IR 05000244/1997005

Insp Rept 50-244/97-05 on 970519-0629.No Violations Noted. Major Areas Inspected:Operations,Maint,Engineering & Plant Support

ML17264A966
Person / Time
Site:	Ginna
Issue date:	07/25/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML17264A965	List: IR 05000244/1997005 ML17264A964
References
50-244-97-05, 50-244-97-5, NUDOCS 9708010072
Download: ML17264A966 (47)

Text

U.S. NUCLEAR REGULATORY COMMISSION REGION I

License No.

DPR-18 Report No.

50-244/97-05 Docket No.

50-244 Licensee:

Facility Name:

Location:

Inspection Period:

I Inspectors:

Rochester Gas and Electric Corporation (RGRE)

R. E. Ginna Nuclear Power Plant 1503 Lake Road

'Ontario, New York 14519 May 19, 1997 through June 29, 1997 P. D. Drysdale, Senior Resident Inspector C. C. Osterholtz', Resident Inspector J. C. Jang, Senior Radiation Specialist Approved by:

L. T. Doerflein, Chief Projects Branch

Division of Reactor Projects 9708010072 970725 PDR ADQCK 05000244

PDR

EXECUTIVE SUMMARY R. E. Ginna Nuclear Power Plant NRC Inspection Report 50-'244/97-05 This integrated inspection included aspects of licensee operations, engineering, maintenance, and plant support.

The report covered a 6-week period of resident inspection.

In addition, it includes the results of an announced inspection by a regional specialist in the effluent monitoring area.

~Oerationa The Ginna plant remained at full power throughout the inspection period.

No primary or secondary plant transients occurred, and there were no failures of safety-related equipment.

Only two nonsafety-related systems/components important to safety were out of service due to a malfunction or failure during the inspection period.

Operator performance throughout the inspection period was good.

The licensee fulfilled the technical specification requirements related to one inoperable door in each of the two containment airlocks.

Preparations to restore the doors to full operability were adequate, although this work had not yet been scheduled.

The licensee's response to reported Reactor Vessel Level Instrumentation System errors was prompt and conservative.

Changes made to the Emergency Operating Procedures minimized the impact on plant operators until a permanent modification can be'considered.

The licensee took conservative actions to maintain safety injection accumulator level within a restrictive operating band while resolving 'a discrepancy between indicated accumulator level and actual volume.

Safety Injection pump operation was required on two occasions to refillthe B-accumulator, but both accumulator levels remained relatively stable.

Maintenance Observed maintenance activities were performed in accordance with procedure requirements, with the exception of two maintenance packages that did not receive appropriate supervisory review. Technicians demonstrated generally good knowledge of

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their maintenance activities.

Adequate post-maintenance testing was performed prior to returning equipment to service.

Good personnel and plant safety practices were observed during all maintenance work.

The shift supervisor authorized all surveillance work observed; surveillance personnel qualifications were properly certified and minor performance issues were discussed with supervisors.

The as-found and as-left test data met the specified acceptance criteria and performance values stated in the Updated Final Safety Analysis Report.

The procedures used were current and properly followed.

The problems with water inleakage and crystal buildup in the residual heat removal pump room have not been fully corrected, and appeared to be recurring.

The planned

Executive Summary (cont'd)

~ maintenance.to completely seal the bottom of the fuel transfer canal has been appropriately scheduled prior to the next refueling outage.

~En ineerin Good troubleshooting efforts were displayed by the system engineer and maintenance technicians in determining the causes and corrective actions needed to restore the accuracy of the screenhouse level indicators.

The further efforts initiated to account for an additional 18 inches of screenhouse"water were appropriate.

e The licensee's efforts to determine the minimum screenhouse water level for service water pump operability were well supported by detailed engineering calculations.

Although additional actions were still in progress at the end of the inspection, the issues related to minimum pump net positive suction head and submergence appeared to be resolved.

The use of Probablistic Safety Assessment (PSA) in various engineering programs was still being proceduralized; however, the inspectors determined including PSA training in the qualification of system engineers was appropriate.

PSA training for system engineers was very good, and effectively highlighted its appropriate use.

Plant Su ort The licensee maintained and implemented good routine radioactive liquid and gaseous effluent control programs with capabilities to protect the public health and safety and the environment.

The calibration methodology for effluent/process RMS was good, however, the calibration methodology for area radiation monitoring systems was inconsistent.

A good ventilation system surveillance program was implemented.

However, the licensee had not fully resolved the inconsistencies between the ventilation system actual air flow capacities and those stated in the Updated Final Safety Analysis Report.

Airborne tritium released from the Spent Fuel Pool (SFP) suggested that the evaporation and/or leakage rates were not able to be determined even though there was a small leak; and a careful measurement should be obtained to determine the evaporation rate from the SFP due to various uncertainties.

The old steam generator storage facility appeared intact and well secured.

All interior spaces were clean and dry, and the facility was not being used to store any unauthorized.

materials.

No loose contamination was detected on external surfaces, and the facility did not appear to represent a radiological hazard to plant personnel or to any areas surrounding the site.

Effluent control procedures were sufficiently detailed to facilitate performance of all

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~ - necessary steps for.the. routine and emergency. operations.. The licensee. effectively implemented the Improved Technical Specifications/Offsite Dose Calculation Manual (ITS/ODCM) requirements for reporting effluent releases and projected doses to the publi Executive Summary (cont'd)

The licensee'.s ODCM had improved and contained sufficient specification, information, and instruction to acceptably implement and maintain the radioactive liquid and gaseous effluent control programs.

The licensee's corrective actions for failure to implement 10 CFR 19.11 posting requirements were prompt and adequate.

The overall consequences of this problem were minor.

In accordance with the NRC enforcement policy, this item is considered a non-cited violation and closed (NCV 50-244/97-05-01).

The full fire brigade responded promptly to an observed drill, and the drill evaluator performed an effective critique. The licensee's follow-up to inspector concerns for pulling fire hoses through narrow passages was effective and provided useful information for fire brigade member TABLE OF CONTENTS EXECUTIVE SUMMARY..

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II TABLE OF CONTENTS

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. Operations.....,..............,...........

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01.1 General Comments 01.2 Summary of Plant Status Operational Status of 'facilities and Equipment................

02.1 Inoperable Containment Airlock Doors.................

02.2 Errors in the Reactor Vessel Level Indication System (RVLIS).

02.3 Adjustments to the Safety Injection (Sl) Accumulator Level Operating Band.............. ~.....

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I. Maintenance I.

M1 Conduct of Maintenance M1.1 Observations of Maintenance Activities...... ~...

M1.2 Observations of Surveillance Activities M2 Maintenance and Material Condition of'Facilities and Equipment M2.1 (Update) IFI 95-15-01; Residual Heat Removal (RHR) Pump Room Inleakage..........

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III. Engineering E2 Engineering Support of Facilities and Equipment...............

E2.1 Screenhouse Level Indicator Errors E2.2 Service Water Pump Minimum Submergence and Net Positive Suction Head Requirements E5 Engineering Staff Training and Qualification..................

E5.1 Probabilistic Safety Assessment (PSA) Training for System

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I R1 Radiological Protection and Chemistry (RP&C) Controls...........

R1.1 Implementation of the Radioactive Liquid and Gaseous Effluent Control Programs

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R2 Status of RP&C Facilities and Equipment........

R2.1 Calibration of Effluent/Process/Area/Accident Radiation Monitoring Systems (RMS)..........................

R2.2 (Update) URI 50-244/96-01-05, Air Cleaning Systems Follow-Up

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R2.3 (Update) IFI 95-15-01, Follow-up of the Spent Fuel Pool Leakage R2.4 Old Steam Generator (SG) Storage Facility...............

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.RP&C Procedures and Documentation........................

R3.1 Chemistry and Radiological Effluent Procedures

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Table of Contents (cont'd)

R6 R7 F4 R3.2 (Closed) NCV 50-244/97-05'-01:

10 CFR 19.'1 1, Posting of Notices to Workers RP&C Organization and Administration R6.1 RP&C Organization and Administration of Effluent Controls..

