IR 05000244/1993012

Insp Rept 50-244/93-12 on 930610-0731.Violations Noted.Major Areas Inspected:Plant Operations,Maint,Engineering & Plant Support

ML17263A366
Person / Time
Site:	Ginna
Issue date:	08/16/1993
From:	Lazarus W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML17263A365	List: IR 05000244/1993012 ML17263A364
References
50-244-93-12, NUDOCS 9308230187
Download: ML17263A366 (23)

Text

U. S. NUCLEAR REGULATORY COMMISSION

REGION I

Inspection Report 50-244/93-12 License: DPR-18 Facility:

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

Inspection:

Inspectors:

June 10 through July 31, 1993 T. A. Moslak, Senior Resident Inspector, Ginna E.

utson, Resident Inspector, Ginna Approved by:

W. J. Laz irus, Chief, Reactor rojects Section 3B INSPECTION SCOPE ae Plant operations, maintenance, engineering, and plant support.

INSPECTION OVERVIEW Operations The plant operated at full power throughout the inspection period.

A partial engineered safety features actuation occurred on July 7, 1993, when a condensate system transient resulted in a momentary "B" steam generator feedwater isolation due to high level.

Prompt operhtor action successfully restored normal conditions.

The Plant Operations Review Committee consistently demonstrated a strong safety perspective in addressing and resolving issues.

Maintenance The "B" service water pump breaker failed to operate during a routine pump shift. No material deficiency was identified that could account for the failure. Following cleaning, lubrication, and extensive operational testing, the breaker was returned to service.

The "C" service water pump breaker failed similarly in May 1993, and was replaced.

The licensee is attempting to establish the root cause of these breaker malfunctions through continuing troubleshooting of the failed breaker.

9308230i87 9308ih PDR ADOCK 05000244

PDR

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INSPECTION OVERVIEW (Continued)

Engineering Improper control rod motion occurred on June 29, 1993, when one of the two rod groups in control bank D moved outward in response to an inward demand signal from the automatic rod control system.

The problem could not be duplicated during subsequent troubleshooting.

A supervisory logic circuit card was replaced as the most likely source of the malfunction; following this, however, the problem again occurred on July 5, 1993, while attempting to exercise rods in control bank D. AHcircuit cards associated with the outward rod motion signal were subsequently replaced and there have since been no recurrences of abnormal rod motion.

Although the replaced cards have undergone extensive testing, the cause of this intermittent problem has yet to be identified.

Licensee response has been conservative, methodical and comprehensive.

Efforts to identify the cause of the problem are continuing.

From review of balance-of-plant maintenance records, the licensee identified a potential mechanism for stem/disc separation in Crane 143'A valves installed in safety-related portions of the service water system.

Operability of these valves was promptly verified by radiographic examination.

Licensee implementation of 10 CFR 21 requirements for reporting ofdefects and noncompliance was examined and found to be effective.

Plant Support Significant reductions in auxiliary building radiation levels achieved through extensive decontamination of the waste holdup tank, floor drains, and the residual heat removal system subbasement sump, demonstrated a proactive approach to reduce dose expenditures and lower the site radioactive waste inventory.

Good ALARAawareness and execution were observed in association with several containment entries.

A simulator-driven emergency preparedness mini-drillprovided effective, realistic training for the Technical Support Center and Emergency Off-site Facility emergency response teams.

The Quality Assurance/Quality Control Subcommittee was effective in conveying findings and trends of factors affecting the quality of plant performance and material conditio TABLEOF CONTENTS VERVIEW e

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TABLE OF CONTENTS 1.0 OPERATIONS (71707)

1.1 Operational Experiences 1.2 Control ofOperations..............

1.3 Partial Engineered Safety Features Actuation 1.4 Plant Operations Review Committee (PORC)

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Meetings

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3 2.0 MAINTENANCE(62703, 61726).................

2.1 Corrective Maintenance 2.1.1 Routine Observations................

2.1.2

"B" Service Water Pump Breaker Malfunction 2.2 Surveillance Observations 2.2.1 Routine Observations................

