\\

P Pl P

operated safely and in compliance with regulatory requirements.

Control room staffing was as required.

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.

Operators responded promptly and correctly to stabilize the plant on two separate occasions.

Plant stability was challenged during troubleshooting to identify the source of electrical interference in the feedwater control system, and following a lube oil level detector failure on turbine EH system.

The actions taken by RGEcE in response to the increased inleakage rate to containment sump "A" were were conservative and presented a well-developed and realistic balance between operational and ALARAconcerns.

Some questions were raised regarding operator knowledge of the functions of the rod bank selector switch.

Operator error resulted in inadvertently shutting down an emergency diesel generator during a surveillance test.

~Ch l:Hllp I

I

l lylpl e.AA briefings made to personnel prior to making a containment entry were detailed and effective for minimizing dose.

The licensee provided well organized, detailed ALARAtraining to maintenance and HP personnel to improve worker awareness of proper techniques for lowering dose and minimizing the spread of contamination.

9201070059 9i 1224 PDR ADOCK 05000244

M int nan e/

rveillan:

Measures to correct spurious signals in the rod control system were expeditiously performed.

However, there were inconsistencies in operators'

understanding the proper position for the rod bank selector switch.

Although mode of operation of the rod control system has limited safety significance and is not specifically addressed in plant technical specifications, operator misunderstanding as to its condition could increase the challenge posed to the plant by a transient.

Emer enc Pre aredness:

There were no challenges to the emergency response organization

, other than a medical emergency drill,which demonstrated good coordination between the control room and the site medical response team in the care of an injured individual.

En ineerin /Technical Su ort:

Actions taken to identify and eliminate the spurious signals affecting Advanced Digital Feedwater Control System (ADFCS) were well coordinated between the respective departments and the operators acted promptly and stabilized the plant following the disruption in ADFCS contro OVERVIEW TABLEOF CONTENTS

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

TABLE OF CONTENTS

~

~

~

~

~

~

~

~

~

~

~

~

~

~ nl

'.0 PLANT OPERATIONS..............:,.............

1 ~ 1 Operational Experiences 1;2 Control ofOperations.........................

'1.3 Main Turbine Electrohydraulic Control System Pump Lockout 1.4 Unidentified Changes in Inleakage to Containment Sump "A"

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

1

1

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

2.1

-

Routine Observations 2.2, Consolidated Maintenance/Health Physics Team ALARATraining 2.3

'Secondary Chemistry Monitoring Program Inspection

~

~

~

~

~

~

~

~

~

~

3

4 3.0 MAINTENANCE/SURVEILLANCE 3.1 Corrective Maintenance 3.1.1 Automatic Rod Control System 3.2 Surveillance Obser vations 3.2.1 Emergency Diesel Generator 1A 3.2.2

"A" Reactor Trip Breaker'....

~

~

~

~

~

~

~

~

Performance Test

~

~

~

~

~

~

~

~

~

~

~

~

~

~

\\

~

~

~

5

6

4.0 EMERGENCY PREPAREDNESS

.4.1:-

Medical Emergency Drill

~

~

~

~

~

5.0 SECURITY 5.1 Routine Observations

~

~

~

~

~

8 6.0 ENGINEERING/TECHNICALSUPPORT 6.1 Spurious Signals in the'Advanced Digital Feedwater Control System (ADFCS)

e

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

6.2 Safety Injection System Pump Recirculation Flow 6.3 Containment Equipment Hatch Leakage..................

~

~

~

P

~

~

9

7.0 SAFETY ASSESSMENT/QUALITY VERIFICATION 7.1 Periodic Reports...................

7.2 Spent Fuel Pool Material Storage... ~.....

7.3 Auxiliary Feed Water System Walkdown....

7.4 Winterizing Inspection 7.5 Management Meetings

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

~

11

12

13 8.0 ADMINISTRATIVE.....................