Quality Assurance in Radiological Protection and Chemistry Activities R7.1 RP&C Audits of Effluents Program Activities Fire Protection Staff Knowledge and Performance F4.1 Fire Brigade Drills.........

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X1 Exit Meeting Summary.................

L2 Review of UFSAR Commitments............

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ATTACHMENTS Attachment 1 - Partial List of Persons Contacted

- Inspection Procedures Used

- Items Opened, Closed, and Discussed

- List of Acronyms Used

Re ort Details

Conduct of Operations'1.1 General Comments Ins ection Procedure IP 71707 The inspectors observed plaqt operations to verify that the facility was operated safely and in accordance with licensee procedures and regulatory requirements.

This review included 1) tours of the accessible areas of the facility; 2) verification that the plant was operated in conformance with the improved technical specifications (ITS), and appropriate action statements for out-of-service equipment were implemented; 3) verification of engineered safeguards features (ESF) system operability; 4) verification of proper control room and shift staffing; and 5)

verification that logs and records accurately identified equipment status or deficiencies.

01.2 Summa of Plant Status The Ginna plant rem'ained at full power throughout the inspection period.

During this period, no primary or secondary plant transients occurred, and there were no failures of safety-related equipment.

Offsite power was reduced to one source (circuit 767) from May 26 - 30, 1997 while preventive maintenance and testing was performed on the other source (circuit 751).

Significant nonsafety-related equipment that was out of service due to a malfunction or failure during the inspection period included the toxic gas monitor for the control room emergency air treatment system (CREATS), and the B-condensate storage tank (B-CST) due to high sodium levels.

The control room ventilation system was placed in the recirculation mode for approximately seven hours while repairs to the GREATS were accomplished; and the B-CST was drained and refilled. Operator performance throughout the inspection period was good.

Operational Status of Facilities and Equipment 02.1 Ino erable Containment Airlock Doors a.

Ins ection Sco e (71707)

The inspector reviewed the licensee's actions following a discovery that seals in the containment airlock inner doors would deteriorate in a high radiation environment,

'Topical headings such as 01, M8, etc., are used in accordance withthe NRC standardized reactor inspection report outline.

Individual reports are not expected to address all outline topic b.

Observations and Findin s The inner doors of both the containment personnel and equipment airlocks were declared inoperable on April 23, 1997, when the licensee determined that teflon seals in the door operating mechanism, and in air equalizing valves, were not qualified.for the harsh radiation environment that would exist inside containment following a loss of coolant accident (LOCA). The breakdown of the seal material was expected to occur in radiation fields of 10E4-10E7 rads.

The licensee considered the outer doors td be still operable with the plant at full power since they are shielded by the inner doors.

If the seals in the inner door were to fail in a post-LOCA environment, the air inside containment could enter the containment airlocks, but the radiation levels exposing the outer doors would be substantially lower and its seals would remain intact and maintain containment integrity. An analysis on post accident operability of the outer door seals showed that they would be exposed to approximately 6 Rem/hr maximum..

One inoperable door in both airlocks required entry into LCO 3.6.2 and verification once every 31 days th'at the operable (outer) door in each airlock is closed and locked.

The LCO allows opening the doors only to enter containment to conduct ITS required surveillance tests.

In the event that corrective maintenance was necessary inside containment, or other equipment problems occurred, the ITS would require entering LCO 3.0.5, and performing a shutdown to Mode 3 in 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, and to Mode 5 in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

Throughout the inspection period, the licensee evaluated various options for replacing the seals with a more radiation resistant material.

In order to complete the replacement, the doors must remain open and the entire door operating mechanism must be disassembled.

With the plant at power, the licensee would have to install a significant amount of neutron shielding near the doors to protect workers.

An estimated total exposure of 6 person-Rem would be expended to install the shielding and to complete repairs on both doors.

The licensee also evaluated the risk of experiencing a corrective maintenance problem inside containment prior to the refueling outage in October 1997.

That risk was not considered high enough to warrant an immediate repair of the doors.

At the end of the inspection, the licensee had not yet scheduled the repair and suggested that it may be deferred until the refueling outage.

However, the replacement parts were available and the job work packages were completed so that repairs could be accomplished during an unanticipated outage lasting more than two days, should that occur prior to October 1997.

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Conclusions The licensee fulfilledthe technical specification requirements related to one

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- ~.inoperable door-in each of the two containment.airlocks..Preparations to restore the doors to full operability were adequate, although this work had not yet been schedule '

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~ 3 Errors in the Reactor Vessel Level Indication S stem RVLIS

'ns ection Sco e (71707)

The inspector reviewed the licensee's actions following a report of errors in the RVLIS system at another Westinghouse plant.

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Observations and Findin s Both RVLIS instrument channels at the Ginna Station were. declared inoperable on June 19, 1997, after engineering evaluated a licensee event report (LER) from a Westinghouse 2-loop sister plant with a problem in the sensing line tubing of the instrument's, reference leg between the condensing pot and the reactor vessel head.

The reported problem was that the tubing did not fully drain when void conditions existed in the reactor vessel, and was not expected to drain if a void formed in the.

vessel following an accident.

The condition resulted in a nonconservative offset in the indicated level with respect to the actual level in the vessel.

RG&E engineering initiated an ACTION Report (97-0927) and evaluated the situation for the Ginna RVLIS instruments.

Their conclusion was that the same problem would likely exist at Ginna under the same circumstances.

RGSE and an outside engineering consultant independently calculated the offset to be 4% high with reactor coolant pumps (RCPs) running, and 9% high with no RCPs running.

The RVLIS instruments were not credited in any accident analysis for the Ginna Station.

However, operator actions are dependent on RVLIS indications in several emergency operating procedures (EOPs), and in the Critical Safety Function Status Trees for determining the entry conditions into functional restoration EOPs.

Operator actions are also dependent upon RVLIS indications once entry into the functional restoration procedures is made.

The instrument tubing between the condensing pot and the reactor head is over twenty feet long and was installed such that the tubing formed a loop seal along its length.

Since a near term modification to this tubing was not practical with the plant at full power, the licensee instead performed a safety evaluation to change the EOP procedures so that operator actions would be taken at the corrected RVLIS levels corresponding to the actual vessel levels that the actions were based upon.

The changed EOP setpoints accounted for the additional instrument error and minimized the impact on plant operators by avoiding an "operator aid" tag on the main control board.

The safety evaluation was approved by the plant operations review committee (PORC) on June 25, 1997, and 22 individual EOPs were subsequently changed to reflect the revised setpoints.

Both RVLIS channels were declared operable the following day after the EOPs were issued.

The licensee expected that an instrument modification would eventually be necessary to correct the condition, and would probably be accomplished during the next refueling outage

.-in October 1997. 'Plant operators were informed about. the RVLIS problem and the EOP changes through written "read and sign" concurrence The inspector inquired about the need to change the RVLIS instrument on the Ginna simulator.

The operator training organization indicated that an evaluation would be necessary before a change could be made. since the simulator currently has another anomaly in-those instruments that was being investigated.

However, a change was considered necessary so that the simulator would accurately model the actual plant under accident conditions.

In the mean time, the licensee stated that it may be necessary to add an operator aid to the simulator so that an allowance can be made for'the new EOP setpoints.

The inspector also inquired about the licensee's response to NRC Information Notice

{IN) 97-25, "Dynamic Range Uncertainties in the Reactor Vessel Level Instrumentation.

The IN described RVLIS errors up to a10% that could result from changes in reactor coolant system hydraulic parameters that may not have been accounted for in the RVLIS instrumentation.

The licensee initially indicated that all RCS flow parameters were fully accounted for during the steam generator replacement project and that the problems reported in the IN were not expected to represent a problem at Ginna.

However, engineering changed the due date for the IN review so that all RVLIS error concerns could be reviewed concurrently.

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Conclusions The licensee's response to the reported RVLIS errors was prompt and conservative.