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3.0 ENGINEERING (71707, 92701)

3.1 Rod Control System Malfunction................

3.2 Service Water System Valve Failure..............

3.3 Implementation of 10 CFR Part 21 Requirements (36100)

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4.0 4.6 4.7 4.8 PLANT SUPPORT (71707)

4.1 Radiological Controls.......................

4.1.1 Routine Observations..................

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4.1.2 Auxiliary Building Decontamination 4.1.3 Containment Entries

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4.2.1 Routine Observations...................

4 ~3 Fire Protection......................

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4.3.1 Routine Observations...................

4.3.2 Licensee Actions on Previous Inspection Findings

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4.4 Chemistry..............................

4.4.1 Routine Observations...................

4.5 Emergency Preparedness.....................

4.5.1 Simulator-Driven Mini-Drill Quality Assurance/Quality Control (QA/QC) Subcommittee Peood'eports..........................

Licensee Event Reports......................

Meeting

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13 5.0 ADMINISTRATIVE(71707, 30702, 94600)

5.1 Enforcement Conference.....................

5.2 Backshift and Deep Backshift Inspection 5..3 Exit Meetings

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DETAIIS 1.0 OPERATIONS (71707)

1.1 Operational Experiences The plant operated at full power (approximately 98 percent) throughout the inspection period.

On July 7, 1993, a partial engineered safety features (ESF) actuation occurred when a

condensate system transient resulted in a momentary "B" steam generator feedwater isolation due to high water level.

Prompt operator action successfully restored normal conditions.

There were no other significant operational events during the inspection period.

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 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 Partial Engineered Safety Features Actuation On July 7, 1993, Instrument and Controls (1&C) technicians began troubleshooting to correct a locked-in low level alarm for the SA feedwater heater.

In the course of this effort, a technician disconnected instrument air (IA)from the SA feedwater heater high level dump valve, AOV-3347. By design, the valve failed to the open position; however, because the valve had not first been isolated, its opening initiated a transient on the condensate and feedwater systems.

The SA feedwater heater high level dump valve directs flow to the heater drain tank (HDT).

As a result of AOV-3347 failing open, a high level condition developed in the HDT.

In response, the HDT high level dump valve opened, connecting the HDT directly to the main condenser hotwell. Since the HDT operates at approximately 120 psig and the main condenser hotwell operates in a vacuum, this mechanism rapidly restores normal HDT level; however, in the process, HDT pump discharge flow also is greatly reduced.

The two HDT pumps, along with two condensate pumps, supply condensate to the suctions of the main feedwater pumps (MFPs), with the HDT pumps normally supplying approximately one third of this flow.

Under normal conditions, a third (standby)

condensate pump would automatically start and the low pressure feedwater heaters condensate bypass valve would operate to make up for the lost HDT pump flow, should the HDT high level dump valve actuate.

In this case, however, these components had been secured as part of an unrelated but concurrent

procedure to place the all-volatile treatment (AVT) mixed bed ion exchanger in service (T-6.9A). As a result, flow to the main feedwater pumps was reduced by approximately one third when the HDT dumped to the main condenser.

The reduced supply flow consequently reduced the MFP output flow. The advanced digital feedwater control system (ADFCS) responded to the reduction in flowby opening the "B" steam generator feedwater regulating valve more fully, in an attempt to maintain a constant mass flow rate.

The "A" steam generator feedwater regulating valve was operating in manual control (as discussed in inspection report 50-244/93-10) and consequently was not affected by the change in feedwater fiow.

Within seconds of disconnecting the IAline, the I&Ctechnician observed the HDT dump valve opening and realized that this would cause an operational problem.

He quickly reconnected the IA line, which restored the SA heater high level dump valve to normal operation.

The HDT high level condition promptly cleared and the HDT dump valve closed.

This restored normal condensate flowto the MFPs. Atthis point, however, the difference between demand and actual feedwater fiowexceeded the ADFCS limitfor automatic operation, and the system automatically shifted to manual.

In such a transition, the feedwater regulating valves fail as-is; consequently, the "B" steam generator feedwater regulating valve remained positioned for reduced flow after normal feedwater flow had been restored.

This resulted in rising water level in the "B" steam generator.

In the control room, operators realized that ADFCS had shifted to manual,'and attempted to regain control of water level in the "B" steam generator.

However, they were unsuccessful in adequately reducing feedwater flow prior to level reaching the feedwater header isolation ESF setpoint.

