IR 05000369/1994008
| ML20029E302 | |
| Person / Time | |
|---|---|
| Site: | McGuire, Mcguire  |
| Issue date: | 05/06/1994 |
| From: | Maxwell G, Sinkule M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20029E286 | List: |
| References | |
| 50-369-94-08, 50-369-94-8, 50-370-94-08, 50-370-94-8, NUDOCS 9405180117 | |
| Download: ML20029E302 (23) | |
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UNITED STATES NUCLEAR REGULATORY COMMISSION
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/* 1 REGION 11 3
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101 MARIETTA STREET, N.W., SUITE 2900
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ATLANTA, GEORGI A 30323 0199 S
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%,.....f Report Nos. 50-369/94-08 and 50-370/94-08 Licensee:
Duke Power Company 422 South Church Street
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Charlotte, NC 28242-1007
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Facility Name:
McGuire Nuclear Station 1 and 2 Docket Nos. 50-369 and 50-370 License Nos. NPF-9 and NPF-17 Inspection Conducted:
March 13, 1994 - April 9, 1994-m Inspector:
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2/duk/7f'
G> Maxwell
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Dale (31gned '
Seni-" Resident Inspector G. Harris Resident Inspector Accompanying Inspectors:
K. Kavanagh, Reactor Engineer Intern, McGuire R. Watkins, Project Engineer, RII
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Neume b -f m A 6.
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/d Approved by:
M. Sinkule, Chief Date Signed Reactor Projects Branch 3 SUMMARY Scope:
This routine, resident inspection was conducted in-the areas of plant operations, surveillance testing, maintenance observations, and followup on previous inspection findings. An evaluation of the use of overtime and an assessment of the standby shutdown facility were performed. Addii.ionally, information meetings with'
local officials and members of the public were conducted.
Backshift inspections were performed on March 14, 15, 16, 18, 20, 25, and April 1, 5, 6, 7, and 8,1994.
9405180117 940506 PDR ADOCK 05000369 G
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Results:
In the area of operations, the inspectors had several concerns about components that forced operator work-arounds and affected plant operations.
These component concerns included:
1) B NC Low Loop Flow Alert annunciator actuations, 2) INV-238, charging flow control valve, instability, 3) INV-124, -letdown relief valve operability, 4) 1KCDT, component cooling water drain tank pump, failures, 5) ICF-26, ICF-28, and ICF-30, main feedwater-containment isolation valves, manual failures, 6) setting main steam safety valves' lift setpoints on a nonconservative basis, and 7) leakage detection systems past inoperability.
These items are discussed in paragraph 2.d.
The licensee has developed a prioritization system to focus management attention on certain plant equipment conditions.
The Top Equipment Problem Resolution Process consists of two parts:
the Major Equipment Problem Resolution list and the Top Plant Work-Arounds Problem Resolution list.
The effectiveness of the process cannot be determined at this time; however, it appears to be a step in the positive direction.
This is discussed in paragraph 2.e.
An unresolved item was identified in the area of severe weather preparations.
The licensee did not implement its natural disaster procedure even though the National Weather Bureau issued a tornado warning for Mecklenburg County.
This is discussed in. paragraph 2.f.
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l In the area of maintenance, the plant staff had initiated improvements to the material condition of the' ice condenser refrigeration sub-system. This involved removing the old-insulation-from the glycol loop outside containment and replacing it with upgraded insulation that was more efficient and less likely to retain water vapor.
This is discussed in paragraph 4.b.
In the area of maintenance, the inspectors concluded that the modification to the diesel generator fuel oil level instrumentation should improve diesel reliability.
This is discussed in paragraph 4.c.
In the area of maintenance, the inspectors concluded that some work coordination problems continued to exist between operations and other station work groups.
This is discussed in paragraph 4.c.
In the area of surveillance, some concerns were expressed i
regarding the potential of ice accumulation affecting the
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operability of the ice condenser doors. This is discussed in
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paragraph 3.c.
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In the area of surveillance, a violation was identified because TS limits were exceeded as a result of non-conservatism in the unidentified leakage calculation.
