IR 05000244/1992017

Insp Rept 50-244/92-17 on 921027-1218.No Violations Noted. Major Areas Inspected:Plant Operations,Radiological Controls,Maint/Surveillance,Security,Emergency Preparedness, Engineering/Technical Support & Safety Assessment

ML17262B133
Person / Time
Site:	Ginna
Issue date:	12/30/1992
From:	Lazarus W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML17262B132	List: IR 05000244/1992017 ML17262B131
References
50-244-92-17, NUDOCS 9301080081
Download: ML17262B133 (38)

Text

U. S. NUCLEAR REGULATORY COMMISSION

REGION I

Inspection Report 50-244/92-17 License: DPR-18

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Facility:

R. E. Ginna Nuclear Powe'r Plant Rochester Gas and Electric Corporation (RG&E)

Inspection:

Inspectors:

October 27 through December 18, 1992 r

T. A. Moslak, Senior Resident Inspector, Ginna E. C.

utso Resident Inspector, Ginna Approved by:

W.

hief, Reactor Projects Section 3B Date INSPECTION SCOPE Plant operations, radiological controls, maintenance/surveillance, security, emergency

, preparedness, engineering/technical support, and safety assessment/quality verification.

INSPECTION OVERVIEW IGI: G dp HM dd d

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G demonstrated during two power reductions and power escalations.

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~conscientiously implemented.

Maintenance/Surveillance:.

Lack of attention-to-detail in revising a surveillance procedure resulted in reduced service water flow to non-safety cooling loads when conducting the testing.

Some auxiliary feedwater system valves of minor importance were not returned to their normal at-power positions as a result of procedural deficiencies.

~gecurtt:

No deficiencies were identified during routine security checks.

Emer enc Pre aredness:

An unannounced off-hours emergency preparedness drill demonstrated the ability to staff the emergency response organization satisfactorily.

En in rin /Technical u

r: Corporate and site technical staffs provided appropriate oversight for "D" service water pump motor repairs to expedite the pump's return to service.

Safet Assessment/

uali Verification: Senior licensee management was appropriately briefed on the results of audits and assessments'in areas affecting plant performance.

r 9301080081 y~30104 PDR ADOCK 05000244

PDR

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TABLEOF CONTENTS OVERVIEW

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

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~ ii 1.0 PLANT OPERATIONS (71707)............... ~...,

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1 ~ 1 Operational Experiences 1.2 Control of Operations............. ~.........

1.3 Power Reduction to Support Off-Site Electrical Distribution M'mtenance 1.4 Power Reduction Due To Feedwater System Leak

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System

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2.0 RADIOLOGICAL.CONTROLS (71707).........

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

2.2 ALARABriefing

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3.0 MAINTENANCE/SURVEILLANCE(62703, 61726)..... ~.........

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Corrective Maintenance 3.1.1

"D" Containment Recirculation Fan Cooler Service Water. Leak 3.1.2

"D" Service Water Pump Motor Failure..............

3.1.3 Containment Recirculation Fan Cooler. Collection Pan Level Detector Inoperable Due To Valve Out-Of-Position 3.2 Surveillance Observations 3.2.1 Turbine Driven Auxiliary Feedwater Pump Quarterly Test...

3.2.2 Failure of Motor Operated Valve During Service Water System Performance Testing......................'....

3.2.3 Inadequate Procedural Control Of Safety System Valve

A'gnments................................

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4.0 SECURITY (71707)

4.1 Routine Observations...............:

4.2 Inverter Failure

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5.0 EMERGENCY PREPAREDNESS (71707)

5.1 Unannounced Emergency Preparedness Drill.....

5.2 Meteorological Tower Maintenance

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6.0 ENGINEERING/TECHNICALSUPPORT (71707, 92701)

6.1

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"C" Safety Injection Pump Discharge Cross-Connect Lo 'lc

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6.2 Safety Injection System Piping Supports 6.3 'team Generator Replacement........ ~.....

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Valves Crossover

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Table of Contents 7.0 SAFETY ASSESSMENT/QUALITY VERIFICATION(90712, 90713, 92701, 40500)

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7.1 Quality Assurance/Quality Control Subcommittee Meeting........;

7.2 Periodic Reports...................................

8.0 ADMINISTRATIVE(71707, 30702, 94600)

8.1 Backshift and Deep Backshift Inspection 8..2 Exit Meetings

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DETAILS 1.0 PLANT OPERATIONS (71707)

1.1 Operational Experiences h

The plant operated at 98 percent power through the majority of the inspection period.

Two brief periods of reduced power operation were required to support maintenance.