A total of five feedwater header ESF isolation signals were generated in a period of 14 seconds as level in the "B" steam generator hovered about the 67 percent ESF setpoint and then began to lower.

Operators then successfully restored normal level in the "B" steam generator and reestablished steady state plant operations.

The inspector observed the transient from the control room.

The inspector noted excellent communications between the I&C technician and the control room operators.

This aided operators in understanding the basis of the transient and contributed to the prompt, correct operator responses.

The inspector observed that the operator was nearly successful in averting the feedwater header ESF isolation through manual control ofthe "B" steam generator feedwater regulating valve.

The inspector considered this to be noteworthy, in that manual feedwater control at full power can be challenging even under steady-state conditions; despite the momentary ESF isolation, the operator was successful in restoring normal level in the "B" steam generator.

The inspector was concerned, however, that inadequate maintenance control apparently contributed to the initiating transient.

At the close of the inspection period, the licensee was preparing a licensee event report on this transient.

The inspector willcontinue to monitor licensee evaluation and corrective action for the event through development and review of this repor.4 Plant Operations Review Committee (PORC) Meetings The inspector attended various PORC meetings frequently held during this reporting period.

These meetings, chaired by the Superintendent, Ginna Production, addressed the safety implications ofongoing station modifications, procedure changes, station event reports (A-25.1),

safety-related equipment status (A-52.4), Plant Management/Shift Technical Advisor, Health Physicist, and Fire Protection Engineer plant tour observations, status of 10 CFR 50.59 evaluations, and review of potential 10 CFR 21 reportability items.

Safety, regulatory, and administrative issues were thoroughly discussed and appropriately resolved.

The inspector concluded that the PORC meetings were an effective safety assessment mechanism within the licensee organization.

2.0 MAINTFAANCE(62703, 61726)

2.1 Corrective Maintenance 2.1.1 Routine Observations The inspector observed portions of maintenance activities to verify that correct parts and tools were utilized, applicable industry code and technical specification requirements were satisfied, adequate measures were in place to.ensure personnel safety and prevent damage to plant structures, systems, and components, and to ensure that equipment operability was verified upon completion.

The following maintenance activities were observed:

Work Order 9301008, "AuxiliaryFeedwater Pump A - Adjust Shaft Packing," conducted per maintenance procedure (M)-11.5C, "AuxiliaryFeedwater Pump Minor Mechanical Inspection and Maintenance," revision 21, effective date June 18,-1992, observed June 18, 1993 Work Order 9340658,

"Service Water Pump "C"- Major Inspection," (pump motor electrical connection), conducted per M-11.10, "MajorInspection ofService Water Pump C", revision 23, procedure change notice (PCN) 93T-666, effective date October 29, 1992, observed June 25, 1993 Work Order 9301054,

"Rod Control System," supervisory logic circuit card (A109)

replacement, observed July 1, 1993 Work Order 9320871, "Repair/Test/Replace Valve 8623, Safety Injection," conducted per M-37.79, "Inspection and/or Maintenance of Kerotest Y-Pattern Check Valves,"

revision 5, effective date May 27, 1993, observed July 7, 1993

2.1.2

"B" Service Water Pump Breaker Malfunction On June 30, 1993, the "B" service water (SW) pump failed to start during a normal shift of operating pumps. A second attempt was made to start the pump, which was also unsuccessful.

An auxiliary operator at the scene reported hearing a clicking noise coming from the "B" SW pump breaker.

Normal operation of the SW system was not interrupted by this failure.

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"B" SW pump was declared inoperable; due to ongoing acceptance testing of the "C" SW pump following completion of scheduled maintenance, only two SW pumps ("A" and "D") remained operable.

Although this configuration is acceptable for unrestricted operation per technical specification 3.3.4, the licensee entered a self-imposed 72-hour action statement that had been generated in response to NRC concerns identified during a 1992 service water system inspection (50-244/92-80).

The "B" SW pump breaker was removed for troubleshooting.

Inspection revealed no abnormalities, although technicians considered operation of the breaker to be stiffer than expected.

After cleaning and lubrication, the breaker was repeatedly bench cycled without failure. The breaker was reinstalled and cycled in the test position, again without failure. The breaker was then returned to service and a normal pump start from the control room was performed.

Both the breaker and the pump operated normally.