This is discussed in paragraph 3.e.
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In the-area of surveillance, the inspectors concluded that human performance errors continue to contribute to safety system.
unavailability. This is discussed in paragraph 3.d.
In the area of plant support,.several discrepancies were.
identified by the licensee during their planned emergency drill.
This is discussed in paragraph 5.
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REPORT DETAILS l.
Persons Contacted
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Licensee Employees D. Baxter, Support Operations Manager A. Beaver, Operations Manager
- J. Boyle, Work Control Manager B. Caldwell, Training Manager
- S. Copp, General Office / Nuclear Regulatory Affairs
- R. Cross, Compliance Specialist T. Curtis, System Engineering Manager R. Deese, Safety Review Group
- E. Estep, INPO Coordinator E. Geddie, Station. Manager
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- G. Gilbert, Safety Assurance Manager
- J. Glenn, Systems Engineering B. Hasty, Emergency Planner F. Hayes, Human Resources
- P. Herran, Engineering Manager
- L. Holt, F/E Management
- D. Jamil, Electrical Engineer
- R. Jones, Superintendent of Operations
- E. Geddie, Station Manager
- T. McMeekin, Site Vice President
- M. Nazar,- Instrument & Electrical Maintenance Superintendent
- R. Quellette, Systems Engineering
- R. Sharpe, Regulatory Compliance Manager B. Travis, Component Engineering Manager
- H. Wallace, Mechanical Engineering Supervisor
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R. White, Mechanical Maintenance Superintendent i
Other licensee employees contacted included craftsmen, technicians, operators, mechanics, security force members, and office personnel.
NRC Resident Inspectors
- G. Maxwell, SRI
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- G.
Harris, RI
- K. Kavanagh, Intern
- R.
Watkins, RII
- Attended exit interview
2.
Plant Operations (71707)
a.
Observations
The inspection staff evaluated plant operations during the report period to verify conformance with applicable regulatory
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requirements.
Control room logs, shift turnover records and equipment removal and restoration records were routinely reviewed.
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l Interviews were conducted with plant operations, maintenance, chemistry, health physics, and performance personnel.
Activities within the control room were monitored during shifts
and at shift changes. Actions and/or activities were conducted as
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prescribed in applicable station administrative directives. The i
number of licensed personnel on each shift met or surpassed the
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minimum required by Technical Specifications (TS).
Plant tours taken during the reporting period included, but were not limited to, the turbine buildings, the auxiliary building,
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electrical equipment rooms, cable spreading rooms, and the station yard zone inside the protected area.
During the plant tours, ongoing activities, housekeeping, fire
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protection, security, equipment status and radiation control practices were observed.
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b.
Unit 1 Operations Unit I has operated essentially at 100% power during the period.
c.
Unit 2 Operations
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Unit 2 has operated essentially at 100% power during the period, d.
Operational Concerns 1)
During a review of the control room logs the inspectors noted that the B NC Low Loop Flow Alert annunciator on Unit I had inadvertently actuated.
The annunciator warned operators of low reactor coolant system flow conditions.
The licensee attached a recorder to the alarm flow circuitry to troubleshoot the problem.
Data obtained from the Loop B NC Flow Protection Channels revealed that the problem was with Channel I.
The licensee has concluded the low flow alarm was caused by random process noise spikes.
In addition, core flow was reduced because of steam generator tube plugging, and the flow transmitters were calibrated using differential pressures prior to the tube plugging.
The process noise spikes have caused indicated flow to dip below the alarm bistable setpoint. _The low flow instrumentation had not been renormalized to their new, reduced core flow value because the licensee believed that the change would make the alarm setpoint less conservative.
The licensee plans to renormalized the instrumentation during -the next refueling outage. This will correct the inadvertent actuation of the annunciator.
The inspectors will continue to follow this issue.
2)
A review of plant records and observations of plant operations revealed that-lNV-238 charging flow control valve i
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has caused unstable charging flow for NCP seal injection and pressurizer level. The valve modulated in response to signals from the pressurizer level control system to maintain level on program.
