IR 05000220/1993006
| ML20044H209 | |
| Person / Time | |
|---|---|
| Site: | Nine Mile Point  |
| Issue date: | 05/24/1993 |
| From: | Briggs L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20044H205 | List: |
| References | |
| 50-220-93-06, 50-220-93-6, 50-410-93-06, 50-410-93-6, NUDOCS 9306080070 | |
| Download: ML20044H209 (17) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report Nos.:
93-06; 93-06 Docket Nos.:
50-220; 50-410 License Nos.:
Niagara Mohawk Power Corporation f
301 Plainfield Road
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Syracuse, New York 13212 Facility:
Nine Mile Point, Units 1 and 2 t
Location:
Scriba, New York Dates:
April 11 through May 8,1993 Inspectors:
W. L. Schmidt, Senior Resident Inspector
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R. A. Plasse, Resident Inspector
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W. F. Mattingly, Resident Inspector l
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Approved by:
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wesw i #f 95
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L'arry E' Briggs, Chifff Date Reactor Projects Section No. l A Division of Reactor Projects i
s Inspection Summary: This inspection report documents routine and reactive inspections of plant operations, radiological controls, maintenance, surveillance, emergency planning, security, and safety assessment / quality verification activities.
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Results: See Executive Summary.
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$DR ADOCK 05000220
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.y EXECUTIVE SUMMARY f
Nine Mile Point Units 1 and 2
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NRC Region I Inspectioc Report Nos. 50-220/93-06 & 50-410/93-06
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04/11/93 - 05/08/93 Plant Operations Very good outage planning and control resulted in a Unit 1 outage that met or exceeded the pre-outage goals for duration, radiation exposure, and contamination occurrence events. The Unit -
1 operations staff performed well during the subsequent plant startup and power ascension
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testing. Control room operators also conducted routine activities well at both units with two nomble exceptions: at Unit 1 an equipment markup failed to provide adequate isolation for a.
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preventive maintenance activity and at Unit 2 two out-of-position primary containment isolation valves were found out of position. Each of these issues was oflow safety significance, however, they demonstrated weaknesses in attention to detail and configuration control. An unresolved'
item was identified concerning the ability to monitor thermal stratification in the reactor vessel bottom head at Unit 1.
Radiolonical and Chemistry Controls
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Observation of selected portions of NMPC's radiological controls program indicated that it
effectively implemented.
Maintenance Observation of safety-related maintenance activities indicated an acceptable level of performance.
Surveillance
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Observation of safety-related surveillance activities indicated an acceptable level of performance.
At Unit 1 a surveillance test was conducted to verify that the emergency diesel generators could
supply power following a simultaneous loss of coolant and loss of off-site power signal. During performance of a fire department surveillance in the reactor building, a technician was found reading a magazine. NMPC took appropriate actions to address this weakness concerning adherence to their reading material guidelines.
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Executive Summary (Continued)
Encineerine and Technical Sunood
Unit 2 engineering provided a well written justification of operability following identification of an untested containment penetration in the traversing incore probe system. Unit 1 engineering performed a good analysis of degraded safety related pump / motor combinations and their affect on the loading of the emergency diesel generators.
Safetv Assessment nnd Ouality Verification
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The inspectors attended several site operations review committee (SORC) meetings and found the discussions in-depth and focused on safety. Vendor issued 10 CFR Part 21 reports will now be tracked in the routine resident inspection reports and closed following NRC review of NMPC's dispositions.
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T_ ABLE OF SUMMARY OF FACILITY ACTIVITIES I
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1.1 Niagara Mohawk Power Corporation Activities.................
I 1.2 NRC Activities..................................... I 2.0 PLANT OPERATIONS (71707, 93702).......................... 1
2.1 Routine Control Room and Plant Observations
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2.3 Inadequate Emergency Diesel Generator Isolation for Preventive Maintenance
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2.4 Inadequate Residual Heat Removal System Configuration Control......