The "B" SW pump breaker had undergone vendor refurbishment less than a year prior to this failure. The "C" SW pump breaker had similarly failed to operate in May, 1993; in that case, the breaker was replaced and troubleshooting of the defective breaker is still in progress.

The inspector considered the licensee's response to failure of the "B" service water pump breaker to have been appropriate.

Adherence to the voluntary 72-hour action statement demonstrated commitment to conservative plant operations.

Although stiffoperation is difficult to definitively establish as the cause of a breaker failure, the inspector considered that troubleshooting, corrective action, and acceptance testing had adequately established breaker operability in this case.

In addition, ongoing troubleshooting of the "C" SW pump breaker demonstrated the licensee's intention to identify the root cause of these breaker failures.

2.2 SurveBlance Observations 2.2.1 Routine Observations Inspectors observed portions ofsurveillances to verifyproper calibration oftest instrumentation, use of approved procedures, performance of work by qualified personnel, conformance to limitingconditions for operation (LCOs), and correct system restoration following testing.

The following surveillances were observed:

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Performance Test (PT)-16M-T, "Auxiliary Feedwater Turbine Pump - Monthly,"

revision 4, effective date May 14, 1993, observed June 28, 1993

The turbine low oil pressure trip occurred at 3.6 psig, which was outside the specified normal band of 2.5 to 3.5 psig.

This portion of the test was repeated three additional times, with results ranging from 4.2 to 3.5 psig.

Gauge calibration was subsequently checked and found to be indicating 0.4 psi higher than actual pressure.

Oil regulating valve output pressure was low outside the normal band (18 psig, normal band 20 psig or greater).

This, along with the above problem, was evaluated by corporate engineering and determined not to adversely affect pump operability.

Valve 9512C (TDAFW pump suction pressure gauge isolation) was erroneously listed in the procedure as valve 9251C.

The error was noted by test personnel and was corrected by PCN (93T-669) prior to operation of this valve.

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PT-9.1.14,

"Undervoltage Protection

- 480 Volt Safeguard Bus 14," revision 14, effective date March 26, 1993, observed July 1, 1993

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PT-1, "Rod Control System (control bank D only)," revision 33, effective date December 11, 1992, observed July 6, 1993

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PT-16Q-A, "Auxiliary Feedwater Pump A - Quarterly," revision 9, PCN 93T-677,

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effective date July 1, 1993, observed July 8, 1993 The inspector determined through observing this testing that operations and test personnel adhered to procedures, test results and equipment operating parameters met acceptance criteria, and redundant equipment was available for emergency operation.

3.0 ENGINEERING (71707, 92701)

3.1 Rod Control System Malfunction At approximately 9:00 PM on June 29, 1993, with the rod control system in automatic, bank D control rods received a signal to step-in in response to a small change in average reactor coolant temperature.

Following receipt of this signal, rod motion began but was automatically stopped when a "Rod Control Urgent Failure" alarm (C-30) was received.

Control room operators immediately implemented the abnormal operation procedure, AP-RCC.2, "Rod Control Cluster / Rod Position Indication Malfunction, to identify the cause of the alarm.

Examination of the rod position indication step counters revealed that the two control rods (C-07 and K-07)

in group 1 of bank D had moved out, contrary to the demand signal, one step from their initial position of 211 steps to 212 steps, while the rods (G-03 and G-11) in group 2 of bank D had moved, as demanded, in one step from 210 steps to 209 steps.

Subsequently, operators placed the rod control system in manual, confirmed rod position on the microprocessor rod position indication (MRPI) system, and verified that reactor operating parameters had not significantly change Plant management, engineering, and technical staffs began a series ofdiagnostic tests to identify the cause of the inappropriate rod movement.

Examination of the rod control system logic cabinet revealed that the urgent alarm resulted from a system malfunction indicated on the 1BD slave cycler integrated circuit card. Initialtroubleshooting involved resetting C-30 and, with the rods in their misaligned positions, performing the rod exercise test (PT-1) while signal current traces were taken.

Subsequently, the bank D rods were realigned and tested again.

During both tests, the rod control system worked properly with no indications of what had caused the malfunction.