The licensee believed that the valve operated in a region of instability because of manipulations of the seal injection valves.
These valves had been manipulated in response to recent NC leakage calculations that revealed that controlled leakage was high and could possibly exceed administrative control values; they were manipulated also in response to pump runout concerns.
The licensee attempted to correct the problem by further manipulating the NCP seal injection valves. The licensee continues to evaluate this valve condition.
3)
The inspectors evaluated the operation of the letdown relief valve, INV-124.
It was weeping after operations personnel induced a pressure transient in the letdown piping while swapping letdown orifices.
Attempts to reseat the valve had failed.
The plant staff asserted that the valve will perform its function if required.
An annunciator, " Letdown Relief Temp Hi," had continuously actuated as a result of the increase in relief tailpipe temperatures.
The engineering staff decided to raise the annunciator setpoint so that the annunciator would clear and be able to detect increased leakage caused by further degradation of the valve.
The valve repairs are scheduled for the next refueling outage.
4)
The inspectors evaluated the circumstances associated with the component cooling water drain tank pump, 1KCDT, breaker tripping because of motor winding damage.
The pump was used to transfer drains collected into the component cooling water drain tank from valve stems and relief valves that contain the chemically treated water. The pump had failed several times in the past, resulting in the discharge of chemically treated water into the WM system.
The chemicals used in the system could damage resins used in the liquid radiation monitor system and waste disposal system.
A temporary pump was installed to drain the tank and direct water to the KC surge tank.
The licensee is continuing to evaluate the pump motor failures.
5)
The inspectors evaluated the Unit 1 power reduction that occurred on March 4, 1994.
Plant operators performed a rapid power reduction when the main feedwater (CF)
containment isolation valve to the A steam generator, ICF-35, was drifting closed. While transferring CF flow to the upper nozzles, the licensee discovered that the main feedwater containment isolation valves, 1CF-26, ICF-28, and ICF-30, for the D, C, and B steam generators, respectively, would not close from the main control board as required by the operating procedure, OP/1/A/6100/03 Step 3.12.2,
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" Controlling Procedure for Unit Operation." These valves were left open and the power reduction was discontinued.
The plant staff originally proposed that the control board closure failure was caused by failure to depress the close pushbutton long enough.
The hydraulic controls that operated the pumps were further evaluated.
Each valve had its own pump to increase the pressure applied to the piston, as indicated by the individual pressure switches.
The technical staff determined that pressure had built up on the
"close" side of the piston to the pressure switch (PSI)
setpoint, which prevented the operation of the pump and the solenoid valve in the closed direction.
The licensee proposed that the pressure buildup was caused by either temperature changes of the fluid trapped in the small chamber or by internal leakage of fluid.
Although this condition did not disable the emergency function of the valves, it did inhibit the pump from starting when the close button was engaged on the main control board.
The plant technicians stated that the pressure buildup could be relieved by using a jumper to bypass PSI, which would allow the pilot check valve to open and relieve the trapped fluid to the reservoir.
A temporary procedure change was made to OP/1/A/6100/03, which provided IAE with the jumper locations of all four valves if any CF containment isolation valves failed to close manually within the designated time period.
Furthermore, the procedure change lengthened the designated time period from 2 to 5 minutes, stating that it may take up to 5 minutes before intermediate position was indicated.
The inspectors identified a few minor procedural discrepancies and a misleading change in the procedure.
Inspectors informed the licensee of these concerns and actions were taken to resolve them. The inspectors will continue to evaluate this change in valve performance.
The licensee has proposed a minor modification to the valve to resolve the problem with the valve's inability to function as designed.
The minor modification is to rewire the CF containment isolation valve circuits to bypass'the PS1 contact in the "close" leg of the hydraulics.
The licensee stated that this modification would relieve the pressure and allow the operator to function as designed while the close pushbutton was depressed.
Inadvertent overpressurization would be prevented by. the internal relief valve, RV1, on the operator. 'The. licensee has scheduled this modification to be completed during the next refueling outage in August 1994.