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2.5 Reactor Scram During Plant Startup........................ 3 2.6 S trike Planning..................................... 4 2.7 Reactor Vessel Bottom Head Pressure / Temperature Limits.......... 4
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3.0 RADIOLOGICAL AND CHEMISTRY CONTROLS (71707)............. 5 l
4.0 MAfNTENANCE (62703)
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4.1 Maintenance Observations
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i 4.2 Indicated Gross Failure of a Rosemount Transmitter.............. 6 5.0 SURVEILLANCE (61726, 61707)
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5.1 Missed Type B Local Leakrate Test........................ 7
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5.2 Unanticipated High Pressure Core Spray Actuation............... 8 5.3 Suppression Pool Vent / Purge Valve Leakrate Testing
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5.4 (Closed) Unresolved Item 50-220/92-24-03: Emergency Diesel Generator
S urveillance Test.................................... 9 i
6.0 ENGINEERING AND TECHNICAL SUPPORT (71707,92703,37700).....
6.1 Reactor Vessel Operating Pressure Test.....................
6.2 (Closed) Unresolved Item 91-80-14; Emergency Diesel Generator Load Calculati on s......................................
6.3 (Open) Unresolved Item 50-410/93-01-02: Service Water Pump Testing / Operability
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7.0 SAFETY ASSESSMENT AND QUALITY VERIFICATION (71707,92700)..
7.1 Vendor Issued 10 CFR Part 21 Reports.....................
I1 7.2 Site Operations Review Committee Meetings
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8.0 M AN AG EM ENT M EETING S _..............................
- The NRC inspection manual procedure or temporary instruction used as inspection guidance are listed for each applicable report section.
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DETAILS
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1.0 SUMMARY OF FACILITY. ACTIVITIES 1.1 Niagara Mohawk Power Comoration Activities
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The Niagara Mohawk Power Corporation (NMPC) conducted nuclear activities safely at Nine Mile Point Unit 1 (Unit 1) and Unit 2 (Unit 2). At the beginning of the inspection period, Unit 1 personnel completed stub tube leakage repairs and various refueling outage items. NMPC i
commenced a unit startup on April 12, however, a reactor scram occurred with power in the intermediate range due to a spurious upscale trip on two intermediate range neutron monitors (IRMs). On April 14, following a modification to the IRM circuitry, NMPC restarted the unit and operated at full power through the end of the inspection period. NMPC safely operated Unit 2 at essentially full power throughout the period.
i 1.2 NRC Activities
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Resident inspectors conducted inspection activities during normal, backshift and weekend hours over this period. There were six hours of backshift (evening shift) and seven hours of deep
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backshift (weekend, holiday, and midnight shift) inspection during this period.
2.0 PLANT OPERATIONS (71707,93702)
2.1 Routine Control Room and Plant Observations Control room operators conducted routine activities well. Shift briefings at both units provided the necessary information to the operating crews. NMPC continues to monitor the number of lit annunciators and out-of-service control room equipment. General housekeeping in the plants was good. The Unit 2 operating crew took appropriate corrective action to remove from service
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a unit cooler that was cycling excessively. During a plant tour the inspector observed a Unit 1 instrumentation and controls (I&C) technician reading a magazine in the reactor building while involved in a fire department surveillance test. NMPC management took appropriate actions to address this weakness in adherence to their reading material guidelines.
2.2 Unit 1 Outage Activities Inspector observations of command / control of outage activities and daily planning meetings appeared to be indicative of very good outage preplanning. The effon appeared to be reflected in the results of the outage which met or exceeded the pre-outage goals for outage duration, radiation exposure, and contamination occurrence events.
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2.3 Inadequate Emercency Diesel Generator Isolation for Preventive Maintenance The inspector noted during a Unit 1 plant tour that the 103 emergency diesel generator (EDG)
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room contained standing water due to overflow of the EDG floor drain holding tanks located below the EDG room. The inspector noted that operators had marked-up the EDG on the previous shift to allow quarterly preventive maintenance (PM) on the EDG jacket cooler heat exchanger (lake water side). The inspector reviewed the piping configuration and temporary
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drain hoses and questioned an operator to determine the cause of the excessive drainage to support the PM activity. The inspector determined that the initial markup failed to fully isolate the EDG jacket cooler. This error resulted in the vent and drain paths, utilized to drain the maintenance area, remaining pressurized by the service water discharge header. The operator left the area unattended during the draining evolution, resulting in a continuous drain to the floor drain holding tank. An operator subsequently isolated the discharge header after approximately 4000 gallons discharged to the holding tank. The SSS corrected the markup and the maintenance department satisfactorily completed the PM activity. Safety significance was low in that no damage to equipment or significant delay to the completion of the EDG LCO resulted from the
inadequate control of this work activity.