On November 7, 1992, power was reduced to 82% to support off-site distribution system maintenance.

On November 29, 1992, a feedwater system leak forced a power reduction to 32% to support repairs.

In both cases, full power operations were restored within one day.

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 were knowledgeable of off-normal plant conditions.

The inspectors reviewed control room log books for activities and trends, observed recorder traces for abnormalities, assessed compliance with Technical Specifications, and verified. equipment availability was consistent with the requirements for existing plant conditions.

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

No operational inadequacies or concerns were identified.

1.3 Power Reduction to Support Off-Site Electrical Distribution System Maintenance On November 7, 1992, power was reduced to 82% to support planned off-site electrical distribution system maintenance.

Following completion of this maintenance and electrical distribution system realignment, power ascension commenced at 8:14 p.m. on November 7, 1992.

Full power (approximately 98%) was reached approximately three hours later.

The inspector observed operations in the control room to realign the electrical distribution system per operating procedure (O)-6.9.2, "Establishing and/or Transferring Offsite Power to Bus 12A/Bus 12B", and to raise plant power per 0-5.2, "Load Increases".

These operations were conducted in a professional manner; in particular, the inspector noted that supervisory control and operator communications were excellent, 1.4 Power Reduction Due To Feedwater System Leak While performing routine plant rounds on the morning of November 29, 1992, an auxiliary operator noted steam and con'densate leaking from the insulation around air operated valve (AOV)-3334B (MSR 2B second pass drain level control AOV to feedwater heater 5B).

Maintenance personnel removed the insulation, which revealed the source of leakage to be a flange between the valve body and the lower valve cap.

To provide isolation for repairs required that-the 2A and 2B moisture separator reheaters (MSRs) be taken out-of-servic Each set of MSRs (1A/B and 2A/B) supplies one of the two low pressure turbines; operation with one set out-of-service limits power to 50%.

However, based on difficulties experienced during single low pressure turbine operations in the past, the decision was made to take both sets of MSRs out-of-service.

With only the high pressure turbine in operation, power is limited.to 35%.

At 6:25'a.m. on November 29, 1992, operators commenced a controlled load reduction to support repair of AOV-3334B. Power was stabilized at 32% at 8:27 a.m.

During valve disassembly, the nuts that fasten the lower cap to the valve body were found to be loose.,

This had caused a gradual degradation of the laminated graphite gasket that seals the flange.

. The suspected reason that the nuts were loose was that, following maintenance during the 1992 refueling outage, the nuts had not been retorqued at normal operating temperature. (hot torqued).

Consequently, this repair included hot-torquing the fasteners following gasket replacement.

The licensee further utilized the period of low power operation to examine main condenser circulating water tubes for leakage (three tubes were found to be leaking 'and were removed from service by plugging) and for turbine stop and intercept valve testing. All maintenance was completed by late evening on November 29, 1992.

Following a brief hold for adjustment of steam generator chemistry, power ascension began at approximately 1:00 a.m.,

~ November 30, 1992.

Full power (98%) was achieved approximately six hours later.

The inspector considered that the licensee's response to the leak from AOV-3334B was appropriate.

The'decision to further evaluate the leak by removing insulation prior to reducing power was prudent and'averted unnecessary challenges to the plant that may have resulted from a rapid downpower.

Placing both sets of MSRs out-of-service, as well as sequentially performing maintenance actions that could affect main condenser vacuum,,

demonstrated concern for plant stability over power generation.

The inspector had no further questions regarding this matter.

2.0 RADIOLOGICALCONTROLS (71707)

2.1 Routine Observations The inspectors periodically confirmed that radiation work permits were effectively implemented, dosimetry was correctly worn in controlled areas and dosimeter readings were accurately recorded, access to high radiation areas was adequately controlled, and postings and labeling were in compliance with procedures and regulations.

Through observations of ongoing activities and discussions-with plant personnel, the inspectors concluded that radiological controls were'conscientiously implemente cy

2.2 ALARABriefing On December 4, 1992, the inspector observed an ALARA(As Low As Reasonably Achievable) briefing presented by the site Health Physics Department to personnel entering the reactor building. This entry involved operations and instrument and control g&C)

personnel troubleshooting the "C" and "D" containment recirculation fan cooler collection pan level detectors.

Detailed presentations were made by the site Health Physics staff to assure personnel were aware of travel paths, low dose waiting areas, high dose "hot spots",

the proper wearing of personnel dosimetry, and contamination control. measures.

Following the ALARAbriefing, personnel were briefed on heat stress mitigation by a Safety Department representative.

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The inspector found, in particular, the use of handouts to individuals, as well as large plant arrangement diagrams identifying major pieces of equipment, area/localized dose rates, and ALARAwaiting areas, to have been effective in communicating dose control measures.