Changes made to the EOPs minimized the impact on plant operators until a permanent modification can be considered.

The licensee's plans to model the simulator RVLIS instruments after the plant were appropriate.

02.3 Ad'ustments to the Safet In'ection Sl Accumulator Level 0 eratin Band aO Ins ection Sco e {71707)

The inspector reviewed the licensee's actions following the discovery that a computational error existed in the ITS specified operating band for Sl accumulator levels.

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Observations and Findin s During a review of a 10 CFR 50.46 {Acceptance criteria for emergency core cooling systems for light-water nuclear power reactors) annual report, the licensee determined that the calculation for converting percent accumulator level to actual accumulator volume in cubic feet {ft')was in error due to incorrect values being used for the accumulator inside radius.

The problem was reported on June 18, 1997 in ACTION Report 97-0960.

The level band currently specified in the ITS was 50% to 82%, supposedly corresponding to 1126 ft'nd 1154 ft', respectively.

- - -".-'-These values were transferred to the ITS from the old technical. specifications without verifying the level percentages with the actual volumes.

However, these volumes actually correspond to 67% and 99.7%, respectively.

Consequently, the licensee initiated a review of the. accumulator volumes assumed in the LOCA accident analysis.

In the interim, a conservative operating restriction was placed on

accumulator levels at 67% to 82% that would encompass"all computational errors, and until the minimum and maximum accumulator water volumes bounding the accident analysis could be verified. This also required an administrative restriction on the minimum and maximum water volumes currently specified in ITS surveillance requirement (SR) 3.5.1.2, i.e., 50% to 82%.

Plant operators had previously been refilling the accumulators upon reaching the low level annunciator setpoint (57%),

and fillingto a point just below the high level annunciator setpoint (75%).

The licensee changed operating procedure 0-6.13, "Daily Surveillance Logs," to reflect the narrower band, and added an operator aid to the main control board, 'also reflecting the new. band.

The Technical Requirements Manual (TRM) was changed to add administrative controls and a table (5.5-1) specifying the appropriate level band.

The inspector noted that the B-accumulator was exhibiting a slow level decrease over recent months and expressed a concern that the narrower level band could cause more frequent operation of Sl pumps in order to maintain the appropriate level. When the level discrepancy was first reported, the B-accumulator level had to be increased to bring it.into the new limits. The level was again increased on

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June 21, 1997.

The B-accumulator level did not require further adjustment for the remainder of the inspection period.

At the end of the inspection period, RG&E was working with Westinghouse to resolve this problem.

It.appeared that the 50% to 82% band will remain valid.

based on the large break LOCA analysis for Ginna.

The volumes corresponding to this band are 1111 ft'nd 1139 ft'.

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Conclusions The inspector concluded that the licensee took conservative actions to maintain accumulator level within the most restrictive operating band.

SI pump operation was required on two occasions to refill the B-accumulator, but both accumulator levels appeared stable thereafter.

II. Maintenance M1 Conduct of Maintenance M1.1 Observations of Maintenance Activities a.

Ins ection Sco e 62707

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components, and to ensure that equipment operability wak verified upon completion of post maintenance testing.

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Observations and Findin s The inspectors observed all or portions of the following.work activities:

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CPI-LVL-3005, "Calibration of Screen House Level Loop 3005;" observed on June 17, 1997.

The calibration had been scheduled for performance at a later date, but it was rescheduled to an earlier date due to the recent concern over the accuracy of the screenhouse.water level instruments (see Section E2.1).

The local gage (Ll-3007), plant process computer point transmitter (LT-3005), and main control board transmitter (LT-3006) did not have consistent indications.

Work Order 19700361, Replacement of LT-3006 bubbler tube; observed on June 19, 1997.

The replaced tube had become clogged with hard mineral-like deposits, causing a high back pressure in the instrument and an incorrect level indication.,

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CPI-TRIP-TEST-5.10, "Reactor Protection System Trip Test/Calibration For Channel 1 (Red) Bistable Alarms," and CPI-TRIP-TEST-5.20, "Reactor Protection System Trip Test/Calibration For Channel 2 (White) Bistable Alarms;" observed on June 23, 1997.

No bistable setpoint adjustments were required as a result of these calibrations.

However, the inspector observed a label on the main control board (MCB) bistable status panel light for the A-Main Steam Loop "Lo" Steam pressure, (PC-469A) did not agree with the label on the bistable in the instrumentation cabinet.

Also, the plant process computer point (P0469A) description ("Stm Line A Lo Press 2/3 Sl")

did not agree with the bistable label.

The procedure indicated the labels as observed on both the bistable and the status panel.

Control room operators suggested that the MCB label should indicate "Lo-Lo" steam pressure (514 psig), since "Lo" steam pressure is actually defined as 600 psig and that some confusion could result over the actual pressure trip setpoint.

The operators wrote an ACTION Report to evaluate all bistable status light labels and to determine if labels, computer points, and procedures should be changed to make them consistent.

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CPI-TRIP-TEST-5.30, "Reactor Protection System Trip Test/Calibration For Channel 3 (Blue) Bistable Alarms," and CPI-TRIP-TEST-5.40, "Reactor Protection System Trip Test/Calibration For Channel 4 (Yellow) Bistable Alarms," observed on June 24, 1997.

No bistable setpoint adjustments were required as a result of the calibrations.

The same bistable label problem existed for the B Main Steam. Loop bistable status. lights and the computer points as noted on Channels 1 and 2 abov ~

. CPI-AXIAL-N41,"Calibration of Nuclear Instrument System Power Range N41 Axial Offset," and CPI-AXIAL-N42,"Calibration of Nuclear Instrument System Power Range N42 Axial Offset;" observed on June 23, 1997.

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CPI-AXIAL-N43,"Calibration of Nuclear Instrument System Power Range N43 Axial Offset," and CPI-AXIAL-N44,"Calibration of Nuclear Instrument System Power Range N44 Axial Offset;" observed on June 24, 1997.

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M-32.1.50, "DB-50 Circuit Breaker Maintenance;"

B-RHR pump, breaker cleaning, inspection, and lubrication;:observed on June 25, 1997.

Two secondary contacts were slightly bent and were replaced.

The package included a post maintenance test to restore the breaker to service.

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M-11.4.13, "Charging Pump Drive Lubrication and Inspection."

B-and C-Charging Pump Vari-Drive 4 month inspection, lubrication, and oil sample; observed on June 24, 25, and 26, 1997.

The maintenance was properly performed; however, the inspector noted that the mechanical maintenance supervisor did not review and sign the work packages for each pump before they were forwarded to the PM analyst.

This was discussed with the mechanical maintenance manager for follow-up.

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M-11.4.4, "Charging Pump Vari-Drive Overhaul Unit," B-and C-Charging Pumps Vari-Drive belt replacement; observed on June 25 and 26, 1997.

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Conclusions The inspectors concluded that the observed maintenance activities were performed in accordance with the procedural requirements, with the exception of two maintenance packages that did not receive appropriate supervisory review. The technicians demonstrated generally good knowledge of the maintenance

.requirements for the affected equipment.

The equipment received adequate post-maintenance testing prior to its return to service.

Good personnel and plant safety practices were observed during all maintenance work.

IVI1.2 Observations of Surveillance Activities a 0 Ins ection Sco e 61726 The inspectors observed selected surveillance tests to verify that approved procedures were in use, procedure details were adequate, test instrumentation was properly calibrated and used, technical specifications were satisfied, testing was performed by qualified and knowledgeable personnel, and test results satisfied acceptance criteria or were properly dispositione b.

Observations and Findin s

'I The inspectors observed portions of the following surveillance activities:

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PT-11, "60 Cell Battery Banks "A" 5 "B" and Spare Cells;" observed on June 2, 1997. This was a quarterly test for station battery voltage, specific gravity, loss of charging alarms, and electrolyte level ~ The inspector noted a minor issue when one technician misplaced several decimal points in the recorded data for specific gravity on the B-cells, The technician had been assigned as a helper on this job and was.not fully trained on all of its tasks.