8.1 Backshift and Deep Backshift Inspection 8.2 ExitMeetings.....................

~

~

13

111

DETAILS 1.0 PLANT OPERATIONS 1.1 Operational Experiences The plant operated at approximately 97% power throughout the inspection period.. A momentary power reduction of 0.5% was experienced during an anticipated transient that occurred while troubleshooting electrical interferences in the feedwater control system.

(Details in 6.1)

1.2 Control of Operations Overall, the inspectors found the R. E. Ginna.Nuclear Power Plant to be operated safely and in compliance with regulatory requirements.

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 significant inadequacies were identified.

1.3 Main Turbine Electrohydraulic Control System Pump Lockout The main turbine electrohydraulic (EH) control system controls the speed and power of the main turbine, and also provides rapid turbine shutdown (trip) capability.

The system operates using pressurized oil to position the valves which admit steam to the high-and low-pressure turbines.

The system includes two oil pumps for maintaining oil pressure; during normal operation, one pump is running and the other is in a standby condition such that it will automatically start ifthe running pump fails.

Four accumulators will maintain system pressure for a short period of time in the event that both pumps fail, but ifthe pumps cannot be returned to service promptly, oil pressure will rapidly bleed down and the control and stop valves will shut.

On November 17, the Main Turbine Electrohydraulic (EH) Control System oil reservoir low level pump lockout annunciator in the Control Room energized.

This was an abnormal situation, since the EH oil reservoir high-low annunciator should have alarmed first ifan actual loss of oil level was occurring.

The control room operators immediately saw that neither EH pump was running and attempted to start the standby pump.

The pump did not run, indicating that an actual lockout condition had occurred.

At about the same time, the EH Control System oil reservoir low level pump lockout annunciator cleared.

The pump lockout, however, remained in effect because the lockout relay must be manually reset.

The

Shift Supervisor realized this, and promptly reset the low fluid level lockout relay, located on the back of the Main Control Board.

When this was done, both EH pumps started.

Oil reservoir level was verified locally and EH system configuration was restored to normal.

The cause of the EH pump lockout was a degraded oil reservoir level detector.

The detector which is used in this system is a magnetrol mercury bottle; changes in oil reservoir level cause the mercury to shift, which makes or breaks an electrical contact.

Vibration due to system operation apparently caused such a shift, resulting in a pump lockout signal being generated; that the annunciator cleared and the lockout relay was able to be reset indicated that the level detector had undergone only a momentary shift, and then had returned to its normal state.

Subsequent troubleshooting revealed the level detector to be defective.

As a result, an installed spare detector was placed in service.

The operators'knowledge and prompt action quickly corrected a problem that could have rapidly degraded into a main turbine and reactor trip.

1.4 Unidentified Changes in Inleakage to Containment Sump "A" On November 20, an increase was noted in the calculated inleakage rate-to containment sump

"A". The inleakage rate. over the previous two months had been relatively constant at about 0.01 gpm.

The new calculated inleakage rate was 0.059 gpm.

Based on chemical/radiochemical analyses of the sump water, as well as reactor coolant system leak rate calculations, the source was believed not to be primary coolant.

This, along with a previous history of service water leaks from the containment fan cooler units, made the service water system the most likely source of the increased leakage.

On Friday, November 22, the decision was made to enter containment to search for the

'source of the leak.

This was considered preferable to isolating service water to individual components because the leak rate was so low; long periods (on the order of days per component) with service water isolated to individual safety-related components would be

.

required before the source of the leak could be identified.

Because the leak rate was so low, it was also decided to defer entry until after the weekend in support of ALARA considerations; deferral would allow containment purge to be used, thereby reducing the concentration of radioactive gases by about 50%.

A containment entry was made on Tuesday, November 26, to inspect the fan cooler units for service water leakage.

No service water leaks were identified, nor was any other source of leakage found; Subsequent to the entry, the inleakage rate to containment sump "A" dropped back to its original value of about 0.01 gpm.

The inspectors considered that the, actions taken by RG&E in response to the increased inleakage rate to containment sump "A" were appropriate.