3.0 MAINTENANCE/SURVEILLANCE(62703, 61726)

3.1 Corrective Maintenance 3.1.1",D" Containment Recirculation Fan Cooler Service Water Leak As discussed in inspection report 50-244/92-15, leaks have been developing in the recirculation fan cooler heat exchangers at an increasing rate over the past. year; inspection reports 50-244/92-10, 92-09, and 91-23 provide the history of recent service water system leaks and repair activities.

During this inspection period, the "D" co'ntainment recirculation-fan cooler was declared inoperable on November 2, 1992, due to a service water leak in the primary heat exchanger.

As before, corrective action consisted of removing the leaking heat exchanger tube from service by cutting it at the supply/return headers and then plugging the stub tubes.

The unit was returned to service on November 5, 1992, The containment recirculation fan cooler heat exchangers are'scheduled to be replaced during the 1993 refueling outage.

The replacement primary heat e'xchangers will be of an advanced design, with greater erosion/corrosion resistance and a physical configuration that will provide both better access for maintenance and greater flexibilityin selecting repair, techniques.

During the interim the licensee has continued to monitor heat exchanger leakage closely and aggressively pursue repairs.

3.1.2

"D" Service Water Pump Motor Failure On November 19, 1992, the "D" service water pump motor experienced a motor winding insulation breakdown, resulting in phase-to-phase shorting and 'a subsequent motor trip..

Operations. personnel promptly implemented procedure AP-SW.1 for off-normal service water system operation and started the redundant "C" service water pum Subsequent to the motor failure, the inspector followed the licensee's actions to diagnose the cause of the failure, oversee repairs, and return the pump to full service in a timely manner.

As a result of stator winding damage experienced during the phase-to-phase short, the motor was shipped off site to a repair facility (Reliance Electric Company, Cleveland, Ohio) for rewinding and determination of failure cause.

Engineers, maintenance technicians, 'and quality assurance personnel from the corporate and site staffs were dispatched to the repair facility to evaluate the=-repairs and testing required to assure reliability and expedite receipt processing.

Upon satisfactory completion of testing, that included measuring motor running current, power, speed, and vibration under no-load conditions, the rewound motor was returned to the site, installed, tested in place, and declared operable on December 10, 1992.

Following examination of the failed components, the repair facility could not identify a specific root cause but suggested that a high voltage surge may have contributed to the failure.

Since an exact failure mechanism was not readily evident, the licensee's maintenance and engineering departments initiated a root cause analysis.

This analysis included using a remotely operated mini-submarine to examine the service water suction bay and pump impellers for flow obstructions, replacing the "D" pump internals with rebuilt internals, and installing monitoring equipment to motor control center 1G to measure motor voltage, current and power.

To date, the component examination and the operational data acquired do not indicate a specific failure mode, and the monitoring of motor electrical parameters will continue.

Based upon observations of the licensee's integrated response to the motor failure, discussions with cognizant licensee representatives, and review of supporting documentation, the inspector concluded that the licensee provided appropriate technical oversight for the'otor repair and acted aggressively to return it to service.

The inspector concluded that the licensee is carrying out appropriate measures to identify a root cause.

The "D" service water pump motor has had a recent history of failures.

Insulation degradation, resulting in phase-to-phase shorting and stator winding damage, occurred in March 1990 and August 1990.

Following the second failure, in August 1990, RG&E had the repair facility upgrade the winding insulation class to enhance the motor's thermal endurance.

To provide assurance that the changes in materials did not affect the motor's operating characteristics, additional dynamic testing to augment static bench tests was performed at RG&E's request.

Following installation of the rewound motor in August 1990, the pump had run for about 11,285 hours0.0033 days <br />0.0792 hours <br />4.712302e-4 weeks <br />1.084425e-4 months <br /> until June 1992, when it was placed in a standby mode.

Since June 1992, it had not been run for continuous long periods until November 19, 1992.

The "D" service water pump was placed in service on that date following completion of the quarterly service water pump surveillance testing, PT-2.7.1.

The pump motor failed after about seven hours of continuous operation.

The licensee has not yet completed a determination of the root cause for the failur.

3.1.3 Containment Recirculation Fan Cooler Collection Pan Level Detector Inoperable Due To Valve Out-Of-Position Technical specification 3.1.5.1.1 requires that two reactor coolant system leakage detection systems be in service during power operation.

The systems that are specified to serve this function are 1) the containment air particulate monitor, 2) the containment radiogas'monitor, 3) the containment atmosphere humidity detector, and 4) the containment water inventory monitoring system.