However, the data was immediately corrected by a fully qualified electrical technician who was leading the job. The electrical technician demonstrated good knowledge of the test procedure and its requirements.

He also demonstrated good knowledge of the bases for the test acceptance criteria and of vendor manual specifications for the batteries.

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M-15.10, "1A or 1B Emergency Diesel Generator Underground Fuel Oil Storage Tank Leak Tightness Testing;" Annual static tank test for leakage;

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Oil samples were also obtained for sediment, water content, and viscosity.

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PT-12.2, "Emergency Diesel Generator B," B-EDG monthly ITS surveillance; observed on June 18, 1997.,

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PT-16Q-T, "AuxiliaryFeedwater Turbine Pump - Quarterly;" observed on June 19, 1997.

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PT-2.2Q, "Residual Heat Removal System - Quarterly;" observed on June 25, 1997.

All pump parameters within their required specifications except that the horizontal inboard pump bearing was still in its American Society of Mechanical Engineers (ASME)Section XI "alert range" due to high vibration (vertical direction) ~ The inspector verified that the vibration had been stable over several months and did not show an increasing trend.

The pump has been on an increased surveillance interval since October 1996 and will remain on an increased frequency of 45 days until the vibration subsides, or the pump is repaired.

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Conclusions The inspector confirmed that the shift supervisor authorized all surveillance work to proceed; surveillance personnel qualifications were properly certified and minor performance issues were discussed with the supervisors.

The as-found and as-left test data met the specified acceptance criteria and performance values stated in the

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"-Updated Final Safety Analysis Report-(UFSAR), and.the, procedures used were current and properly followe M2 NI2.1 Maintenance and Material Condition of Facilities and Equipment U date IFI 95-15-01'esidual Heat Removal RHR Pum Room Inleaka e

Ins ection Sco e (62707)

The inspector toured the RHR pump room to observe the material condition of plant equipment in the room and to observe the current amount of water inleakage through wall seams and pipin'g penetrations, b.

Observations and Findin s In July 1995, the NRC reported a large buildup of hard scale mineral deposits on RHR pump room walls, and the presence of water inleakage through wall penetrations.

Since then, the licensee had taken several actions to capture all water entering the room, to identify all likely sources of the water, to remove the scale deposits, and to refurbish the entire room.

Boric acid and various nuclides were present in the water entering the room, which identified the adjacent spent fuel pool

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During the last refueling outage, the licensee sealed part of the bottom of the fuel transfer canal in an effort to block one suspected leak path from the SFP to the RHR pump room and to allow the walls to dfy.

On June 25, 1997, the inspector toured the RHR pump room to observe the amount of water currently leaking into the room from the fuel transfer canal.

The canal had been filled approximately three weeks earlier to accommodate removal of the SFP weir gate and replacement of its seal.

The inspector observed a notable accumulation of.hard crystalline deposits on the west, north, and east walls of the room, and all three walls were wet from water inleakage.

The water was slowly flowing down these walls and was collecting in puddles on the floor around both RHR pump pedestals.

The temporary leakage collection system previously installed to collect water from the fuel transfer canal on the west wall was collecting only a small part of the water entering onto that wall, and was not able to collect any of the water on the north and east walls. An RP technician reported that he was emptying the 55 gallon barrel used with the collection system approximately once per week when the barrel was one-half full to completely full. The inspector was concerned that the mineral deposits on all three walls appeared to contain boron crystals, and that potentially new leak paths from the transfer canal to the pump room had resulted from fillingthe fuel transfer canal.

The licensee took samples of the crystals and performed a laboratory analysis of its chemical constituents, which indicated that the crystals contained less than 1%

boric acid in solution (the remainder was primarily sodium chloride).

The boric acid

-" --level was above. the natural concentration in ground waterand suggested that the origin of some of the water inleakage was from the SFP.

However, the licensee did not conclude that potentially new leak paths were resulting from the water in the transfer canal due to the long standing presence of boron near piping penetrations in all pump room walls from past problems with blockage in the installed SFP leak

~ 10 collection system.

The licensee planned to drain the fuel transfer canal after the weir gate seal'was replaced> and to prepare the canal for additional maintenance that will seal the remaining surfaces where the leakage-most likely occurred.

That work is scheduled to take place in mid August 1997.

The licensee also indicated that the condition of the RHR pump room will be reevaluated and the necessary actions taken to prevent the conditions noted in 1995 from recurring.

C.

Conclusions The inspector concluded that the original problems with water inleakage and crystal buildup have not been fully corrected, and that they appeared to be recurring.

The planned maintenance to completely seal the bottom of the fuel transfer canal have been appropriately scheduled prior to the next refueling outage.

III. En ineerin E2 Engineering Support of Facilities and Equipment E2.1 Screenhouse Level Indicator Errors

Ins ection Sco e (37551)

The inspector reviewed the licensee's actions to troubleshoot errors in the screenhouse water level instrumentation.

b.

Observations and Findin s During a routine tour of the screenhouse on May 13, 1997, the inspector noted a

discrepancy between the three screenhouse bay water level instruments and the instrument that measures differential water pressure across the traveling screens.

The screenhouse level indicators use a "bubbler tube" installed in the screenhouse water, and a low air flow at a pressure corresponding to the water depth above the bottom'of the tube.

The corresponding transmitters and gage respond to the back

.pressure of the air. The local gage upstream of the travelling screens (LI-3007)

indicated 305 inches (25.4 ft), and the downstream level detector (LT-3006)

indicated 27.5 ft. Since the upstream level is never lower than the downstream level, the inspector discussed the apparent errors with the system engineer.

The system engineer initiated an ACTION Report to investigate the problem, and operators were informed that the main control board level indication was nonconservative.

The main control board annunciators for screenhouse water level alarm at 20 ft, 17 ft, and 15 ft. and a preliminary review suggested that these levels would still provide good margin for service water pump operability including

- the level instrument errors.

The licensee performed a calibration of the level detectors on June 17, 1997.

During the calibration, technicians noted that both transmitters and the local gage were calibrated accurately with respect to the air pressure driving the instruments.

I

~ 11 However, the difference between the indicated water level and the level actually measured using a tape measure suggested that one of the instruments may have had an air leak.

The system engineer requested that the bubbler tubes be measured to ascertain their actual. length for comparison with their design length.

The technicians measured the length of the LT-3006 tube and found it to be in accordance with the as-built installation drawings.

However,.the tube's internals were partially blocked with solid deposits, which would cause it to have a higher back pressure, and would account for its error.

Also during troubleshooting, it became apparent that all of the level indicators were not accounting for 18 inches of water in the screenhouse bay since the end of the tubes were installed at 18 inches above the inlet floor. At the end of the inspection period, the system engineer planned to work with the instrumentation and control maintenance group to determine if the level transmitters and the local gage could be offset to read accurately and account for the additional 18 inches of screenhouse water depth.

Conclusions In response to the inspector's concerns,"the system engineer and maintenance technicians displayed good troubleshooting efforts in determining the causes and corrective actions needed to restore the accuracy and consistency of the screenhouse level indicators.

The further efforts initiated to account for the additional 18 inches of water were considered appropriate.

Service Water Pum Minimum Submer ence and Net Positive Suction Head Ins ection Sco e (37551)

The inspector reviewed the licensee's actions to review the ITS basis statement that the service water pumps would remain operable with screenhouse water level at the same elevation as the pump inlet.

Observations and Findin s The inspectors reported in IR 50-244/97-01 (Section E2.3) that the ITS basis stated that the service water pumps would remain operable with the screenhouse water level at 5 feet.

However, the bottom of the pump inlet is also at the 5 foot elevation.

The inspectors were concerned that no minimum water level was specified in operations procedures to assure adequate net positive suction head (NPSH) for the pumps, and that no engineering analysis for this value was available.

Consequently, the licensee initiated an ACTION Report (97-0572) to evaluate the minimum water level required for pump operability.

Engineering also requested the control room operators to declare the pumps inoperable if the water level dropped to 10 feet.