Actions were conservative and presented a well-developed and realistic balance between operational and ALARAconcern.0 RADIOLOGICALCONTROLS 2.1 Routine Observations.

The inspectois 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'discu'ssions with plant personnel, the inspectors concluded that radiological controls were conscientiously implemented.

No inadequacies were identified.

The inspectors attended an ALARAbriefing held in preparation for a containment entry.

The purposes of this entry were to search for the source of a slight increase in inleakage to the "A" containment sump and to attempt to identify the source of air inleakage from the containment equipment hatch; these items are discussed in detail in sections 1.4 and 6.3 respectively, of this report.

Health Physics personnel were well prepared for this briefing.

Containment maps accurately reflected existing radiological conditions and were useful in developing ingress/egress paths which avoided hot spots and identified low dose rate areas.

Job scope, work locations, and stay-times were thoroughly developed. Consolidated Maintenance/Health Physics Team ALARATraining On'November 8, the inspector observed a consolidated training session that was designed to improve the coordination of activities between maintenance personnel and health physics technicians when performing a maintenance task.

The training goal was to upgrade worker practices to maintain dose/personnel contaminations as low as reasonably achievable (ALARA). Training was conducted at RG&E's Materials Engineering and Inspection Services (MEIS) Building at Beebee Station, using valve/piping run mock-ups normally used by MEIS in preparing for component non-destructive examinations (NDE).

• Performing a check valve inspection per Corrective Maintenance Procedure (CMP)-37,'4-inch, 150 lb Swing Check Valve Maintenance, was the task to be accomplished during the training scenario.

Specific job aspects that were addressed included:

work package preparation, pre-job surveys, radiation work permit preparation, pre-job briefing, proper donning/removing of protective clothing (PCs), job site preparations, maintenance procedure adherence, and post-work cleanup.

Allphases of the training were video taped for review by the instructors and students in the post-instruction critique.

From observations and through discussions with participants, the inspector concluded that the licensee is providing well organized, detailed training scenarios, in a realistic environment.

Overall, worker awareness of proper techniques to lower dose and minimize the spread of contamination.was increased.

Formal administrative controls are in'place to assure that identified performance weaknesses could be corrected through changes in station procedures,

job-specific practices; or hardware modifications.

Lesson plans were found to be well prepared.

Individualized instruction was provided, when needed.

Throughout the training, observed deficiencies were clearly and promptly communicated to the crew by the instructor.

2.3 Secondary Chemistry Monitoring Program Inspection B

carefully controlling steam generator water chemistry, material degradation caused by cherubical impurities in secondary system water can be minimized.

During plant opera

'

ration the. licensee attempts to maintain chemistry controls so that impurity concentrations are kept to a practical and achievable minimum.

Procedure WC-l, Revision 28, entitled, "A List o S 'e Chemical Parameters and Sampling Schedule,".lists the parameters to be checked on le, individual samples, normally expected analytical values and provides a sampling schedu e, Procedure WC-15, Revision 18, entitled, "Secondary Water Chemistry Monitoring,"

summarizes the major elements of the secondary water chemistry monitoring program..

The Plant observes the guidelines established by Westinghouse and the Electric Power Research Institute/Steam Generator Owners Group regarding secondary water chemistry.

The critica e critical parameters monitored in steam generator blowdown include the. following:

Cation conductivity

~

Chloride concentration o

Sodium concentration Water chemistry data for the period from May 1991 through August 1991, were reviewed to ascertain that the licensee maintains its secondary water chemistry within the limits established by its secondary chemistry specification.

The secondary water chemistry results measured during the reviewed period are shown below.

Parameter Conductivity (pMHOs)

Chloride (ppb)

Sulfate (ppb)

Sodium (ppb)

~Re elt 0.1 - 0.15 1 - 4.5 1-2 S ecific tion

< 0.25 Note:

Values do not reflect power transient ~onclu ion.

The secondary water chemistry was maintained within the licensee's specification for the reviewed period.