The containment recirculation fan cooler level detection system comprises a portion of the containment water inventory monitoring system.

A level detector provides indication and a high level alarm for condensate that collects in the bottom of each of the recirculation fan cooler units.

As necessary, operators drain the condensate from the individual recirculation fan coolers to the "A" containment sump by means of remotely operated valves.

On December 3, 1992, operators noted that the level detection system for the "D".

containment recirculation fan cooler appeared to be malfunctioning, in that indicated level was not changing.

Troubleshooting revealed that level detector valve alignment was incorrect; specifically, valve V-11492 (Level indicator LI-1093 high side root valve) was-shut.

The valve was subsequently opened, which restored normal level indication.

The licensee determined that the "D" containment recirculation fan cooler level detector had last been observed to be operational on November 2, 1992, when it had provided indication that the unit had developed a service water leak (see section 3.1.1).

Following repair and return to service on November 5, 1992, the unit was operated continuously until November 18, and again from November 25 until December 4.

No condensate draining was performed during these periods.

Since draining is normally done in response to a high level alarm, the fact that draining was not conducted during this period indicates that the level detector had likely been inoperable since the unit had been returned'to service on November 5.

Although the "D" containment recirculation fan cooler level detector was apparently inoperable for approximately one month, the containment water inventory monitoring system remained operable, in that 1) "A" containment sump level indication was available throughout this period, and 2) overflow from the "D" containment recirculation fan cooler drains to the "A" containment sump.

Therefore, the requirements of technical specification 3.1.5.1.1 remained satisfied in spite of this problem.

At the end of the inspection period, the licensee was still in the process of attempting to determine how the level detector had been isolated.

In addition, the licensee initiated a corrective action report (CAR-2069) to review this occurrence in light of other recent instances of valves found out of their expected positions (see section 3.2.3).

The inspector considered that these corrective actions were appropriat I

3.2 Surveillance Observations Inspectors observed portions of surveillances to verify proper calibration of test instrumentation, use of approved procedures, performance of work by qualified personnel, conformance to Limiting Conditions for Operation (LCOs), and correct system restoration following testing.

The following surveillances were observed:

Performance Test (PT)-12.1, "Emergency Diesel Generator 1A", revision 68, dated April 9, 1992, observed November 10, 1992 PT-2.1M, "Safety Injection System Monthly Test", revision 8, dated May 2, 1992, observed November 24, 1992

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PT-3M, "Containment Spray Pump Monthly Test", revision 7, procedure change notice (PCN) 92T-813, dated November 30, 1992, observed November 30, 1992

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'PT-16M-A and B, "AuxiliaryFeedwater Pump A and B - Monthly" revision 2, dated January 29, 1992, observed December 10, 1992 The inspector determined that Results and Test personnel adhered to procedures, equipment operating parameters met acceptance criteria, and redundant equipment was available for emergency operation.

3.2.1 Turbine Driven AuxiliaryFeedwater Pump Quarterly Test Testing of the turbine driven auxiliary feedwater (TDAFW) pump was performed on November 12, 1992, in accordance with PT-16Q-T, "AuxiliaryFeedwater Turbine Pump-Quarterly," revision 2, dated October 15, 1992.

The inspector reviewed the completed procedure (prior to licensee review) and noted the following:

a.

Leak rate determination for check valves (CV)-4003 and CV-4004:

The combined leak rate was incorrectly calculated; specifically, the volume of leakage collected was multiplied (rather than divided) by the time taken to collect it. The erroneously calculated leak rate was in excess of the specified limitof 1.4 gallons per minute (gpm); the actual leak rate was within this limit.

The procedure specified additional testing (Attachment 3 to the basic procedure) to determine the individual valve leak rates, in the event that the combined leak'rate exceeded the specification.

As a result of the above error, this testing was conducted.

Despite the same calculational error being made in determining these new leak rates, each came out to be less than 1.4 gpm.

The inspector noted, however, that the Attachment 3 procedure did not address individual valve leak rate specifications.

The specification of 1.4 gpm is implied, in that it is standard practice to use the most limiting individual valve leak rate specification as the limitfor combined valve leak rate testing; however, this was not stated in the procedur Two procedural steps (6.6.30.4.1 and 2) that required data entry (average steam generator pressures)

were, instead, initialed by the technician.

These two data points are the averaged values of three pressure indications, and are subsequently used in steps 6.6.30.6.2 and 3.

Values for steam generator pressure were recorded in these subsequent steps; however, the source of these data points (a single indication, or the average of three indications as required by steps 6.6.30.4.1 and 2) could not be determined through examination of the completed procedure.