Since the problem could not be duplicated, a possible cause was attributed to the intermittent buildup of heat in the rod control cabinets, affecting heat-sensitive components in the slave cycler circuitry. Until there was reasonable assurance that the cause of the rod control problem had been identified and corrected, the licensee maintained the rod control system in manual and exercised the bank D rods daily per PT-1, to ensure the system was functioning properly.

Additionally, ventilation in the area of the rod control cabinets was increased to mitigate potential temperature-related effects.

Upon conferring with Westinghouse, the licensee's staff considered that either the master cycler logic card or the supervisory logic 2 card could have caused the problem.

On July 1, 1993, the supervisory logic 2 card (A-109) was replaced and tested satisfactorily by performance ofPT-1.

On July 5, 1993, when performing PT-1 for bank D rods, group 2 stepped in from 212 steps to 211 steps, while group 1 stepped out from 212 steps to 213 steps upon attempting to insert bank D rods.

No alarms were received at this time.

As the next step in troubleshooting, the master cycler logic card (A-105) was replaced.

Again, subsequent testing showed that both rod groups responded correctly and produced no abnormal current traces.

However, because the nature of the problem was intermitted, the root cause of the problem could not be confirmed through this testing.

On July 7, 1993, the licensee contacted Westinghouse and cognizant personnel at the Salem Nuclear Station for assistance.

The decision was made that the best approach to eliminate the problem from the system and also to pinpoint the cause was to replace all printed circuit cards associated with the "up" signal and to test the removed cards at Salem.

The following cards were replaced in the logic cabinet and taken to the Salem training facility for testing:

A-105, A-109, A-108, A-112, A-113, A-208, Master Cycler Logic Supervisory Logic 2 Supervisory Logic 1 Supervisory Buffer Memory Supervisory Data Logging Bank Overlap Logic 1A Although operating anomalies were identified in various circuit cards, the original problem could not be repeated, nor could heat be directly attributed to degraded operatio Testing results did indicate that a faulty logic gate on the master cycler logic card (A-105)

contributed to problems the licensee has experienced in the past, such as groups stepping out of sequence and rods being out of alignment by two steps.

However, this component could not be directly attributed to causing one group of rods moving in and one group moving out.

The licensee is continuing troubleshooting the circuit cards to identify the failure cause.

Suspect cards have been sent to the'rod control system simulator at the Braidwood Nuclear Facility for additional testing by Westinghouse specialists.

Should a definite cause not be established through these efforts, the licensee will dissect individual subcomponents from the cards and return them to the manufacturer (Motorola) for analysis.

Until there is reasonable assurance that the cause of the rod control problem has been resolved, the rod control system willremain in manual, with increased frequency of exercising the bank D rods.

Through close observation ofthe licensee's response to the malfunction, the inspector concluded that operators appropriately responded to the initial incident, adhering to relevant procedures, and that follow-upby site management and the RG&E engineering staff was methodically carried out.

The inspector determined that, in these specific instances, the inappropriate rod motion had no impact on plant stability or reactor safety.

The safety function of the control rods to shut down the reactor upon initiation of a reactor trip signal was not compromised.

Since the bank D rods are maintained at approximately 210 steps, which is near the fullywithdrawn position (228 steps)

and therefore, a low worth core region, there was no significant change in reactor power or quadrant power tiltas a result of two rods stepping one step in a contrary direction to demand.

3.2 Service Water System Valve FaBure On June 15, 1993, the licensee informed the inspector ofa potential problem with certain valves in safety-related portions of the service water (SW) system.

The problem had been identified during review of completed outage maintenance by the valve preventative maintenance analyst.

The analyst noted that stem/disc separation had been reported as the as-found condition during maintenance on valve 4674 (bus duct cooler SW outlet isolation). This valve is a Crane model 143'h and is located in a non-safety related portion of the SW system.

The analyst determined, however, that three Crane model 143'h valves are installed in the safety-related portion of the SW system.

These valves are V-4622 (spent fuel pool heat exchanger "A"SW outlet isolation),

and V-4671 and 4672 (EDG "A" and "B" heat exchangers SW outlet blocks).

The licensee reviewed the failure of V-4674 to determine what action should be taken with regards to Crane model 143'A valves currently serving in safety-related applications.

The stem/disc separation that occurred on V-4674 had been due to the disc backing out of its threaded connection to the stem, apparently as a result of flow-induced vibration.