The stability of the water chemistry analysis indicates that. the licensee has

'good control of the variables affecting water quality.

3.0 MAINTENANCE/SURVEILLANCE

3.1 Corrective Maintenance 3.1.1 Automatic Rod Control System On November 1, a problem occurred with the automatic rod control system in which control bank "D" was automatically withdrawn approximately 1.5 inches without valid system actuation inputs.

Operators promptly recognized the abnormal situation and stopped rod mo io ot'on by placing the rod bank selector switch in the manual position.

Control rod bank

"D" was then restored to its original position.

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

Th suspected cause of the system abnormality was a malfunction within the rod speed e sus controller.

Ori November 11, this module was removed for troubleshooting. A total of sev n en capacitors were identified's defective and were subsequently replaced.

The module was successfully tested and returned to service on November 12.

Because of the possible generic nature of the capacitor failures, the licensee plans to perform further inspection and testing of capacitors in the automatic rod control system.

The inspector observed portions of the post-maintenance alignment and testing (Procedure Number CP-13, Calibration/Maintenance of the Rod Control System Rack, Rev. 10, Effective date May 24, 1991), and reviewed the completed maintenance package (Work

, Order Number 9101881, Rework/replace TC-401N Rod Speed Controller).

No operational or administrative deficiencies were identified; the inspector was, however, concerned over the lack of formal control placed on operation of the rod bank selector switch during the maintenance.

Specifically, manual operation of the rod control system was required during the maintenance; the system is normally operated in automatic, however, no speci ic administrative controls {such as an operator aid tag or a night order entry) were required or established to ensure that the rod bank selector switch would remain in the manual position.

When questioned regarding how this switch position was controlled during the maintenance, control room operators responded that system status was passed on at watch turnovei, and that, regardless of the maintenance issue, all operators'ere" aware of the importance of this switch; its position would'ot be inadvertently changed, and any planned change in its position would first be known by all control room operator Through review of control room documents, observations of operator actions, and interviews with operations personnel, the inspector determined that there were inconsistencies in operators'nderstanding the proper position for the rod bank'selector switch.

Although mode of operation of the rod control system has limited safety significance and is not specifically addressed in plant technical specifications, operator misunderstanding as to its condition could increase the challenge posed to the plant by a transient:

The inconsistency and informality obser'ved in control over operation of the rod bank selector switch was discussed with RGB'anagement.

Site management agreed to evaluate the administrative controls to determine what actions are appropriate to assure more consistent practice, 3.2 Surveillance Observations Inspectors observed portions of surveillances to verify proper calibration of test instrumentation, use of approved procedures, performance of work by qualified personnel, conformance with Limiting Conditions for Operation (LCOs), and correct system restoration following testing.

The following surveillances were observed:

Reactor Protection System Trip Test/Calibration Channel 3, CP-I-RPS-TRIP TEST-5.30 Safety Injection System Quarterly Test, PT-2.1Q, rev. 8 3.2.1 Emergency Diesel Generator 1A Performance Test On November 11, during the conduct of Performance Test (PT) 12.1, Emergency Diesel Generator (EDG) 1A, operator error resulted in the EDG being secured prior to completion of the test.

In attempting to lower the electrical load on the EDG in accordance with the test procedure, the operator mistakenly operated the EDG 1A control switch instead'of the governor switch.

These two switches are identical in appearance and are located vertically adjacent on the same panel, separated by about 8 inches.

Rotating the control switch in the counterclockwise direction (as was required on the gov'ernor switch to lower load) placed it in the stop position, causing the EDG to shut down.

EDG 1A had been supplying power to safeguards buses 14 and 18, in parallel with their normal commercial power supplies, The normal supplies assumed all electrical load upon loss of EDG 1A, thereby maintaining the buses energized throughout the transient.

The EDG control switch is normally covered by a removable plexiglas shield, installed to help prevent inadvertent. operation of the switch.

This cover had been removed earlier in the test and was not in position over the control switch at the time that the problem occurred; had it been, it likely would have prevented the operator from operating the wrong switch.