On June 11, 1997, the li'censee completed design analysis DA-ME-97-050, "Service Water Pump Submergence and NPSH Requirements, Including Suction Strainer Fouling Limits," (Rev.0).

The calculation was performed at an assumed water inlet

~ 12 temperature of 75 degrees fahrenheit ('F)'and determined that the minimum NPSH available at the instantaneous low lake level stated in the UFSAR was greater than the minimum NPSH required for the pump, as stated by the pump manufacturer.

Tlie analysis also concluded that the minimum "submergence level" to prevent vortexing and air entrainment into.the inlet water was more limiting for pump operability than minimum NPSH at the low lake level. The analysis determined that 14.0 feet of water in the screenhouse would provided sufficient submergence to prevent vortexing.

This level is approximately 3 feet below the instantaneous low

'ake level in the screenhouse The licensee also completed an evaluation for minimum submergence for the diesel and electric fire pumps, both of which are higher than the service water pumps.

That evaluation concluded that the fire pumps must have 17.0 feet of water in the screenhouse to remain operable.

i C.

The inspector questioned if the NPSH available at the minimum submergence level with inlet water at the design basis maximum of 80 F would also be sufficient to satisfy the vendor requirements'for minimum NPSH.

The licensee stated that the additional 5 F above the analyzed temperature would only effect the vapor pressure component of NPSH by an insignificant amount ((1 ft) and that the submergence level would still be more limiting than NPSH. 'The licensee intended to initiate a change to operating'procedure 0-6.13, "Daily Surveillance Log," to specify the corrected value for minimum screenhouse level during operator shift rounds'.

Emergency response procedure ER-SC-3, "Low Screenhouse Water Level," and the ITS basis will both be changed to specify 14.0 feet as the lowest allowed water level for service water pump operability.

Conclusions The inspector concluded that the licensee's efforts to determine the minimum screenhouse water level for service water pump operability were well supported by detailed engineering calculations.

Although additional actions were still in progress at the end of the inspection, the issues related to minimum pump NPSH and submergence appeared to be resolved.

E5 Engineering Staff Training and Qualification E5.1 Probabilistic Safet Assessment PSA Trainin for S stem En ineers Ins ection Sco e (37551)

The inspector attended PSA training provided for system engineers conducted by the principal author of the PSA.

b.

Observations and Findin s The licensee completed a substantial revision to the "Level 1" PSA (dealing with internal plant events that could lead to core damage)

and submitted it to the NRC on January 15, 1997.

The PSA was developed in response to NRC Generic Letter 88-20, "Individual Plant Examination for Severe Accident Vulnerabilities."

I

. 13 The use of the PSA in engineering has not yet been fully proceduralized in the various established engineering processes.

All modifications currently require a plant change impact review to determine ifthey could impact maintenance rule requirements.

Equipment modifications that could reflect changes in the performance or unavailability of equipment assumed in the PSA will require, engineering review to ensure the PSA and maintenance rule programs remain consistent.

In addition, all EOP changes will be reviewed by the engineering maintenance rule coordinator to determine if there could be any impact on PSA assumptions or conclusions. "'Also, system engineers will be expected to understand the risk significance associated with removing components from service to do on-line maintenance.

Equipment that has risk significance is identified in the PSA. The licensee indicated that they intended to continue to formally proceduralize the use of the PSA in engineering activities.

On June 6, 1997, the licensee conducted PSA training for system engineers in order to review fundamental PSA terminology; to review the most risk significant components and systems at Ginna; to highlight complex system interactions and dependencies that have a high risk significance; to understand initiating events and their relative contribution to core damage frequencies; and to review event and fault trees, and PSA cut sets.

System engineering managers also attended the training and considered making it mandatory training for the qualification of system engineers.

C.

Conclusions The use of PSA in engineering has not yet been fully proceduralized in the various established engineering programs.

However, the inspector considered it appropriate to have PSA training in the qualification of system engineers.

The inspector also concluded that the PSA training for system engineers was very good, and effectively highlighted its appropriate use.

IV. Plant Su ort R1 Radiological Protection and Chemistry (RPLC) Controls R1.1 Im lementation of the Radioactive Li uid and Gaseous Effluent Control Pro rams a.

Ins ection Sco e 84750-01 The inspection consisted of 1) a tour of radioactive liquid and gaseous effluent pathways and process facilities, and the main control room; 2) a review of radioactive liquid and gaseous effluent release permits; and 3) a review of unplanned or unmonitored release pathway b.

Observations and Findin s The inspector toured the main control room and selected radioactive liquid and gas processing facilities and equipment, including effluent/process/area radiation monitors and air cleaning systems.

All equipment was operable at the time of the tour.

Observed effluent/process/area radiation monitors were. also operable.

However, the inspector noted at the display panel in the control room that the containment high range area monitor was out-of-service.

The licensee stated that this monitor will be repaired during the refueling outage scheduled to commence during the summer of 1997.

The licensee maintained a negative pressure in the auxiliary building.'he inspector observed that there were several flow measurement holes (uncovered)

in various ventilation ducts.

The inspector also observed degraded material conditions at the bends, joints, and elbows. 'The inspector noted that the licensee did not have a program for ventilation system improvement, and discussed this issue with the licensee.

During review of selected radioactive liquid and gaseous effluent discharge permits, the inspector determined that discharge permits were complete and met the Improved Technical Specification/Offsite Dose Calculation Manual (ITS/ODCM)

requirements for sampling and analyses at the frequencies and lower limits of detection (LLD) established in the ITS/ODCM. The inspector noted that the licensee had reviewed the effluent control programs relative to NRC Bulletin No. 80-10,

"Contamination of Nonradioactive System and Resulting Potential for Unmonitored, Uncontrolled Release of Radioactivity to Environment."

C.

Conclusions Based on the above reviews, the inspector determined that the licensee maintained and implemented good routine radioactive liquid and gaseous effluent control programs with capabilities to protect the public health and safety and the

'environment.

The inspector also determined that the licensee should have a program for improvement of the ventilation systems.

R2 Status of RP8cC Facilities and Equipment R2.1 Calibration of Effluent Process Area Accident Radiation Monitorin S stems RMS a 0 Ins ection Sco e 84750-01 The inspector reviewed the most recent calibration results for the following selected effluent/process/area/accident radiation monitors:

~

Containment Area Monitors (R-29 and R-30)

~, Spent Fuel Pool Area Monitor (R-5)

~

Control Room Area Monitor (R-1)

~

Containment Purge Noble Gas Monitor (R-12 and R-12A)

~

Plant Vent Noble Gas Monitor (R-14 and R-14A)

~

Plant Vent Flow Rate Monitor (RM-14)

~ 15

. Condenser Air Ejector Monitor (R-15A and R-15A) " "

Component Cooling Water Detector (R-17)

Containment Fan Coolers Monitor (R-16)

Liquid Waste Disposal Monitor (R-18)

Main Steam Line Monitors (R-31 and R-32)

Turbine Building Floor Drain Monitor (R-21)

Steam Generator Blowdown Monitor (R-19)

Spent Fuel Pool Heat Exchanger Detectors (R-20 A&B)

b.

Observations and Findin s The Instrumentation and Controls (l&C) department and the RP/Chemistry department performed electronic and radiological calibrations for the above radiation monitors.

All reviewed calibration results were within the licensee's acceptance criteria.

However, the inspector identified that the licensee had an inconsistent calibration methodology for the area radiation monitoring system, such as containment area monitor (R-30). The licensee stated that all area radiation monitor calibration procedures would be reviewed and updated accordingly.

/

The inspector discussed the maintenance and operability/reliability of the RMS with the system engineer who was recently assigned-to the system (October 1996).

The inspector noted that the system engineer had experience primarily in the area of RMS design engineering, but not in calibration methodology, detector physics, and tracking/trending of the systems.

During the discussion, the inspector noted that the system engineer displayed a good sense of ownership of the RMS and an eagerness to learn the system in a short time. The inspector noted that in-house training was available.