The inspector identified several work control performance weaknesses. The operator draining the piping failed to identify the inadequate isolation of the piping prior to leaving the
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maintenance area. Also, the operators who authorized the markup failed to determine that the maintenance area would be adequately isolated.
The operators relied on a previously developed markup from the computer data base. The inspector concluded that the inadequate markup in the computer data base and the failure of the operators to identify the error prior to releasing the markup to the maintenance department for review were examples of inadequate work control. The inspector discussed these observations
with the operations manager who informed the inspector that a root cause evaluation of the event was in progress. This issue remained unresolved pending final disposition by NMPC and review by the NRC. (URI 220/93-06-01)
i 2.4 Inadeauate Residual Heat Removal System Conficuration Control i
During a routine Unit 2 control room panel walkdown on April 30, the inspector observed two
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redundant normally closed residual heat removal (RHR) "B" heat exchanger vent valves, 2RHS*MOV26B and 2RHS*MOV27B, open. The inspector questioned the licensed control room staff regarding the status of these valves and determined that they were unaware that the valves were open. The operators promptly shut the valves once they determined that there was no reason for them to be open and initiated a deviation / event report (DER). The operators subsequently determined that a reactor operator (RO) on the previous shift opened the valves per OP-31 to reduce pressure in the heat exchanger. The RO that vented the heat exchanger failed
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to notify the remaining operations staff of his actions or turnover the information to his relief.
The valves were open for about 1% hours.
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These remote manually operated valves allow operators to vent non-condensible gas built up in the heat exchanger during steam condensing mode of operation to the suppression pool. The valves also allow operators to periodically lower pressure in the heat exchanger caused by leaking RHR steam condensing isolation valves.
The open RHR heat exchanger vent valves did not adversely affect primary containment integrity because the penetration associated with the valves is not required by the FSAR to be closed
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during accident conditions for the following reason. The downstream piping discharges to the
suppression pool, below the suppression pool water level, and therefore is not exposed to the primary containment atmosphere. iso, the containment penetration line does not constitute a bypass leakage path because the RHR system is considered a leakage boundary (a closed piping
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system outside the primary containment).
Unit 2 engineering department personnel evaluated the open RHR heat exchanger vent valves
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with respect to operability of the low pressure coolant injection (LPCI) mode of the RHR system. After conservatively estimating the bypass flow through the valves, they concluded that the as-foad LPCI system flow satisfied the emergency core cooling system (ECCS) flow requirements. The inspector reviewed the calculations and found them acceptable.
The inspector also reviewed the FSAR, technical specifications (TSs), system prints, procedures,
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and operating logs, and interviewed several individuals involved in-the event, including operations department management. The inspector considered the immediate corrective actions appropriate. The preliminary findings and proposed corrective actions from the root cause evaluation were satisfactory. However, this instance indicated weak operator configuration
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control and turnover of significant plant information.
2.5 Reactor Scram During Plant Startup While performing a Unit I reactor startup on April 13, a reactor scram occurred due to an upscale trip on two of the eight IRMs (channels 13 and 16). The high level on the IRMs occurred simultaneously on both channels of the reactor protection system (RPS). All control rods fully inserted. This scram occurred at a reactor pressure near atmospheric, temperature i
at 140 F, the reactor at the point of adding heat, and all IRMs on range 6 or 7. No other engineered safety feature actuations occurred.
During the startup, operators bypassed IRM 17 for testing purposes. Following the test, while the operator was un-bypassing IRM 17, a full reactor scram occurred. Operators noted that the -
red seal-in lights on IRM 13 and 16 were illuminated signaling that these two IRMs caused the scram. No control rod motion had occurred for about ten minutes prior to the scram.
Troubleshooting activities determined that the IRM channel bypass switch caused the spurious high level trip. The movement of the bypass switch out of the bypass position resulted in j
deenergizing a relay coil which generated electrical noise. The noise generated could cross j
between RPS channels via common control room ground wiring resulting in a spurious IRM high
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level trip. To prevent reoccurrence NMPC completed modifications to suppress the noise prior to restart. The inspectors reviewed the modifications and the associated 10 CFR 50.59 safety evaluation. The inspectors determined the troubleshooting activities were effective and NMPC took appropriate actions to address the identified deficiency.