As a result, a temporary change to the test procedure was generated to specify the sequence

for removing and replacing the EDG control switch protective cover, thereby ensuring it would be in place prior to performing electrical load changes.

This change to the procedure was incorporated prior to reperformance of the test.

The inspector observed the reperformance of PT-12.1 on November 12.

Good procedural adherence was observed.

The EDG operator was knowledgeable of and proficient at operation of the EDG.

The test was completed satisfactorily and the inspector noted no deficiencies in its conduct and documentation.

In summary, the inspector considered actions in response to the inadvertent securing of EDG 1A during the conduct of PT-12.1 to have been appropriate and effective in preventing recurrence.

3.2.2

"A"Reactor Trip Breaker The inspector observed portions of reactor trip breaker testing - "A" train, periodic test (PT)

32A, revision 10, effective date May 13, 1991.

The purpose of this test was to test the "A" reactor trip breaker, bypass breaker, and associated

"A" reactor protection system logic train actuating contacts.

Each reactor protection function tested during this procedu're was covered by a separate, section.

In general, each section 1) noted which Control Room annunciator alarms would be initiated, 2) described the actual conduct of the test, and finally, 3) directed resetting the reactor trip "first out" and annunciator panel, and verifying that the applicable Control Room alarms had 'cleared.

One section (6.15, Power Range High Range (2/4 108% Power)

Reactor Trip), however, did not include the final step of resetting the annunciator panel.

After brief discussion between the maintenance technicians who were conducting the test and the Head Control Operator, the decision was made to clear the alarm as had been done in previous steps and proceed with the test.

When questioned by the inspector as to what authorized this course of action, the maintenance technicians indicated that restoration upon completion of a section could be performed at the discretion of operations personnel; and that, even ifnot done, the procedure could be performed as written in that completion of the next section would have cleared the alarms.

The inspector checked the equivalent test procedure for the "B" reactor protection system logic train (PT-32B) and found that the step which was missing in section 6.15 of PT-32A had been included.

The inspector determined that the procedure change which had added the steps to clear the "first out" and annunciator panel had been generated in October 1989.

By inadvertent omission, this step was not added to section 6.15 of PT-32A.

This concern was subsequently discussed with RG&E management.

Management response was both positive and timely. A permanent change notice (PCN 91T-1257) was generated to eliminate the inconsistency in PT-32A.

Action was taken to clarify the role of operations

personnel during testing and to reenforce the importance of procedural compliance.

The inspector was satisfied with the depth and scope of these corrective actions and had no additional concerns.

4.0 EMERGENCY PREPAREDNESS 4.1 Medical Emergency Drill On December 3, the site Emergency Preparedness staff conducted a medical emergency drill for the purpose of assessing the skills of the site medical team.

Drillparticipants were to render basic first-aid to an individual who had presumably been scalded by steam and had fallen offa ladder.

Through observation of the medical team response, discussions with participants, and review of the scenario, the inspector concluded that the drill objectives were-met and that there was effective communication between the control room and medical team while conducting the drill.

5.0 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 bar'riers were well maintained, personnel were properly badged for unescorted or escorted access, and compensatory measures were implemented when necessary.

Site modifi'cations are in progress to upgrade site security systems; during this inspection period, placement of underground conduit and other ground support work was completed for installation of two surveillance video cameras in the main parking lot. No unacceptable conditions were identified.

6.0 ENGINEERING/TECHNICALSUPPORT 6.1 Spurious Signals in the Advanced Digital Feedwater Control System (ADI'CS)

Following installation of the ADFCS, during the 1991 refueling outage, control room operators observed slight changes in the feedwater regulating valve position while testing the diesel driven fire pump.

These changes were infrequent and appeared to be random in nature. In an attempt to understand and isolate the cause of these disturbances, site engineering staff conducted troubleshooting of the ADFCS system on November 11th, under Work Order No. 9122181.

In conducting this test, the diesel driven fire pump was manually started and run for about a minute.