These control board closure failures were identified in Inspection Report 94-06 as part of Inspector Follow-up Item 94-06-04, Main feedwater containment isolation valve ICF-35
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failure.
Since the failure mechanism of the valves and the proposed resolution to this problem was different in that report, this will be identified as Inspector Follow-up Item 94-08-03, Control board failures of main feedwater containment isolation valves.
6)
The inspectors evaluated the Westinghouse ' Nuclear' Safety Advisory Letter, NSAL 94-01-001, " Operation At Reduced Power Levels With Inoperable MSSVs," which identified a deficiency in the basis for the Westinghouse Standard Te'chnical Specifications (TS) 3.7.1.1 Table 3.7-1, " Operable Main Steam Safety Valves (MSSVs) Versus Applicable Power in Percent of Rated Power." TS 3.7.1.1 allowed operation with a reduced number of operable MSSVs at a reduced power level and power range neutron flux high setpoint.
The deficiency was the assumption that the maximum allowable initial power level was a linear function of the available MSSV relief capacity; this was not valid.
Westinghouse found that, in a Loss of Load / Turbine Trip (LOL/TT) event at the current reduced power levels, a delayed reactor trip on low steam generator water level may not occur before steam pressure exceeds 110% of the design value if one or inore MSSVs are inoperable. Westinghouse determined that the MSSV issue did not represent a substantial safety hazard.
NSAL-94-001 provided a more conservative methodology for correctly adjusting the power range neutron flux high setpoint.
The licensee had requested a change to TS 3.7.1.1, Table 3.7-1, in May 1993 to reduce the power range neutron flux high setpoints by 3 to 8 percent using the current basis formula. The licensee requested the TS amendment because the current reduced trip setpoints were derived by assuming the MSSVs were the same size and had the same relieving capacity. During their Design Basis Document development process, the licensee discovered that their MSSVs were certified to different ASME relieving capacities.
The inspectors note:1 that the licensee submitted the TS amendment as a conservative measure prior to NSAL-94-01-001.
The inspectors discussed NSAL-94-01-001 with regards to the licensee TS amendment with the plant staff and the NRR project manager for McGuire. NRR and the licensee decided to place the amendment on hold until the completion of the licensee's evaluation of NSAL 94-01-001.
The inspectors evaluated the power range neutron flux high setpoints using Westinghouse's conservative methodology and the licensee's certified relieving capacities of the MSSVs.
The inspectors found that the conservative methodology produced setpoints significantly lower than the current TS 3.7.1.1 setpoints.
Furthermore, the inspectors noted that
the licensee's current TS required the power range neutron flux high setpoint to be reduced if one of the twenty MSSVs
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is declared inoperable, whereas the Westinghouse Standard TS was based on one inoperable MSSV per steam line (four total)
for reducing the setpoint.
The licensee was still evaluating this issue, but has required that engineering be notified upon MSSV inoperability.
In addition, the inspectors questioned the station's ability to mitigate the consequences of an anticipated transient without scram (ATWS) given the reduction in MSSV relieving capacity.
The licensee was still evaluating this concern.
This is Inspector Follow-up Item 94-08-04, Operation at reduced power levels with inoperable main steam safety valves.
7)
The inspectors are continuing to monitor problems with the station's leakage detection systems.
The inspectors and plant staff have questioned the system's ability to meet its design basis. According to Regulatory Guide 1.45, the leakage detection system should be able to detect unidentified leakage of 1 gpm within one hour.
As a result, the licensee determined that containment air gaseous monitor, EMF-39, was declared past inoperable and containment airborne particulate monitor, EMF-38,.was declared conditionally operable.
In addition, Special Order 94-06 has been issued to operations personnel to monitor containment floor and equipment sump flows closely and to calculate sump input rate once per hour.
Also, the special order contained steps to be taken if EMF-38 is declared inoperable.
The inspectors will continue to track the
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licensee's actions on leakage detection.
e.