Although this error had no effect on the test results, it indicated a lack of attention to detail in documenting test performance.

C.

Procedural step 6.10.4, a procedure path decision point, was marked "N/A" when it should actually have been initialed. While this was strictly an error in documentation and had no effect on the conduct of testing, it further indicated inadequate attention-to-detail.

As a result of the deficiencies noted in leak rate determinations for valves CV-4003 and CV-4004, the inspector reviewed TDAFW pump quarterly test results for the past year.

The inspector found that the leak rate as determined during testing on February 6, 1992 (0.083 gpm) had also been calculated in error; the actual leak rate (1.0 gallons collected over a period of five minutes, or 0.2 gpm) was still less than the specified limit.

.These items were discussed with licensee management.

As a.result, the licensee is preparing a procedure change to PT-16Q-T to more clearly specify the method for performing leak rate determinations.

Additionally, licensee management held a meeting with the Results and Test group to reenforce the need for attention to detail during testing.

The inspector concluded that the licensee was making a good faith effort to follow the procedure and that the errors were simple human errors which were conservative (higher leak rate than actual).

Licensee actions to correct problems associated with TDAFW system testing were appropriate.

3.2.2 Failure of Motor Operated Valve During Service Water System Performance Testillg On November 17, 1992, while performing Periodic Test (PT)-2.3, "Safeguard Valve Operation," motor operated valve (MOV)-4613, a turbine building service water isolation valve, failed to close (safety position) as required due to a torque switch trip. Additionally, the valve failed to open fully (non-safety position) upon demand, reducing service water flow to balance-of-plant equipment.

MOV-4613 is designed to close, isolating non-safety cooling loads from the safety related portions of the service water system upon receipt of a safety injection signal in coincidence with a loss of off-site power.

PT-2.3 is performed quarterly to measure the stroke times of safety-related MOVs to assure their operability.

While conducting PT-2.3, the Results and Tests Section (R&T) performed step 6.3.6.1 to stroke time MOV-4613 from the open (normal) to the closed position.

When the actuation switch was taken to close, MOV-4613 gave dual indication (opened and closed) and never indicated closed only.

A second isolation valve, MOV-4670, in series with MOV-4613, that operates

on the same actuation signal, stroked closed as required.

Upon determining that MOV-4613 did not operate, control room operators declared the valve inoperable, entering a six hour limiting condition. for operation (LCO) in accordance with Technical Specification 3.3.4.1b.

In immediate response to this plant condition, operations and maintenance personnel met to identify the contingency actions to assure plant safety and the scope of troubleshooting necessary to diagnose the cause of valve failure.

Operations management directed that the service water system cross-tie valves, MOV-4680 and MOV-4693, be opened.

This action shifted service water flow from the A-header to the B-header, thereby restoring to service the capability to automatically isolate safety-related from balance of plant service water cooling loads.

This action assured compliance with Technical Specification'3.3.4.1b for service water system operability.

With the A-header now isolated, electricians, pipe fitters, and mechanics carried out a systematic troubleshooting approach.

Maintenance personnel cleaned and lubricated the valve stem and stroked the valve several times, In addition, an engineering review indicated that the "close" torque switch setting could be raised to preclude future spurious torque switch trips.

Raising the torque switch setting from 1.5 to 2 was found to provide the margin necessary to prevent a spurious trip yet provide an operational trip below the motor stall value.

Accordingly, as an interim measure, the torque switch setting was raised to 2.0.

Although the probable cause of the valve failure is due to stem binding due to a build-up of rust on the stem, the valve will be

'iagnostically tested to further pinpoint the binding problem, during the 1993 outage.

Until then, the valve willbe tested monthly to verify the adequacy of corrective actions to date.

The inspector observed the operations and maintenance actions in response to the failure of MOY-4613 to close and to open fully. Actions by the control room operators were prompt and decisive to open the service water cross-tie valves to provide service water cooling to balance of plant equipment.

The inspector determined that safety-related equipment was not affected by the failure of MOV-4613 to close or to open fully, however cooling water was reduced to vital balance of plant equipment, e.g., main turbine lube oil cooling, jeopardizing the stable operating conditions of this equipment.

During the site management meeting held in immediate response to the valve failure, R&T personnel promptly identified a deficiency in PT-2.3 in that the balance of plant cross-tie valves (MOY-4680 and MOV-4693) were not opened prior to testing MOV-4613, thereby assuring uninterrupted service water cooling to balance of plant equipment.

'A procedure change notice (PCN) was prepared to correct PT-2.3.

Subsequently, R&T management conducted an in-depth review to identify the cause of the procedure deficiency.