Upon starting the pump, operators observed both main feedwater flows increasing with the condensate bypass valve opening and the standby main condensate pump starting.

Steam generator levels continued to increase resulting in the ADFCS shifting to the manual mode and a feedwater line isolation signal being received.

Subsequently, condensate booster pumps tripped on high pressure and a runback of 10% per

)I t

tl l

hour was initiated.

Operators took immediate control of feedwater to dampen flow oscillations and stabilize steam generator levels.

Upon attaining stable plant conditions,'eedwater control was returned to auto at which time the load decrease was stopped.

During this short interval, the plant experienced a power reduction of about 0.5%.

Subsequently, control room supervision notified the NRC Operations Center of the feedwater isolation'

'

within the four hour period as required by 10 CFR 50.72, Through evaluating the root cause of the effect of starting the fire pump upon ADFCS, the site engineering staff determined that an "AR-80" relay in the fire pump starting circuitry, upon deenergizing, may cause spurious voltage spikes in ADFCS cabling that lies iri close proximity to fire pump cables in the same cable run.

To correct this electrical disturbance, a

reverse-bias diode was installed across the relay to suppress the spiking.

Following installation of the diode, starting of the fire pump resulted in no ADFCS disturbances.

To support modifying the relay, the site engineering staff 'evaluated the safety implications of the proposed change.

A technical staff review (TSR-91-219) and 10 CFR 50.59 safety evaluation were completed and subsequently reviewed and approved by quality control engineering and the site engineering manager.

-

The inspectors evaluated the actions taken by the licensee in response to the spurious signals affecting ADFCS.

Based on discussions with operations and site engineering personnel, the inspector's concluded that the initial troubleshooting effort was well coordinated between'he respective departments and that the operators promptly and astutely stabilized the plant following the disruption in ADFCS control.

Through review of the technical staff engineering evaluation, the inspectors determined that the cause of the voltage spikes was thoroughly analyzed and the method of diode suppression was appropriately justified. The inspectors also concluded that the supporting 10 CFR 50.59 safety evaluation was sufficiently detailed to assess the safety implications of altering the AR-80 relay.

During routine starting of the diesel driven fire pump, the inspectors found rio abnormal interruptions affecting ADFCS and'concluded that the method of diode suppression was effective.

In accordance with 10 CFR 50.73, the licensee is preparing a 30 day Licensee Event Report (LER) describing the experience.

The inspector willreview the LER for completeness upon receipt.

6.2 Safety Injection System Pump Recirculation Flow On November 7, during the conduct of PT-2.1Q, Safety Injection (Sl) System Quarterly Test, Rev. 8, effective September 12, 1991, startup recirculation flow rate for SI pump "B" was found to be less than the administrative limit. Actual startup recirculation flow rate was 90 gpm, whereas the procedure specified a band of 93-100 gpm.

Although this is not a Technical Specification requirement and although the completed test. satisfied the applicable Technical Specification requirement, the licensee declared SI pump "B" inoperable pending evaluation of the conditio ~ ~

Mechanical Engineering evaluated the existing startup recirculation flow rate of SI pump

"B". The lower administrative limitof 93 gpm was based on recirculation line check valve

,considerations (minimum flow of 91 gpm required to maintain the check valve fully open, plus 2 gpm for instrument error), and therefore was.not applicable in determining minimum acceptable recirculation 'flow to prevent pump damage.

Prior to installation of the SI system minimum flow recirculation system iri 1988, the SI pumps had been operated at a significantly lower flow rate (approximately 35 gpm flow during testing)

~ Approximately 20 years of intermittent operation at this flow rate had not produced any pump degradation.

Mechanical Engineering concluded that 85 gpm was an acceptable value for minimum SI pump startup recirculation flow. On this basis, SI pump "B" was declared operable on November 8.

The inspector considered that RGS.E's actions in response this situation demonstrated commitment to safe, conservative plant operation.

The engineering evaluation was made promptly and on sound technical bases.

The inspector had no additional concerns on this

'atter.