2.6 Strike Planning The contract between NMPC and the International Brotherhood of Electrical Workers expires on May 31. NMPC has taken steps to address the yssibility of a strike by union employees.
This plan includes reactivation of stafflicensa - ensure continued safe operation of both units.
NMPC was still in the process of finalizing then plans, which will get approval by thejoint site operations review committee (SORC).
2.7 Reactor Vessel Bottom Head Pressure / Temperature Limits
Two recent industry events at boiling water reactors (BWRs) involved thermal stratification in the bottom of the reactor vessel following a reactor scram and loss of recirculating flow. In both cases the control room operators did not recognize that thermal stratification sufficient to cause vessel pressure / temperature limit violations could occur under these conditions. Contributing factors to the thermal stratification and subsequent pressure / temperature limit violations included the lack of forced circulation coupled with the injection of relatively cool water into the vessel from the control rod drive (CRD) system.
Other contributing factors were inadequate procedures to monitor heatup and cooldown rates during abnormal plant conditions coupled with insufficient operator awareness of the application of the pressure / temperature limits and of the necessary steps for prevention or mitigation of reactor coolant thermal stratification..
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Unit 1 Review The inspector reviewed the Unit 1 operating procedures for reactor scram, shutdown cooling, reactor startup and shutdown, and the recirculation system. Based on this review the inspector concluded that the Unit 1 operating staff had adequate guidance for mitigation and prevention of thermal stratification in the appropriate procedures. The operations department personnel interviewed exhibited a thorough understanding of the potential for thermal stratification and the need to maintain forced circulation (i.e., at least one recirculation pump running). However,
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the inspector noted the procedures did not contain guidance to prevent thermal stratification during recovery of a recirculation pump following a loss of recirculation flow event.
The inspector reviewed General Electric service information letter (SIL) 251, dated October 3, 1977, which addressed thermal stratification during recirculation pump starts following a loss of recirculation flow. The SIL stated that starting a recirculation pump could create a thermal
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over-stress condition by sweeping hot water across the relatively cooler vessel bottom head area and control rod drive stub tubes. NMPC's response to the SIL stated that the reactor analyst determined that the SIL was not applicable to Unit 1. The response did not provide a technical basis for this determination and the inspector questioned the validity of this conclusion.
The inspector reviewed the Unit I configuration and determined that no current method existed for the operators to monitor temperature conditions in the bottom head area because the reactor water cleanup bottom head drain line contains no thermocouples.
Currently, operating procedures require the use of recirculation loop suction temperatures to monitor heat-up and cooldown rates. With the current design operators cannot monitor the temperature in the bottom head region to prevent exceeding pressure / temperature limits if a thermal stratification condition existed. The inspector noted most BWRs have TS requirements for recirculation pump start conditions (minimum temperature differential between the vessel and bottom head regions)
to prevent thermal over-stress conditions. The inspector discussed these concerns with the Unit i engindng staff. NMPC agreed to review SIL 251 and the recent thermal stratification events. This issue was unresolved pending final disposition by NMPC and review by the NRC.
(URI 220/93-06-02)
Unit 2 Review
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i The Unit 2 quality assurance (QA) department initiated a DER to address the two industry thermal stratification events. Operations department management reviewed the industry events, the associated industry correspondence, and the applicable Unit 2 operating procedures. Prior to the DER, Unit 2 staff made several procedure modifications and enhanced operator training to emphasize the thermal stratification concerns in the vessel bottom head region during cooldown.
Based on the above review, the Unit 2 staff identified several procedural enhancements (and attendant training) to fmther address the thermal stratification concerns.
Specifically, the operations department staff plans to revise several procedures to minimize the possibility of thermal stratification by: resetting the scram as soon as possible to minimize injection flow rates into the bottom of the vessel, increasing the bottom head drain flow via the reactor water cleanup system when the system is available, and monitoring bottom head drain temperature following a scram without forced circulation.
Unlike Unit 1, Unit 2 has a thermocouple on the bottom head drain line for temperature monitoring and associated TS minimum differential temperature requirements to prevent thermal over-stress conditions. The inspector reviewed NMPC's evaluation of the issue and considered the corrective actions
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appropriate and the time table for implementation satisfactory.