As manufactured, these valves have a lock weld installed between the stem and disc to prevent such

e inadvertent separation.

However, this is a weld between dissimilar metals (the disc is a nickel-copper alloy and the stem is 410 stainless steel) and, as such, is susceptible to cracking. Failure of the lock weld due to cracking could then allow the disc to rotate offof the stem.

Given this failure mechanism, the licensee concluded that, while the condition of the lock weld could not be determined by means short ofvalve disassembly, it should be possible to verify the integrity of the stem/disc union by radiography.

Radiographic examination showed full stem/disc engagement for the three Crane model 143'h valves in question.

The licensee is currently evaluating further corrective action.

The inspector observed radiographs of the three valves in question and saw no evidence that the discs were backing offof the stems.

The inspector assessed that this action was timely and that iteffectively established near term operability ofthe three valves in question.

The inspector will continue to follow the development of long-term corrective actions.

3.3 Implementation of 10 CFR Part 21 Requirements (36100)

The inspector reviewed relevant procedures, interviewed cognizant licensee representatives, and examined supporting records to determine ifthe licensee effectively implements the requirements of 10 CFR 21, "Reporting of Defects and Noncompliance."

In conducting this inspection, the inspector determined that the licensee has prominently posted the requirements and has implemented the following Administrative (A) and Quality Engineering (QE) procedures to assure that deviations identified in basic components are systematically evaluated and reported:

A-61, Method ofEvaluation for Reporting Requirements in Basic Components under 10 CFR 21 A-401, Control of Procurement Documents Prepared at Ginna Station A-405, Evaluation of Commercial Grade Items for Safety-Related Applications A-1502, Nonconformance Reports A-1601, Corrective Actions Reports A-1606, Identified Deficiency Reports QE-1604, Performing "Substantial Safety Hazard" Evaluations for 10 CFR 21 Reportability Through these procedures and management structure, RG&E engineering, procurement, and quality assurance organizations have the administrative controls, including reporting time frames and identification ofresponsible corporate officer for making notifications, necessary to comply with Part 21 requirements.

To determine the effectiveness of these procedures, Substantial Safety Hazard Evaluations were reviewed for the following three nonconformance reports (NCRs):

NCR 93-188, "A" Service Water Pump First Stage Impeller Oversized

NCR 93-129, Shipping ofIncorrect Parts by a Local Valve and Fitting Supplier to Ginna Station NCR 91-613, Incomplete Calibration Services Provided by a Vendor Through this review, the inspector concluded that the evaluations were detailed and complete, and logically substantiated that a safety hazard did not exist for the identified condition. As part of the inspection effort, the inspector reviewed a recent Part 21 report.

In accordance with the reporting requirements of 10 CFR 21, (c)(3)(i) and (ii) respectively, on June 22, 1993, the licensee made initial notification, by facsimile, to the NRC Operations Center, with a follow-up written notification submitted on July 20, 1993, regarding a defect identified in the component cooling water (CCW) heat exchangers.

Specifically, the licensee identified, through eddy current testing and engineering analysis, that tubes in the immediate vicinityofthe CCW heat exchanger shell side inlet and outlet nozzles were susceptible to fretting at the tube support plate locations due to high, localized fluid velocities at the nozzle locations.

The flowinduced vibration and subsequent tube degradation occurs at design flow rates and was not originally considered by the component's manufacturer.

Although no tube failures have occurred, the results ofrecent eddy current examinations, when compared with earlier inspection results, confirmed that an active wear phenomena existed for both heat exchangers.

As immediate corrective action, all tubes with through-wall indications greater than 70 percent were plugged and a new maximum CCW flow rate was established to minimize future tube degradation.

In addition to making the Part 21 notification, the licensee provided this information to the Nuclear Network and Nuclear Plant Reliability Data System to advise the industry of a condition that was not considered in the original design of this component.

From a review of the licensee actions on this matter, the inspector concluded that the licensee has implemented the requirements of Part 21 to assure that defects identified in original plant equipment, procured components, and contracted services affecting safety-related equipment are promptly and thoroughly evaluated, and that the appropriate notifications are made, ifrequired.

4.0 PLANT SUPPORT (71707)

4.1 Radiological Controls 4.1.1 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, survey information was kept current, and postings and labeling were in compliance with regulatory requirements.