6.3 Containment Equipment Hatch Leakage Periodic Test (PT) 22.4, Equipment Hatch Between Door Volume Leak Rate Test, Revision 26, Effective Date October 15,.1991 was performed on November 19.

The purpose of this test was to verify that the leakage rate from the containment equipment hatch air lock (between door volume) when pressurized to its design pressure of 60 psig was within the technical specification limitof 22,471 cc/min.

Although the. resultant value of 11,738 cc/min was satisfactory in this respect, it was in excess of the licensee's more restrictive administrative limitof 2500 cc/min.

Troubleshooting was undertaken to reduce the leakage rate to within the administrative limit.

Shaft packing of the operating handwheels was adjusted and a small leak on an air connection leading to the door seal was identified and corrected.

Hatch strongbacks, which are only installed for the performance of this test, were also tightened.

These actions reduced the leakage rate to 4082 cc/min.

A containment entry was made on November 26 to attempt to identify the source of leakage.

With the between door volume pressurized, the hatch was inspected from inside the containment.

This revealed excessive leakage around the bottom of the door at the approximate position of one of the strongback mounting points.

The between door volume was then depressurized and the hatch was opened to inspect the door seals.

No physical damage to the door seals was noted.

The containment equipment hatch leakage was suspected to be related to variability in installation of the hatch strongbacks.

There is currently no procedural guidance for installation of these strongbacks.

As a result, variations in (for example) the amount of

~ ~

torque used to tighten the strongback bolts, or elongation of the bolts over the years could have caused the observed leakage rate increase.

These possibilities were being examined by the licensee at the close of the inspection period.

The inspector considered RG&E's response to the containment equipment hatch leakage to have been timely and conservative.

Although the current leakage rate is well less than the technical specification limit, RGB'ontinues to pursue reducing it to less than their administrative limit.

7.0 SAFETY ASSESSME<NT/QUAI ITY VERIFICATION 7.1 Periodic Reports Periodic reports submitted by the licensee pursuant to Technical Specifications 6.9.1 A.2 and 6.9.1.4 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 October 1991.

No unacceptable conditions were identified.

7.2 Spent Fuel Pool Material Storage An inspection of the spent fuel pool (SFP) was conducted to verify the adequacy of material storage.

This was done in response to an event at another Region I plant in which a component suspended in the SFP fell due to parting of its supporting cable.

Therefore, storage of suspended components was closely examined during the inspection, with particular emphasis on examining the materials used to suspend equipment and the potential for fuel element damage should the equipment fall.

Four handling tools were stored vertically in the SFP; of these, three were mounted on installed hangers, and were not considered to pose a credible drop hazard.

The remaining tool, a canister handling tool weighing approximately 150 pounds, was suspended by nylon slings and ropes from the SFP hand rail. The point of attachment to the handling tool was above the tank water level, so water-induced degradation of the suspending material was not, a concern.

The tool was suspended over an empty storage location.

Although the tool was approximately 30 feet in length, its potential for impacting any fuel assemblies in the SFP should the supporting lines part was evaluated to be very low. It would most probably lodge

.

vertically in the empty storage location immediately beneath it rather than fall over.

Based on these considerations, the inspector evaluated the storage of this tool to be adequate.

No additional components were suspended in the SF ~ ~

II'I 1,

1>>

The licensee's administrative controls over SFP,storage were also reviewed.

An inventory of materials stored in the SFP was maintained in accordance'with Reactor Engineering Guideline (REG) 2.0 and updated annually as required by REG 3.1.

Utilized during the inspection, this checklist accurately reflected the actual materials and storage locations.

Additionally, REG 2.0 restricts storage of additional materials in the SFP.

In summary, storage of material in the SFP was inspected and found to be satisfactory.

The licensee had adequate administrative controls in place both to track the storage of existing materials and to limitadditional material storage in the SFP.

The inspector had no additional concerns in this area.