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3.0 RADIOLOGICAL AND CHEMISTRY CONTROLS (71707)
During frequent tours of the accessible areas at both units, the inspectors observed the implementation of selected portions of NMPC's radiological controls program to ensure: the utilization and compliance with radiological work permits (RWPs), detailed descriptions of radiological conditions including personnel adherance to RWP requirements. The inspectors observed adequate controls of access to various radiologically controlled areas and use of
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personnel monitors and frisking methods upon exit from these areas. Posting and control of radiation areas, contaminated areas and hot spots, and labelling and control of containers holding radioactive materials were verified to be in accordance with NMPC procedures. Radiation protection technician control and monitoring of these activiNs was satisfactory. Overall, the inspector observed an acceptable level of performance and implementation of the radiological
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controls program.
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4.0 MAINTENANCE (62703)
i 4.1 Maintenance Observations
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Through observations of safety-related maintenance activities, interviews, and review of records
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the inspectors verified the: proper use of administrative authorizations and tag outs, adequacy of procedures, use of certified parts and materials, calibration of measuring and test equipment
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(M&TE), proper implementation of radiological control requirements, use of controlled system
prints and wiring removal documentation, and proper establishment of quality control hold points. Maintenance activities observed by the inspectors are listed below:
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N2-MPM-SLS-A143, Standby liquid control (SLC) pump preventive maintenance i
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WR 197861, EDG I local annunciator panel troubleshooting N2-MPM-HVP-A558, EDG II ventilation fan preventive maintenance
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N2-MPM-GEN-V200, SLC pump isolation valve packing WO 93-01949, EDG 103 heat exchanger preventive maintenance
WO 93-02359, #12 RWCU pump mechanical seal leakage / pump overhaul WO 93-02160, Troubleshooting cause of reactor scram
WO 93-02147, Install spike suppres.sion varistors in reactor manual control system.
The above activities were effective with respect to meeting the safety objectives.
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4.2 Indicated Gross Failure of a Rosemount Transmitter l
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On April 21, with Unit 1 operating at 100% power, one of the four 10-10-10 reactor water level J
i instruments, which initiates the automatic depressurization system (ADS), indicated a high gross failure. The gross failure from a Rosemount analog transmitter trip system shows that the transmitter has failed causing the signal to either fail high or low depending on how the
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transmitter failed. The operating shift responded well to this failure, declaring ADS inoperable,
entering the applicable ADS TS limiting condition for operation (LCO) and initiating an
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emergency work order for I&C to investigate the situation. Through voltage readings taken on
the failed instrument and the three other instruments, I&C found that the instrument had not i
experienced a gross failure because its voltage output read consistent with that of the other instruments.
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The variable legs for the 10-10-10 water level instruments tie into the core spray injection line.
This causes the instruments to read upscale with recirculation pumps in operation, due to the flow through the core. I&C found that the setpoints for the gross failure voltage had drifted to
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below the actual voltage seen by the instrument due to the flow. Based on the voltage readings I&C conducted a calibration of the gross failure voltage to increase it above the actual voltage, this corrected the problem. Further, I&C conducted similar calibration of the three other gross failure alarms on the other instruments to preclude the problem in the futre, inspector revi:w of the completed work order following the initial gross failure showed that the technicians did not completely document the taking of voltages and their assessment of the condition in determination that the instrument was actually operable. Voltage readings had been taken and were recorded subsequently. The calibration procedure and the post-work testing completed were well documented and completed properly for all the instruments setpoint changes. Through review of the station shift supervisor (SSS) log and discussions with the SSS, the inspector determined that the SSS took a conservative action when declaring ADS inoperable. The SSS
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was not fully familiar with a new TS amendment that would have allowed the instrument to be inoperabic for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, before placing it in a tripped condition and would not have required that ADS be declared inoperable or the entry into the 10 hour1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> LCO.
5.0 SURVEILLANCE (61726, 61707)
Through observation of safety-related surveillance activities, interviews, and review of records,
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the inspectors verified: use of proper administrative approve, personnel adherence to procedure
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precautions and limitations, accurate and timely review of test data, conformance of surveillances to technical specifications, including required frequencies, and use of good radiological controls.