Through examination of the licensee's evaluation of the factors that contributed to the procedure deficiency, the inspector concluded that, generally, the R&T organization showed a lack of attention to detail when revising -PT-2.3, to include certain test requirements from PT-2.7, "Service Water System".

The inspector determined that the licensee has developed appropriate corrective actions to address the lessons learned

from this "oversight.

Following resolution of the contributing factors, site management met with REcT personnel to delineate management expectations regarding making procedure changes.

The inspector concluded that the operational, troubleshooting, and maintenance activities were well coordinated under the control of site management and the PCNs generated to correct the procedural deficiencies were appropriately reviewed by the Plant Operations Review Committee.

3.2.3 Inadequate Procedural Control Of Safety System Valve Alignments Valve F nd t-f-P iti n Prior T n

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w er tern Te tin Standby. auxiliary feedwater (SAFW) system testing per PT-36Q-C and -D, "Standby Auxiliary Feedwater Pump C (D) - Quarterly", was conducted on December 3, 1992.

In preparation for observing the test, the inspector conducted a partial walkdown of the SAFW system, using the SAFW piping and instrumentation diagram (P&ID), drawing number 33013-1238, as the system configuration reference.

The inspector noted that normally closed valve V-9735 (instrument root valve to PI-4092, SAFW pump discharge)

was open.

The equivalent instrument root valve in the "D" SAFW train, V-9736, was subsequently found to be closed.

The position of these valves has no affect on operability of the SAFW system, however the valves must be open to record SAFW discharge pressure as part of the surveillance test.

Review of the test procedures showed that V-9735 and V-9736 were not required to be positioned as part of this surveillance test, indicating that they were assumed to be open.

Upon being informed of the apparent discrepancy, test and operations personnel suspended the test.

Procedure changes were generated to place the gauges in service as required and to isolate them on completiori of testing.

Testing was resumed and completed later the same day.

Standby auxiliary feedwater pump discharge pressure is used to determine differential pressure (dp) across two check valves in the associated SAFW system discharge header.

Sufficient dp across these check valves, in turn, is interpreted as verification of operability, as required quarterly by the licensee's inservice testing program.

The inspector was concerned that past test results may not have been valid ifthey were based on pressure obtained from an isolated gauge.

However, a review of test results from the past year determined 'that values recorded from the gauges in question indicated that the gauges had been in service during surveillance testing.

Licensee review indicated that technicians were not placing the gauges in service outside of the test procedure to obtain the required readings; rather, that valve seat leakage was sufficient-to cause the gauges to respond normally, thereby never raising a question over valve positio Valv F und ut-f-P ition Pri r To Auxilia Feedwater tern Testin Auxiliary feedwater (AFW) system testing per PT-16M-A and -B, "AuxiliaryFeedwater Pump A (B) - Monthly", was conducted on December 10, 1992.

In preparation for observing the test, the inspector conducted a partial walkdown of the AFW system, using the AFW P&ID, drawing number 33013-1237, as the system configuration reference.

The inspector noted that two normally closed valves in the steam generator chemical addition lines in both the "A" and "B" motor-driven AFW pump trains appeared, by stem position, to be open.

The inspector reported this apparent discrepancy to the shift supervisor and an auxiliary operator (AO) was dispatched to determine the actual positions of the valves.

All four valves were found to be, in fact, open.

The valves were returned to their normal shut position.

Chemical addition via the AFW system is normally performed only while the plant is shut down.

Review of turbine system operating procedure (T)-7Q, "Chemical Addition Using 1E Secondary Chemical Addition Tank", revealed that only two of the four valves in question are restored to their normally shut position upon completion of the procedure.

The last such chemical addition had'been performed on June 11, 1992.

Through review of records, the licensee determined that two steam generator chemical additions had been made on that date, but that no completed T-7Q procedure existed to document the second addition.

The licensee concluded that the cause of the valves being out of their required positions was 1) that procedure T-7Q had not been used when chemicals were last added to the steam generators via the AFW system, and 2) that T-7Q did not fully restore the chemical addition path to its normal at-power alignment.

In neither of the above cases did the valves being out of their normal positions affect the operability of the systems.

Nonetheless, the inspector was concerned that the procedures used for these two surveillance tests did not adequately'ontrol system configuration.

Further investigation revealed the cause to be inconsistency between the initial system lineup procedures and surveillance test and normal operating procedures.

As a.result of these examples, the licensee conducted walkdowns of primary mechanical safety systems to verify at-power alignment, and initiated a comprehensive review of sa'fety system procedures with respect to system alignments.

No safety significant valve misalignments were identified.