Through observations ofongoing activities and discussions with plant personnel, the inspectors concluded that radiological controls were conscientiously implemente The inspector participated in a routine monthly containment entry.

On July 1, 1993, the inspector attended the pre-entry ALARAbriefing as required by administrative procedure (A)-3,

"Containment Vessel Access Requirements."

The inspector considered that this briefing adequately discussed precautions to be taken and considerations to minimize personnel exposure while coordinating several different maintenance and testing activities.

The containment entry was conducted on July 7, 1993.

The inspector observed results and test (R&T) personnel involved in testing ofthe containment recirculation fan coolers, operations personnel conducting a test of the containment sump level detection system, and maintenance personnel conducting repairs on a nitrogen system check valve. The inspector observed excellent ALARAawareness on the part of the workers and conscientious oversite of activities by health physics technicians.

The inspector concluded that the principles of ALARA were effectively implemented in association with this containment entry.

4.1.2 AuxiliaryBuilding Decontamination During this inspection period, the licensee completed various efforts to lower auxiliary building radiation field source terms.

Desludging of the waste holdup tank, associated floor drain piping, and the residual heat removal system subbasement sump was effectively carried out.

General area radiation levels and loose surface contamination were significantly reduced to permit downgrading ofthe waste holdup tank room from a locked high radiation area to a high radiation area.

These tasks were well coordinated between the site health physics department and the contractor, with a total collective dose of about 6.3 person-rem.

The inspector concluded that this effort demonstrated the licensee's proactive approach to reduce future dose expenditures and lower the site radioactive waste inventory.

4.1.3 Containment Entries A series of containment entries were made to investigate a small steam leak.

Following identification ofa small increase in the "A"containment sump pump down frequency, operations and radiological controls personnel initially entered containment on July 19, 1993, but were unable to pinpoint the leak source, although the leak location was determined to be in the general vicinity of the "B" reactor coolant pump (RCP).

Before continuing further, due to the high radiation fields in this area, licensee management established an ALARAtask group to develop a formal plan to identify the leak, while minimizing personnel dose.

Following installation of a robotic camera, lighting, and communications equipment, a containment entry on July 22, 1993, identified the leak to be coming from a blind flange downstream of the "B" RCP number one seal bypass vent valve (V-206B). A work package was then compiled to stop the leak.

From a review oflicensee activities, the inspector concluded that control room operators astutely detected a small leak that had minor safety significance.

Additionally, site management assured that pre-job planning was thorough and made optimum use of remote monitoring and communication equipment to minimize personnel dos.2 Security 4;2.1 Routine Observations During this inspection period, the inspectors verified that x-ray machines and metal and explosive detectors were operable, protected area and vital area barriers were well maintained, personnel were properly badged for unescorted or escorted access, and compensatory measures were implemented when necessary.

No unacceptable conditions were identified.

4.3 Hre Protection 4.3.1 Routine Observations The inspectors periodically verified the adequacy of combustible material controls and storage in safety-related areas ofthe plant, monitored transient fire loads, verified the operability offire detection and suppression systems, assessed the condition of fire barriers, and verified the adequacy of required compensatory measures.

No discrepancies were noted.

4.3.2 Licensee Actions on Previous Inspection Findings

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(Closed)

Violation (50-244/93-06-01),

"Containment Recirculation Fan Cooling System (CRFCS) Roughing Filter Fire" The inspector reviewed the adequacy of the licensee's corrective actions taken in response to a fire that occurred on the CRFCS roughing filters on March 19, 1993.

Actions included specifying additional conservative fire prevention measures in the administrative (A) procedure A-905, "Open Flame, Welding and Grinding Permit" to either totally remove or encapsulated filters prior to beginning hot work, treat all ventilation filter media as combustible materials when specifying fire protection measures, and instituting a monthly visual inspection of the CRFCS roughing filters for combustible material accumulation.

The latter inspection procedure will incorporate guidance contained in ANSI-N510, 1989, Testing of Nuclear Air Cleaning Systems."

Through this review, the inspector concluded that the licensee's actions were comprehensive to adequately address the finding. This item is closed.

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(Closed) Violation (50-244/93-10-01), "Inadequate Fire Prevention Measures During a Grinding Operation" The inspector reviewed licensee actions regarding improving fire prevention measures when conducting metal grinding. As immediate action, the Fire Protection Engineer held an awareness critique with fire protection personnel regarding the proper implementation of the relevant fire prevention procedures.