Surveillance activities observed included those listed and discussed below:
N2-ESP-BYS-W675, Division III 125 volts DC battery surveillance N2-OSP-SWS-Q001, Service water check valve operability test N2-ESP-BYS-R682, Division III battery charger load test N1-ST-R2, Loss of coolant accident and EDG simulated automatic initiation test N1-STP-34, Power ascension test of feedwater flow control valve j
N1-IST-LK-101, Reactor pressure vessel and ASME Class 1 system leakage test
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The above activities were effective with respect to meeting the safety objectives.
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5.1 Missed Tyne B local Leaktate Test During an audit of the 10 CFR 50 Appendix J leakrate testing program at Unit 2, NMPC QA identified that bellows on the traversing in-core probe drive line penetrations had not received a Type B leakrate test. Once identified NMPC management took aggressive actions to review
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the situation. NMPC engineering prepared a good engineering operability determination of this situation. The rational for why the penetrations were operable was that the penetration bellows were tested during the 1992 integrated leak rate test (ILRT) and that if all the ILRT leakage was assumed to have been through the bellows the total of this leakage and the total type B and C
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leakages would still be less that 05 La. The inspector found this an acceptable justification.
During this process NMPC determined that relief from the requirement of 10 CFR 50 Appendix-J would be necessary, and officially contacted the NRC project manager to discuss the needed relief request.
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5.2 Unanticinated High Pressure Core Soray Actuation While exiting a high pressure core spray (HPCS) battery charger load surveillance test on April
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20, false low reactor vessel water level signals caused an unanticipated HPCS actuation. The HPCS EDG automatically started and the HPCS injection valve opened; however, a HPCS
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injection did not occur because the HPCS pump was in pull-to-lock to support unrelated system preventive maintenance. A DC bus voltage transient, during the testing, caused the Topaz inverter supplying the HPCS reactor level transmitters to deenergize and then reenergize. The false low reactor vessel water level signals resulted when the transmitter trip units reenergized.
When exiting the battery charger load test, a malfunction of the test load bank control unit caused an inadvertent application of the test load to the DC bus. The system engineer present for the surveillance immediately responded to remove the test load and verify proper operability of the battery charger. This load, h,owever, lowered the Division III DC bus voltage to about 85 volts (from a normal 135 volts DC), which caused several control room alarms and the shutdown of the Topaz inverter. The Topaz inverter is designed to automatically shutdown at
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supply voltages s100 volts DC and automatically reset at s108 volts DC increasing with a fixed dead band of about 13 volts DC. Following removal of the test load the DC bus voltage promptly returned to normal, the inverter automatically reset, and the Rosemount trip units reenergized. The trip units' respective transmitters, which failed to zero on the loss of power, however, required several additional milliseconds to reenergize completely. Thus, the trip units
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sensed a zero input from their transmitters, satisfying the low level HPCS initiation logic. NRC Informaion Notice 90-22, " Unanticipated equipment actuations following restoration of power-
to Rosemumt transmitter trip units," described similar events.
The Unit 2 operators responded properly to the HPCS actuation, returned the HPCS system to
its prior configuration after determining the cause of the actuation, notified the NRC per 10 CFR 50.72(b)(2)(ii), and initiated a DER to investigate the event.
System engineering review of the event determined that the DC bus conservatively experienced a 328 amp load for about 9 seconds. NMPC inspected the Division III battery and determined that no damage occurred because of this event and considered the battery capable of performing its design function. The battery sustained an approximately 0.6875 amp-hour discharge, less than 1 % of the design discharge rate'. NMPC confirmed their inspect:on results with the battery vendor. At the end of the inspection period, NMPC's investigation of the malfunctioning load bank continued.
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The inspector reviewed NMPC's response to Information Notice 90-22 and determined that Unit
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2 planned to remove the automatic reset feature of the Topaz inverter during the next refueling
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outage scheduled for October 1993. Subsequent discussions with the system engineers revealed
that ' Unit 2 now plans to replace the Topaz inverter during the October 1993 refueling outage.
The replacement power supply specifications differ from the Topaz inverter in two significant ways. During degraded supply voltage conditions the output of the power supply will degrade proportionally instead of automatically shutting down. Also, there is no automatic reset feature following a loss of supply power. These changes will accommodate procedure changes to l
prevent inadvertent actuations following restoration of power. NMPC believes this design is an improvement over the Topaz design.