The procedure review was in progress at the close of the inspection period and is being coordinated by the licensee under CAR-2069.

The inspector had no further questions in this area.

4.0 SECURITY (71707)

4.1 Routine Observations During this inspection period, the resident inspectors verified that x-ray machines and metal and explosive detectors were operable, protected area and vital area bamers were well maintained, personnel were properly badged for unescorted or escorted access, and

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compensatory measures were implemented when necessary.

Adequate compensatory measures were provided to support ongoing site security upgrade modifications.

No unacceptable conditions were identified.

4.2 Inverter Failure On December 6, 1992, at 10:59 p.m, an electrical inverter that serves as the nor'mal power supply for site security systems failed.

Power to these systems was quickly transferred to the redundant backup source, with no loss of safeguards capability.

Through discussions with licensee representatives, the inspector determined that the site security, operations, and

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maintenance departments promptly responded to assure that security systems would not be.

compromised until repairs were completed and that compensatory measures were in place to address further contingencies.

5.0 EMERGENCY PREPAREDNESS (71707)

5.1 Unannounced Emergency Preparedness Drill On November 11, 1992, the licensee conducted an off-hours, unannounced emergency preparedness drill to test the ability of the RG&E's emergency response organizations to staff key positions promptly.

The drill was'designed as a mustering drill, intended to mobilize selected positions in the emergency organization that are essential for facility activation.

These minimum staffing positions include those identified in the Nuclear Emergency Response Plan as the Technical Support Center, Emergency Operations Facility, Operations Support Center, Engineering Support Center, Joint Emergency News Center, and Survey Center.

Other emergency organization staff positions not required to be physically present-during the drill were notified by telephone, but were not required to report to the site.

Through participation in'this exercise, the inspector determined that the staffing of the licensee's site and off-site emergency response organizations wa's achieved within 60 minutes

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following the declaration of a simulated Site Area Emergency.

The drill began at 8:00 p.m.-

on November 11, 1992 and was secured at approximately 10:00 p.m. when all facilities had the minimum positions staffed for activation and the Technical Support Center had assumed command and control of the simulated emergency.

The inspector determined that the drill was well controlled and met the guidance of NUREG-0654.11.N. l-.b.

5.2 Meteorological Tower Maintenance As a result of aging equipment, the primary (250 foot) meteorological tower was removed from service and refurbished during the period October 26 through December 2, 1992.

To assure that adequate sources of meteorological data were readily available while the main tower was out of service, the licensee's Emergency Preparedness Department identified several back-up capabilities and revised relevant emergency preparedness implementing procedures (EPIPs) to incorporate these measures.

Compensatory measures available during

the primary tower refurbishment included use of the back-up tower, and communications with the National Weather Service, local media meteorologists, and power control goad

'dispatcher).

In addition to the back-up tower, wind speed/direction data was available using communication links with RG&E substation 230.

To verify reliability of substation 13A instrumentation, reliability was verified three times per week and substation 230 operability was verified weekly, RG&E EP personnel met with operations management and shift supervisors to inform them of EPIP procedure changes and compensatory measures in place.

Refurbishment of the primary meteorological tower included:

replacement of meteorological sensors, i.e., wind speed/direction and temperature indication; installation of new signal conditioning equipment, recorders, and communication links; upgrading lightning protection devices; and, installation of a back-up, stand alone AC generator to provide.AC power should normal service be interrupted.

The inspector determined that licensee actions in identifying compensatory measures and disseminating information to operations personnel regarding these measures when the primary tower was out of service were well planned.

6.0 ENGINEERING/TECHNICALSUPPORT (71707, 92701)

"C" Safety Injection Pump Discharge Cross-Connect Valves Crossover Logic The safety injection (SI) system is designed to inject high pressure borated water into the reactor vessel in the event of an accident that results in loss of reactor coolant inventory.

The system consists of two redundant and independent flow paths ("A" and "B" trains), each supplied by a pump that is powered from one of two safety-grade 480-volt electrical buses.

To satisfy single failure criteria (that'is, to maintain both SI trains operable in the event of a pump failure or loss of one safety-grade electrical bus), the system contains a third ("C")

pump that can be powered from either electrical bus and can supply either of the two discharge headers.

The control circuitry for the "C" SI pump discharge cross-connect valves was designed such that the valves would close individually iftheir associated primary SI pump failed, but would remain open ifboth primary SI pumps failed (breakers open).

The SI system would therefore be maintained fully functional ifa. single primary SI pump failed, and at least partially functional (with half the rated flow being maintained to both discharge headers)

even ifboth primary SI pumps failed.