The inspector also noted that the licensee performed daily trending analysis for the above RMS in the main control room.

The licensee plotted RMS readings twice a day on the control charts to track any changes.

The system engineer uses the data to calculate availability of the effluent RMS, which the inspector considered good.

The system engineer also assessed the RMS status on a quarterly basis.

The inspector reviewed the status report for the first quarter of the 1997, and considered it to be good.

The inspector also noted that the licensee added the RMS to the maintenance rule program as appropriate under the scoping criteria for the rule.

C.

Conclusions Based on the above reviews and discussion, the inspector concluded that the licensee's calibration methodology for effluent/process RMS was good; however, the calibration methodology for area radiation monitoring systems was inconsistent.

.- --

~ -=The-system. engineer. exhibited good ownership. of the.RMS,.regularly tracked the availability, and reported RMS status quarterly.

Adding the RMS to the maintenance rule practice was appropriat ~ 16 R2.2 U date URI 5 -244 96-01-05 Air Cleanin S stems Folldw-u a.

Ins ection Sco e 84750-01 The inspector reviewed the licensee's most recent surveillance test results (visual inspection, in-place HEPA leak tests, in-place charcoal leak tests, air capacity tests, pressure drop tests, and laboratory tests for the iodine collection efficiencies) for the control room emergency.air supply systems and containment air recirculation system.

The inspector also reviewed the corrective actions for unresolved item (URI 50-244/96-01-05)

~ The unresolved item related to inconsistencies between the actual air flow capacities for the main control room and the auxiliary building, and the airflow capacities stated in the UFSAR; and to the air flow balance for several plant ventilation systems.

b.

Observations and Findin s All:surveillance test results'for the control room emergency ventilation operation and containment air recirculation systems met the ITS acceptance criteria. The inspector had no further questions regarding the reviewed surveillance tests.

The inspector discussed the corrective actions for the unresolved item with the newly assigned HVAC system engineer and a nuclear safety and licensing representative.

The licensee retrieved and reviewed design basis data; however, they experienced some difficulties in'justifying the original data because several system modifications had been made.

Therefore, the licensee was in the process of collecting and evaluating the necessary design/modification basis justification and data.

The inspector noted that the licensee had completed the review of a large portion of the plant ventilation syste'ms.

The licensee state'd that the corrective actions were expected to be complete in the near future, possibly in July 1997.

c.

Conclusions I

Based on the above reviews and discussion, the inspector determined that the licensee implemented a good surveillance program.

'The inspector noted that the licensee's efforts to correct the unresolved item were taking longer than expected due to the large number of modifications made over the life of the plant, and the fact that the HVAC system engineer was newly assigned.

R2.3 U date IFI 95-15-01 Follow-u of the S ent Fuel Pool Leaka e

a.

Ins ection Sco e 84750-01 During a previous inspection (IR 50-244/96-01), an NRC inspector reviewed the licensee's investigation results for the spent fuel pool (SFP) leakage, including planned future actions.

This inspection consisted of 1) a review of tritium analytical results of water samples obtained from the shallow, middle, and deep levels of I

~ 17 Well C; 2) a review of the program to monitor and evaluate ground water movement; 3) a review of the licensee's actions for resolution of suspected SFP leakage; and 4) a review of the quantification technique for analyzing the airborne tritium released from the SFP.

b.

Observations and Findin s The analytical results from the samples of the shallow depth of Well C indicated that tritium activity had decreased since March 1996.The highest activity was measured in February 1996 which was 1.75E-5 pCI/cc.

The measurement results of the shallow depth indicated that the source of tritium at Well C was caused by a badly eroded underground steam generator blowdown line. After the licensee discovered the eroded line and repaired it, the tritium activity decreased.

The 1997 analytical results of the shallow depth of Well C were below the lower limit of detection (LLD) which was 6.0E-6 pCI/cc.

The middle and deep levels of Well C were installed in August 1996 and analytical results of the 1996 and 1997 samples were below or near the LLD.

During a previous inspection, in an effort to provide for assessment of suspected leakage, the licensee planned to: 1) install a deeper monitoring well (or a multi-level monitoring well) adjacent to Well C and analyze ground water samples;.2) continue to monitor and analyze samples from on-site Wells A, 8, and C; 3) continue to monitor and evaluate ground water movement; and 4) determine actions for resolution of the suspected leakage.

The inspector verified the licensee completed the above items with the exception of the Item 4, which had not been fully evaluated by the licensee.

The ground water movement was studied by an RG&E consultant.

At a meeting with the NRC on May 1, 1996, the consultant presented the tritium underground migration study results, and described the underground water mixing ratio. The

'tudy concluded that the underground water movement was slow at the location of Well C. The inspector, therefore, believed that tritium measurements for three depths of Well C should be continued until small fluctuations in the results are obtaine'd.

The licensee stated that the tritium monitoring program for Well C would be continued.

The inspector also reviewed the licensee's capability to monitor and quantify airborne tritium. The licensee calculated the total amount of water loss from the SFP during June-September 1996.

The licensee assumed that water loss was due to evaporation from the SFP, about 0.04 gpm (gallons per minute), to the environment via the plant vent, In consideration of the SFP surface dimensions and air movement near the pool surface, the inspector noted the loss of 0.04 gpm appeared to be too small.

In addition, using SFP tritium measurement results, the

~

~ -

'= "

'-licensee calculated the airborne tritium released through.the plant.vent during June-September 1996 to be 5A4 curies.

The licensee measured and reported that, for the same period of time, 14.2 curies of airborne tritium were released through the plant vent. Although the licensee's assumptions and calculation methodologies were good in monitoring and quantifying airborne tritium releases, the major source

of error appeared to be the SFP makeup water inventory. %n accurate SFP makeup water inventory was a crucial factor to determine either the leakage and/or evaporation rates.

The inspector was info'rmed that the responsible individual had left the company and that the information was not transferred to another person, which may have contributed to the calculation errors.

The licensee planned to repair the leak before the 1997 refueling outage.

The inspector pointed out that the measurement of a small leak or evaporation rate for the SFP was a very difficult task, and warranted special attention.

C.

Conclusions Based on the above reviews and discussion, the inspector concluded that: 1)

although SFP makeup water, inventory was the most important parameter to investigate for either SFP leakage and/or the evaporation rates, an accurate inventory was not available; 2) airborne tritium released from the SFP suggested that the evaporation and/or leakage rates could not be determined; and 3) a careful measurement should be obtained to determine the evaporation rate from the SFP due to various uncertainties concerning SFP water losses.

R2.4 Old Steam Generator SG Stora e Facilit

Ins ection Sco e (71750)

The inspector performed an inspection of the old SGs and internal spaces of their storage facility during a routine maintenance and radiation survey.

b.

Observations and Findin s The old steam generators were removed from the Ginna plant during the 1996 refueling outage and were placed into a specially engineered bunker on the west side of the site that was designed for long term safe storage (see IR 50-244/97-02).

The facility was designed with one entrance way containing two doors.

Both were locked to prevent inadvertent or unauthorized access.

The entrance was posted as a high r'adiation area (~100 mR/hr). The inspector accompanied maintenance and radiological protection personnel during routine maintenance and radiation surveys inside the facility on May 27, 1997.'The maintenance was only to remove excess'arp material under one of the old SGs and to trim up remnants.

The inspector noted that all inside spaces and surfaces were generally clean and dry, except for a few small wet spots on the floor where condensation had collected.

The exterior wrappings on the old steam generators were intact and dry, and exhibited no signs of deterioration.

All wall and ceiling surfaces and joints were dry and did not exhibit any signs of previous leakage.

No radioactive material other.

--:.-"-.--than.the SGs.were stored inside the facility. The, floor..sump. contained approximately 1 inch of wate I-C.

.19 The highest general area radiation level measured was 85 lmR/hr. Approximately 95 mR/hr was'detected at 30 cm from the B-SG near its tube sheet and rear cradle.