The inspector also independently reviewed the data associated with the event, the HPCS-initiation logic drawings, the Topaz inverter technical manual, and interviewed several persons involved with the event. Based on the above, the inspector concluded that all systems responded
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as designed, NMPC satisfactorily responded to Information Notice 90-22, and that operations
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and system engineering staff properly responded to and investigated the event.
5.3 Suppression Pool Vent / Purge Valve Leakrate Testing As documented in Combined Inspection Reports 92-16/92-18, NMPC committed to perform leakrate testing on the Unit 2 suppression pool vent / purge valves following use, because of
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frequent leakrate test failures. NMPC performed a root cause analysis on these failures and-determined that improperly set butterDy valve position limit blocks let the valves not close fully on their seats. Following resetting of these valves closing limit blocks NMPC performed several post venting operations and satisfactory leak tests. NMPC requested that a commitment made
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previously to test these valves after e' ch operation be revoked placing the valves on their normal a
TS leakage test surveillance frequency of 2 years. The inspectors found that NMPC took
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adequate corrective actions to identify the cause for the leak rate test failures and provided adequate justi6 cation for not having to test the valves after every operation.
5.4 (Closed) Unresolved Item 50-220/92-24-03: Emergency Diesel Generator Surveillance T_cs1
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The inspector reviewed the actions taken by NMPC to address a concern that N1-ST-R2, Loss
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of Coolant Accident (LOCA) and EDG Simulated Automatic Initiation Test, did not match the design basis for the EDGs. Specifically, the test did not appear to meet the intent of technical
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specifications or the system design basis in that the LOCA and loss of off-site power (LOOP)
signals were not simultaneous. NMPC updated the procedure to simulate a low-low reactor water level and high drywell pressure signal while simultaneously simulating an under-voltage
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signal in the appropriate power board for the specific EDG under test. The inspector monitored performance of the test on April 11. The inspector verified all safety systems properly
responded to the initiation signals that resulted in the automatic initiation of the EDGs and automatic sequential loading of the ECCS pumps. This item is closed.
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6.0 ENGINEERING AND TECHNICAL SUPPORT (71707,92703,37700)
i 6.1 Reactor Vessel Operating Pressure Test
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NMPC performed a reactor vessel pressure test as a post-maintenance test of various refueling l
outage work activities. Test pressure of 1035 psig was attained with a control rod drive pump as the pressure source. The principal test director and the operations staff adequately controlled the test. Inspection of the system welds at test pressure identified leakage from two control rod
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drive stub tubes which caused the leak test to be unsatisfactory. NMPC management requested a discussion with the NRC to provide a basis for relief from repair of the identified stub tube leakage. Based on this discussion the NRC concluded that NMPC had an existing ASME section
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XI code relief for stub tube leaks and that NMPC did not provide justification of additional
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hardship or difficulties not already~ addressed by the original safety evaluation (SER) dated March 25,1987, to justify further code relief. NMPC agreed to follow the agreements of the existing relief request by rolling the two leaking stub tubes to stop the water leakage. The inspector reviewed NMPC's repair plan for the stub tube leakage.
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The inspector noted that the planned retest following the stub tube repair was a visual inspection with the reactor vessel depressurized. The inspector reviewed the SER and the proposed retest and concluded that NMPC met the requirements of the SER. However, the stub tubes were not observed to be leaking, prior to rolling, at a higher static head than the proposed retest conditions (i.e., with the reactor vessel depressurized and flooded with the spent fuel pool gates removed). The inspector discussed, with the plant manager, whether the static pressure test would provide sufficient indication that the stub tube rolling had corrected the leakage.
Subsequently, NMPC performed a visual inspection and found no leakage from the stub tubes at 500 psig during the plant restart.
6.2 (Closed) Unresolved Item 91-80-14: Emergency Diesel Generator Load Calculations This item dealt with the suitability of NMPC's calculation of the EDG loads at Unit 1.
In Combined Inspection Reports 92-19/92-21, the NRC found that the methodology applied for the calculation was appropriate. Howev'er, the actual load placed on the EDGs by large motors was not known, and assumed to be the original design values. As stated in Combined Inspection Reports 92-29/92-34, NMPC performed testing of two large pumps in January 1993 and determined that in one case a containment spray raw water pump was operating below its design efficiency and thus would draw a higher load that the design value.