7.3 Auxiliary Feed Water System Walkdown The inspector performed walkdowns of accessible portions of the Auxiliary Feedwater (AFW) and Standby Auxiliary Feedwater (SAFW) systems utilizing the risk important AFW system walkdown table of "AuxiliaryFeedwater System Risk-Based Inspection Guide for the Ginna Nuclear Power Plant," NUREG/CR-5764 PNL-7594.

Developed on the basis of probabilistic risk assessment (PRA), this table provides guidance for inspection of AFW and supporting system components important to the prevention of core damage.

The inspector noted no discrepancies in existing system lineup.

Additionally, plant procedures for initial system alignments, operations, and component'position verifications were reviewed, with rio deficiencies noted.

7.4 Winterizing Inspection The inspector reviewed programmatic, maintenance, and operational aspects of the licensee's program of protective measures for extreme cold weather.

Maintenance Procedure M-1306.1, "Ginna Station, Maintenance Department, Winterizing Inspection Program,"

Revision 3, effective October 18, 1991, is the controlling procedure for the cold weather protection program.

Areas inspected per this instruction include heat trace circuits, piping insulation, critical motor winterizing, window and ventilation supply openings, and screenhouse overflow weirs; specific equipment and locations identified as susceptible to freezing are identified under each area.

Inspections are specified to be completed by October 15 each year, with corrective action to be completed by November 1.

The inspector reviewed the completed procedure for 1991.

Two minor discrepancies had been noted during the inspections; all corrective action was completed by October 31. - The previous winter, two heat traces associated with the "B" Emergency Diesel Generator fuel oil system had been out-of-commission; details were discussed in Inspection Report 90-26.

The inspector noted that repairs to these heat traces had been completed as projected in that repor ~ 4 Ci

Operations department responsibility within the cold weather p'rotection program is specified in Administrative Procedure A-54.4.1, "Cold Weather Walkdown Procedure,"

Revision 10, Effective Date September 12, 1991.

This procedure specifies criteria for implementing additional monitoring requirements; these monitoring requirements include verification of equipment operability and closure integrity, as well as general area temperature monitoring.

The inspector performed a plant cold weather walkdown utilizing,the guidance of A-54.4.1; inspection points listed in M-1306.1 were also examined.

No significant deficiencies were noted.

In summary, the cold weather protection program at Ginna was reviewed and found to be of adequate scope and effectively implemented.

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

The inspector noted that these meetings were well planned and efficient.

Discussions among committee members were candid, and there was no hesitancy in withholding approval of items which, as a result of these discussions, required modification or further review.

The inspector also attended the quarterly meeting of the RG&E corporate Quality Assurance/Quality Verification subcommittee.

Discussions included possible improvements to the methodology used for trending quality performance indicators, such as the number of Audit Finding Corrective Action Reports (AFCARs) and Non-Conformance Reports (NCRs),

and an improved format for tracking Identified Deficiency Reports (IDRs) which were of particular concern.

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

November 11, 24, and December 7, 1991.

8.2 Exit Meetings At periodic intervals and at the conclusion of the inspection, meetings were h'eld with senior station m'anagement to discuss the scope and findings of this inspection.

The exit meeting for inspection report 50-244/91-27 was held on December 11, 1991 with the following individuals attending:

L

fr t

I t

~Nme Title Thomas Moslak Edward Knutson Senior Resident Inspector Resident Inspector RG&E Joe Widay Thomas Marlow John Fisher Paul Gorski Andy Harhay

, Kenneth Laning Ron Jaquin Michael Lilley

'ichard Marchionda Jeff Wayland John St. Martin Clair Edgar Terry Schuler Glenn Litzenberger Plant Manager Superintendent, Ginna Production Maintenance Planning Sc Scheduling Manager, Mech. Maintenance-Manager, HP & Chemistry Health Physicist Engineer NSEcL Manager, Nuclear Assurance Superintendent, Support Services Reactor Engineer Corrective Action Coordinator Manager, Electrical Maintenance/I&,C Operations Manager Operations Shift Supervisor

'%4

ll

~