Approximately 115 mR/hr was detected in an. accessible area under the B-SG and warranted maintaining a High Radiation Area posting for the storage facility.

General area levels beyond the forward cradle were s10 mR/hr.

Contamination surveys indicated all areas inside the facility were less than 5QO dpm/100cm2.

Conclusions From the inside, the facility appeared to be intact and well secured.

No degradation of the steam generator wrappings was evident.

All interior spaces were clean and dry, and the facility was not being used to store any unauthorized materials.

No loose contamination was detected on external surfaces, and the facility did not appear to represent a radiological hazard to plant. personnel or to any areas surrounding the site.

R3 RP&C Procedures and Documentation R3.1 Chemistr and Radiolo ical Effluent Procedures Ins ection Sco e 84570-01 The inspector reviewed 1) selected chemistry procedures to conduct the effluent control programs; 2) the 1995 and 1996 Annual Radioactive Effluent Release Reports; and 3) the Offsite Dose Calculation Manual (ODCM).

b.

Observations and Findin s The inspector noted that the reviewed effluent control procedures were detailed, easy to follow, and that ODCM requirements were. incorporated into the appropriate procedures.

The licensee had good procedures to satisfy the ITS/ODCM requirements for routine and emergency operations.

The ins'pector reviewed the 1995 and 1996 annual radioactive effluent release reports.

These reports provided data indicating total released radioactivity for liquid and gaseous effluents.

The annual reports also summarized the assessment of the projected maximum individual and population doses resulting from 'routine radioactive airborne and liquid effluents.

Projected doses to the public were well below the Technical Specification limits. The inspector determined that there were no anomalous measurements, omissions or adverse trends in the reports.

The inspector reviewed the licensee's ODCM (Rev.9), effective October 1996.

The inspector noted that the current ODCM was a notable improvement over previous

• ~ "~'" ~- -- i'-'-~versions... The.ODCM.provided better, descriptions of.the. sampling.and analysis programs, which were established for quantifying radioactive liquid and gaseous

'effluent concentrations, and for calculating projected doses to the public. All necessary parameters, such as effluent radiation monitor setpoint calculation methodologies, site-specific dilution factors, and dose factors, were listed in

~ 20 the ODCM. The licensee adopted other necessary parameters from Regulatory Guide 1.109, "Calculation of Annual Doses to Man from Routine'Releases of Reactor.Effluents for the Purpose of Evaluating Compliance with 10 CFR Part 50, Appendix I ~

C.

Conclusion Based on the above reviews, the inspector determined that 1) effluent control procedures were sufficiently detailed to facilitate performance of all necessary steps for both routine and emergency operations; 2) the licensee effectively implemented the ITS/ODCM requirements for reporting effluent releases and projected doses to the public; and 3) the licensee's ODCM had improved and contained sufficient specification, information, and instruction to acceptably implement and maintain the radioactive liquid and gaseous effluent control programs.

R3.2 Closed NCV 50-244 97-05-01: 10 CFR 19.11 Postin of Notices to Workers ao Ins ection Sco e (71707)

The inspector evaluated the licensee's actions following discovery that the provisions of 10 CFR 19.11 for posting notices to workers were not implemented in the plant.

b.

Observations and Findin s During a routine tour of the Ginna Station in May 1997, the inspectors noted that the licensee did not post Notice of Violation (NOV) 50-244/97-01-01, or the licensee's response, dated April 29, 1997, as required by 10 CFR 19.11 (4), (c)(1),

(d), and (e) for review by plant workers.

In addition, NRC Form 3, "Notice to Employees," was displayed throughout the plant; however, the current version (January 1996) was not posted, as also required by the rule.

10 CFR 19.11 requires that NOVs for radiological working conditions and responses from the licensee be posted in sufficient number within two working days after issuance of those d'ocuments, in locations where individuals going into the affected areas will be able to read the NOV and the licensee'.s plans for corrective actions.

No administrative procedure existed at Ginna to assure that the requirements of 10 CFR 19 were properly implemented.

The necessary postings were accomplished in the past through a memorandum from the Ginna Production Superintendent to all Ginna Station workers on August 1, 1988, to make appropriate postings in accordance with 10 CFR 19.

The issues associated with the NOV concerned inadequate maintenance work practices and contamination boundary controls, which were wide spread throughout

~-~ ~'>>.

"~ '='the station.'Plant*workers responsible for the problems-became aware of the issues when upgrade training was initiated to correct the problems.

Plant workers received an additional awareness when new administrative controls were established, and when the plant manager distributed a memorandum to all plant staff to emphasized

~ 21 the need to correct the problems.

The inspector considerdd that the latest version of NRC Form 3 provided no substantial changes from the previous version.

e The licensee initiated an ACTION Report to correct the posting problem and promptly displayed copies of the NOV and RGRE's response letter throughout the plant in prominent places.

In addition, the latest version of NRC Form 3 was obtained and also displayed throughout'the plant.

The licensee also initiated actions to develop an Interface Procedure (IP) that would include a requirement to properly implement 10 CFR 19 in the future.

C.

Conclusions The inspector considered that the licensee's corrective actions were prompt and adequate, and that the overall consequences of this problem were minor. This failure constitutes a violation of minor significance and is being treated as a Non-Cited Violation consistent with Section IV of the NRC Enforcement Policy.

R6 ROC Organization and Administration R6.1 RPSC Or anization and Administration of Effluent Controls Ins ection Sco e (84570-01)

The inspector reviewed the organization and administration of the radioactive liquid and gaseous effluent control programs and discussed with the licensee changes made since the last inspection in this area, conducted in January 1996.

b.

Observations and Findin s There were no major changes since the last inspection of the programs.

The chemistry department had the major responsibility to conduct the effluent control programs.

Other groups (i.e., radiation protection, operations, IRC, and system engineers)

had supporting responsibilities to the program.

Staffing levels appeared to be appropriate for the conduct of routine and emergency operations.

The licensee reorganized the system'engineering group on September 10, 1996.

The inspector discussed responsibilities and job-related areas with the newly assigned HVAC and RMS system engineers.

The HVAC and RMS system engineers had some experience and knowledge of their assigned systems; however, it appeared that reorganization had left some lapses in the transfer of system information and responsibilities.

For example, a responsible individual had been assigned to track the SFP inventory, but it appeared that he did not transfer his knowledge or all system data to the currently responsible individual before he left

.-the company:.(see. Section R1.2).. The, inspector discussed.-with. plant management their expectations of system engineers'oles and training.

The inspector noted that upper management's decision to support the RMS and HVAC system engineers'raining (either in-house or outside) was goo ~ 22 c.

Conclusions Based on the above'discussions with system engineers and plant management, the inspector determined that the HVAC and RMS system engineers'xpertise should improve after additional training and,daily plant system experience.

The system engineers displayed good ownership of their systems.

The inspector considered that staffing levels appeared to be appropriate for engineering support of routine system operations.

R7 Quality Assurance in Radiological Protection and Chemistry Activities R7.1 RP&C Audits of Effluents Pro ram Activities a.

Ins ection Sco e 84750-01 The inspection consisted of a review of 1) the 1996 RP&C audit of effluent program activities; 2) the QA policies for the measurement laboratory; and 3) the implementation of the measurement laboratory quality control program for radioactive liquid and gaseous effluent samples.

b.

Observations and Findin s The inspector reviewed QA audit report No. 1996-0005-NAB.

The audit team identified two findings.

These findings were not safety-related, but were recommended as enhancements to the effluent control programs.

The licensee's response to these findings was completed in a timely manner.

The inspector noted that the scope and technical depth of the audit was sufficient to assess the quality of the radioactive liquid and gaseous=effluent control programs.

The licensee maintained a good QA policy and implemented the policy throughout the chemistry department, including the analytical measurement laboratory.

The inspector reviewed the QC data for inter-laboratory comparisons.

When discrepancies were found, effective resolutions were determined and implemented.

The inspector discussed with the licensee. the importance of intra-laboratory comparisons (blind, split, and spike samples)

and the importance of including the program as part of the current laboratory QC program to validate all measurement results.