Additionally, the Fire Protection Engineer requested changes be made to the General Employee Training Lesson Plan to heighten all plant personnel's awareness of

fire protection requirements.

The licensee is tracking implementation of this action through Correction Action Report (CAR) 2076.

Through this review, the inspector concluded that the licensee s actions were prompt and adequate in addressing this matter.

This item is closed.

4.4 Chemistry 4.4.1 Routine Observations The inspectors periodically verified that plant chemistry was within technical specification and procedural limits, monitored reactor coolant and secondary water activity and radiation monitor trends and alarm status to confirm fuel cladding and steam generator tube integrity, and verified that the results of chemical analyses were maintained within established industry standards.

No discrepancies were noted.

4.5 Emergency Preparedness 4.5.1 Simulator-Driven Mini-Drill On July 21, 1993, an emergency preparedness mini-drillwas conducted; scope was limited to mobilizing the site Technical Support Center (TSC) and Emergency Operations Facility (EOF).

Parameters displayed on the TSC and EOF data links were generated by the plant's training simulator. A critique was held upon drillcompletion.

The inspector examined various aspects of this drill and concluded that the drill scenario was sufficiently challenging, use of the simulator and associated displays in the TSC and EOF provided realism, and the drill did not impact normal plant operation.

4.6 Quality Assurance/Quality Control (QA/QC) Subcommittee Meeting On July 29, 1993, the inspector attended the RG&E QA/QC Subcommittee meeting.

The meeting, chaired by senior licensee management, addressed the status, findings, and trends identified in various audits, surveillance programs, and corrective action systems.

A summary of the Corrective Action Performance Indicators presented to the subcommittee showed improvements in overall site performance for data gathered from July 1991 through June 1993.

No new areas of concern were evident that required further detailed analysis or warranted increased management attention.

The status of various open items, including implementation of a peer verification program to augment the quality control effort, was discussed in detail.

Through this attendance, the inspector concluded that senior licensee management was properly informed of factors affecting the quality of overall plant performance and material condition.

Issues are thoroughly and candidly discussed with action items assigned to assure a timely resolution of unresolved concerns.

Management expectations in addressing issues were clearly state.7 Periodic Reports Periodic reports submitted by the licensee pursuant to Technical Specification 6.9.1 were reviewed.

Inspectors verified that the reports contained information required by the NRC, that test results and/or supporting information were consistent with design predictions and performance specifications, and that reported information was accurate.

The following reports were reviewed:

Monthly Operating Reports for May and June, 1993 No unacceptable conditions were identified.

4.8 Licensee Event Reports A licensee event report (LER) voluntarily submitted to the NRC was reviewed to determine whether details were clearly reported, causes were properly identified, and corrective actions were appropriate.

The inspectors also assessed whether potential safety consequences were properly evaluated, generic implications were indicated, events warranted onsite follow-up, and applicable requirements of 10 CFR 50.72 were met.

The following LER was reviewed (Note: date indicated is event date):

93-003, During Planned Maintenance, Failures of Safeguard Service Water System Valves Were Discovered (March 28, 1993)

The inspector concluded that the LER was accurate and met regulatory requirements.

No unacceptable conditions were identified.

5.0 ADMINISTRATIVE(71707, 30702, 94600)

5.1 Enforcement Conference An enforcement conference was held on July 16, 1993, to discuss corrective action for service water system valve failures identified during the 1993 refueling outage.

Results of this conference are presented in a NRC letter dated July 22, 1993, forwarding the Notice of Violation.

5.2 Backshift and Deep Backshift Inspection During this inspection period, a backshift inspection was conducted on June 29, 1993.

Deep backshift inspections were conducted on the following dates:

June 27, 30, July 5 and 6, 199.3 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 50-244/93-13 (engineering programs review, conducted June 14-18, 1993) was held by Mr. Harold Gregg on June 18, 1993. The exit meeting for inspection report 50-244/93-14 (personnel dosimetry, conducted July 12-16, 1993) was held by Mr. James Noggle on July 16, 1993.

The exit meeting for inspection report 50-244/93-12 was held on August 3, 1993.