To address this issue NMPC conducted testing on all the 4.16 KV pumps / motors near the end of the most recent refueling outage. The results of the testing showed that these pumps needed higher current than design due to degradation in the efficiency of the pump-motor combination.
This degradation in efficiency caused the pump motors to draw more current than the design conditions. Based on the test results NMPC took action to include these increased KW loads
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in their EDG load calculation. With the increased loads the calculated maximum KW rating of each EDG would have been above the continuous rating. However, based on the modification during the outage that installed static inverters in place of motor-generator sets, the actual load was below the continuous rating of each machine.
NMPC engineering did a good job in resolving this concern. This item was closed. However, an issue that still needs to be addressed is how, during normal plant testing, the degradation of pump performance and its affect on KW loading can be accounted for. NMPC engineering is
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reviewing this issue.
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6.3 (Onen) Unresolved Item 50-410/93-01-02: Service Water Pumo Testing / Operability
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This item dealt with two service water (SW) pump issues. First, an impeller less than the required diameter was installed in SW pump 1A; this impeller did not develop adequate
discharge pressure at the tested pump flow and the inspector was concerned that it may not have been acceptable at the single pump accident design flow. Second, NMPC had not performed
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post maintenance pump curve validation prior to declaring the pump operable after installation of the mis-sized impeller or after installing a new correctly sized impeller.
The inspector observed the determination of SWP*1 A pump curve on April 23. The operators and test engineer performed well to get the data required. Review of the data indicated that the pump was producing approximately 17 psid less that the design pump curve supplied by the manufacturer. The pump was able to meet the TS required flow of 6500 gpm at 80 psid. The inspectors remained concerned about the required flows from service water pumps. NMPC's evaluation of this concern continues. This item remains open.
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7.0 SAFETY ASSESSMENT AND QUALITY VERIFICATION (71707,92700)
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7.1 Vendor Issued 10 CFR Part 21 Reoorts
The following is a list of 10 CFR Part 21 reports, received by the NRC since 1992, which are
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believed to be applicable to Nine Mile Point. As part of the normal ir.spection process the inspector will review these Part 21 report issues to ensure adequate review by NMPC for applicability to either Nine Mile Point unit. Each Part 21 report that is not unit specific is given two identification numbers to allow tracking of inspector review. Each item will remain open pending inspector review of NMPC's actions.
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Unit /Open Part 21 Vendor Description of Problem Item #
Letter Date Unit 1 8/31/92 GNB Industrial Station Batteries failed to comply with 93-001 Battery published 1 minute ratings.
Unit 2 Company 93-036 Unit 1 9/11/92 ABB Defects in Type 60 relays.93-002
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93-037 Unit 2 11/10/92 Cooper Defective fuel oil check valve.
93-003 Industries Unit 1 11/23/92 Limitorque Defective SB/SBD-1 housing cover screws.93-005 Corp.
Unit 2 93-038 Unit 1 12/7/92 Limitorque Potential defect in SMB/SB-00 AND
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93-041 Corp SMB/SB/SBD-00 declutch system assemblies.
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'93-042 Unit 1 3/31/92 Cajon of Defect in stainless steel pipe fittings.
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Unit 2 Ohio
93-039
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i Unit 1 4/7/93 ABB K-4000 circuit breakers failed to meet rating 93-033 criteria.
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Unit 2
93-034
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Unit 2 4/14/93 Cooper Defect in fuel oil pump.93-032 Industries
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Unit 1 4/27/93 Atwood and Failure of main steam isolation valve to close.93-035 Morrill Co.,
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13-7.2 Site Operations Review Committee Meetings The inspector attended a Unit 1 SORC meeting that was held to discuss continued testing on the turbine driven feedwater pump. The meeting was well controlled and presentations provided good information. SORC determined that it was appropriate to allow power increases and further testing on the flow control valve.
8.0 MANAGEMENT MEETINGS At periodic intervals and at the conclusion of the inspection, meetings were held with senior station management to discuss the scope and findings of this inspection. Based on the.NRC Regiori I review of this report and discussions held with Niagara Mohawk representatives, it was determined that this report does not contain safeguards or proprietary information. Niagara Mohawk did not object to any of the findings or observations presented at the exit interview.