The licensee willreview the intra-laboratory comparison and implement it, as necessary.

c.

Conclusions Based on the above reviews, the inspector determined that the licensee's QA audit was sufficient to effectively assess the radioactive liquid and gaseous effluent

-- ~control:program.. The licensee implemented. an. acceptable.QC program to validate measurement results for effluent sample Fire Protection Staff Knowledge and Performance F4.1 Fire Bri ade Drills a0 b.

Ins ection Sco e (64704)

The inspector observed a fire brigade drill, and reviewed the licensee's critiques of this and two other drills.

V Observations and Findin s On June 3, 1997, the licensee conducted a previously unannounced fire drill for a simulated fire in the main feed pump (MFP) room.

Five brigade members responded including two plant operators and three security guards.

All brigade members dressed out in full protective gear with a self-contained breathing apparatus (SCBA).

Extra air tanks were obtained for the SCBAs, and brigade members fully unwound two hose reels, as standard response practices for a plant fire.

A licensed training instructor evaluated the drill and,noted that positive communications, personnel safety concerns, and a timely response were achieved.

He also expressed some negative concerns noting that brigade personnel, should have initially closed the MFP room door while preparing the fire fighting equipment and evaluating the fire conditions, before entering the room.

Also, radio communications were difficultfrom poor transmission.

The inspector noted that one of the unreeled 1-1/2" hoses was laid out on the turbine floor in a narrow confined area in such a manner that the hose looped back around on itself. The inspector questioned the drill evaluator about the potential for not being able to drag the hose through this space if the hose was actually charged with water under system pressure.

It also appeared that the hose could potentially kink if pulled through a narrow space and shut off water flow through the hose.

The brigade members normally do not charge the fire hoses during drills, and these

. potential problems had not been previously considered during training since the hoses are not normally pressurized.

However, the evaluator stated that an attempt would be made to determine how flexible the 1-1/2 hoses are during the next fire training at the facility in Oswego, NY, where simulated structures with narrow passages existed.

On July 1, 1997, the drill evaluator pressurized the same hose in the turbine building as a test, and found that it would start to kink when the hose was looped down to about 40 inches across.

The evaluator indicated that plant operators would be advised as a precaution to avoid bending hoses in a loop smaller than 40 inches across to avoid kinking.

The inspector also reviewed an evaluation sheet of June 12, 1997, for another

'"':- '~ ~'=simulated.fire, in.the.MFP room.

One.of:the weaknesses-.identified by the evaluator was that the brigade captain did not dress out in the appropriate protective clothing for the given circumstances.

This weakness was a repeat occurrence from a drill conducted on February 22, 1997, when the fire brigade failed the drill, partly due to the brigade captain not wearing the appropriate protective clothing for the simulated

~ 24 conditions.

The licensee initiated an ACTION Report to address the drill failure and resolved the issues by conducting additional training to reiterate'the expectations for protective clothing.

However, the weakness occurred again during the drill on June 12, 1997.

The inspector discussed the repeated occurrence with the licensed training supervisor who indicated that an evaluation would be performed to determine the appropriate actions needed to assure that plant. management and training department expectations are fulfilled during future drills.

C.

Conclusions The inspector concluded that the full fire brigade responded promptly to the observed drill, and the drill evaluator performed an effective critique.

The licensee's follow-up to inspector concerns for pulling fire hoses through narrow passages was effective and provided useful information for fire brigade members.

V. IVlana ement'IVleetin s

X1 Exit Meeting Summary, The inspectors presented the inspection results from the Radioactive Waste and Effluent Controls Program to members of licensee management at the conclusion of the inspection on June 6, 1997. At the end of the inspection period, the inspectors presented the overall results to members of licensee management on July 8, 1997.

The licensee acknowledged the findings presented.

The inspectors asked the licensee whether any. materials examined during the inspection should be considered proprietary.

No proprietary information was identified.

L2 Review of'UFSAR Commitments A recent discovery of a licensee operating their facility in a manner contrary to the Updated Final Safety Analysis Report (UFSAR) description highlighted the need for a special focused review that corripares plant practices, procedures and/or parameters to the UFSAR description.

While performing the inspections discussed in this report, the inspector reviewed the applicable portions of the UFSAR that related to the areas inspected.

The inspector verified that the UFSAR wording was consistent with the observed plant practices, procedure and/or parameters, with the exception of the unresolved item URI 50-244/96-01-05 (Section R2.2).

Attachment

PARTIAL LIST OF PERSONS CONTACTED Licensee K. Gona D. Crowley D. Fillion B. Flynn C. Forkell G. Graus A. Harhay J. Hotchkiss R. Jaquin G. Jones G. Joss N. Leoni R. Marchionda F. Mis R. Ploof J. Smith J. Widay T. White G. Wrobel RMS System Engineer HVAC System Engineer Radiochemist Primary.Systems Engineering Manager Electrical Systems Engineering Manager INC/Electrical Maintenance Manager Chemistry & Radiological Protection Manager Mechanical Maintenance Manager Nuclear Safety and Licensing Chemist

'Results and Test Superviso+

Radiation Protection and Chemistry Production Superintendent Principle Health Physicist Secondary Systems Engineering Manager

'Maintenance Superintendent Plant Manager Operations Manager Nuclear Safety 5 Licensing Manager INSPECTION PROCEDURES USED IP 37551:

IP 61726:

IP 62707:

IP 64704:

IP 71707:

IP 71750:

IP 92902:

Onsite Engineering Surveillance Observation Maintenance Observation Fire Protection Program Plant..Operations Plant Support Follow-up - Maintenance ITEMS OPENED, CLOSED, AND DISCUSSED Closed NCV 97-05-01; 10 CFR 19.11, Posting of Notices to Workers Discussed

'-

'

'"'URI -"'96-01-05;

-Follow-up,on Air Cleaning Systems

-

-

~

IFI 95-15-01; Follow-up on Spent Fuel Pool and RHR Pump Room Leakage

Attachment

2 L'IST OF ACRONYMS USED AFW ASME CFR CREATS CST d/p dpm ECCS EDG EOP ESF HEPA HVAC l&.C IFI IN IR IST ITS LCO LOCA LLD mR/hr NCV NOV NPSH NRC ODCM PORC ppm PSA pslg PT QA QC RCA RCP RGRE RHR RMS RP RP5C RVLIS RWP SCBA SFP SG SI SR

'uxiliary Feedwater American Society of Mechanical Engineers Code of Federal Regulations Control Room Emergency AirTreatment System Condensate Storage Tank differential pressure disintegrations per minute Emergency Core Cooling System Emergency Diesel Generator Emergency Operating Procedure Engineered Safety Feature High Efficiency Particulate Analysis (filter)

Heating, Ventilation, and Air Conditioning Instrumentation and Controls Inspector Follow-up Item Information Notice

Inspection Report

Inservice Test

Improved Technical Specification

Limiting Condition for Operation

Loss-of-Coolant Accident

Lower Limitof Detection

milli-Rem per hour

Noncited Violation

Notice of Violation

Net Positive Suction Head

Nuclear Regulatory Commission

Offsite Dose Calculation Manual

Plant Operations Review Committee

parts per million

Probabilistic Safety Assessment

pounds per square inch gage

Periodic Test

Quality Assurance

Quality Control

Radiologically Controlled Area

Reactor Coolant Pump

Rochester Gas and Electric Corporation

Residual Heat Removal

Radiation Monitoring System

Radiation Protection

Radiological Protection and Chemistry

Reactor Vessel Level Instrumentation System

Radiation Work Permit

Self-Contained

Breathing Apparatus

Spent Fuel Pool

Steam Generator

Safety Injection

Surveillance Requirement

Attachment

SW

TDAFW

Service Water

turbine-Driven Auxiliary Feedwater

.

TRM

UFSAR

URI

pCI/cc

Technical Requirements

Manual

Updated Final Safety Analysis Report

Unresolved Item

'icro-Curies

per cubic centimeter