During this inspection period, the licensee reported a design weakness in the control'circuit for the "C" SI pump discharge cross-connect valves for the situation in which one primary SI pump breaker is removed or racked;out rather than tripped, a condition permitted for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Ifa safety injection initiated in that condition and the other primary SI pump failed (breaker tripped),- the discharge cross-connect valves would close, rather than remain open, thus isolating the "C" SI pump and rendering the SI system completely inoperabl As interim corrective action, the licensee issued instructions to preclude,'removal of either primary SI pump motor breaker without further guidance from the site technical division.

, Were such action to become necessary, the pump motor breakei condition contact would be jumpered prior to breaker removal so that the breaker would be seen as tripped.

An engineering work request (EWR 10079) was generated to evaluate permanent corrective action.

This design deficiency was identified as a result of problems experienced by technicians performing SI system testing during the 1992 refueling outage.

The test, refueling shutdown surveillance procedure (RSSP)-23,,"Safety Injection Pump C Interlock Verification", had been revised to allow testing of each pump independent of the others; the 1992 outage was the first time that this revised procedure had been used.

When MOV-871A stroke timing was first attempted, the valve did not operate.

The technicians realized that the "B" SI pump motor breaker was not installed at the time due to'ongoing maintenance; since it contains a portion of the cross-connect valve crossover logic, the technicians correctly attributed the test failure to the missing breaker.

With the "B" SI pump motor breaker reinstalled, MOV-871A stroke testing was successfully completed.

This problem was noted in the comments section-of the completed test.

The subsequent routine engineering review was thorough, and correctly identified this obscure design deficiency.

6.2*

Safety Injection System Piping Supports During containment spray pump testing per PT-3M, "Containment Spray Pump Monthly Test", the inspector noted that operation of the "A" CS pump induced vibrations in the piping between the discharge of valve V-1817 (SI pump "C" suction relief valve to CS pump header) and the CS system discharge header.

The vibration,was in the horizontal plane and was only observed during operation of the "A" CS pump.

The inspector was concerned that this vibration produced visible flexure of V-1817 relative to the SI suction piping; given that the 0.75-inch diameter pipe that connects V-1817 to the SI suction piping is very short (approximately four inches in length), such flexure appeared to be excessive.

The inspector discussed this concern with the licensee.

As a result, the licensee generated an engineering work request (10080) to evaluate the condition.

6.3 Steam Generator Replacement On December 16, 1992, RG&E announced that it will replace the two steam generators at the Ginna Nuclear Plant in 1996.

Cost of replacement is estimated at $ 115 million. The generators cost about $40 million, and installation will cost about $60 million. The remainder of'the cost is.for engineering and support services.

Installation of the new steam generators will take about three months and is tentatively scheduled for March - June 199 fe

Over its 22 years of operation, Ginna has experienced degradation in some of the 3,260 tubes that makeup each steam generator.

About 30 percent of the tubes have. required repair.

In addition, chemical fouling of the tubes has reduced their'eat transfer capability, causing a loss in plant capacity of three peicent, or 15 megawatts.

The existing steam generators will be removed through the reactor building dome using a crane..They willbe placed in a protective structure that willbe built on the Ginna site.

7.0, SAFETY ASSESSMEAT/QUALITYVERIFICATION(90712, 90713, 92701, 40500)

7.1 Quality Assurance/Quality Control Subcommittee Meeting On December 2, 1992; the inspector attended the quarterly meeting of the RG&E corporate QA/QC subcommittee.

The inspector observed that senior corporate management was provided independent and objective information regarding the results of comprehensive assessments and audits of plant performance trends, From this meeting, the inspector concluded that the QA/QC subcommittee was an effective management tool for the self identification and resolution of site programmatic issues.

7.2 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 monthly operating reports for October and November 1992 were reviewed.

No unacceptable-conditions were identified.

8.0 ADMINISTRATIVE(71707, 30702, 94600)

8.1 Backshift and Deep Backshift Inspection During this inspection period, a backshift inspection was conducted on November 11, 1992.

Deep backshift inspections were conducted on the following dates:

November 7, 21, 29, and December 13, 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 inspections.

The exit meeting for inspection report 50-244/92-16 (security inspection, conducted October 26-29, 1992) was held'by Mr. A. Della Ratta,on October 30, 1992.

The exit meeting for'nspection report 50-244/92-18 (engineering inspection, conducted November 9-13, 1992) was held by Mr. Neal

. Della Greca on November 13, 1992.

The exit meeting for inspection report 50-244/92-19

(health physics inspection, conducted December 14-18, 1992) was held by Mr. James Noggle on December 18, 1992.

The exit meeting for inspection report 50-244/92-17 was held on December 18, 199 e