Top Equipment Problem Resolution Process The licensee has developed a new program to quickly close certain plant equipment problems. The Top Equipment Problem Resolution Process (TEPR) focuses management attention on selected equipment problems until resolution and closure are attained.
The TEPR coexists with the Problem Investigation Process (PIP), which also identifies station problems that needed resolution.
The TEPR consists of the Major Equipment Problem Resolution list and the Top Plant Work-Arounds Problem Resolution list. The Major Equipment Problem Resolution' list contains ten plant equipment problems that have a high impact, or have the potential to have a
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high impact, on plant availability, reliability, or nuclear safety.
Examples of items on the list were feedwater regulating valve reliability, EMF availability, and DP battery capacity.
The Top Plant Work-Arounds Problem Resolution list consists of twenty plant problems that prevent the operation or maintenance of systems and/or equipment as originally designed or intended. This
list includes such items as the Unit 2 boric acid flow controller, diaphragm valve bolting, and pressurizer heater problems.
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Each item on the lists was assigned to individuals from the appropriate work group to manage and resolve the problem.
The TEPR project review team consists of management representatives who meet once a month to evaluate the progress of each item, replace-closed items with new items, and change priorities as-necessary.
The inspectors noted that the licensee's management has begun to pursue the resolution of important plant equipment problems.
Since the TEPR process was recently developed, the inspectors could not evaluate the process' overall effectiveness.
The inspectors will continue to monitor the licensee's progress on closing important plant equipment problems and work-arounds.
f.
Severe Weather Preparations On March 27, 1994 a tornado warning was declared for the counties surrounding the McGuire Station. A tornado warning is a public notification by the National Weather Service (NWS) that an actual tornado has been reported or has been sighted on radar. There had been several tornados sighted in the Char _lotte area. As a result the National Weather Service issued a tornado warning for Mecklenburg, Gaston, Lincoln, Cabarrus, and Cleveland Counties.
The station is located in Mecklenburg county.
The inspectors discovered that the station did not enter the
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procedure, as required, designed to protect the faci _lity against natural disasters such as low water flood,. hurricane, seiche and tornados.
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Plant procedure, Natural Disasters RP/0/A/5700/06, was designed to
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provide the shift supervisor with guidance on steps to take if a
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natural disaster, such as one listed, is imminent according to information from radio broadcasts, dispatcher, or U.S. Weather Bureau, or observation.
The licensee had implemented this
procedure during a previous tornado threat.
Although the station took some precautionary measures, it was not evident that the licensee made general announcements to warn personnel that the site was under a tornado warning.
In addition,
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there was no evidence that' attempts were made to coordinate information to and from the System Dispatcher concerning system l
conditions or anything that might affect plant load.
There was no evidence that the licensee had taken actions to survey and anchor yard cranes, to minimize or stop the handling of radioactive materials and releases of radioactive waste to the environment, or to monitor the groundwater drainage system.
Coincidentally, no radioactive materials were being handled and no environmental releases were in progress.
The inspectors discovered that, although the shift manager had referred to the procedure, this was not communicated to the
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control room shift supervisor.
Furthermore, the shift manager did not believe that the facility was under a tornado warning because the NWS announcement did not specifically refer to the northern portion of the Mecklenburg county.
In addition, the shift control room SRO was not initially aware of the procedure's existence and the fact that it should have been implemented.
The inspectors discussed this with NWS personnel, who stated that when a tornado warning is issued it is applicable to the entire county.
The inspectors reviewed site meteorological data that revealed that winds were greater than 60 miles per hour on site for a brief period.
The site emergency procedures required an Unusual Event to be declared if winds are sustained at 60 miles an hour for 15 minutes.
There was no damage to the station.
The inspectors reviewed the FSAR and Design Basis Documentation and found that the facility was designed to withstand a tornado with a rotational wind speed of 300 mph, translational speed of 60 mph, radius of maximum rotational speed of 250 ft. and tornado-induced negative pressure differential of 3 psi occurring in three seconds.
The inspectors reviewed Regulatory Guide 1.76, " Design Basis Tornado for Nuclear Power Plants," and noted that, although these were exceptions to the stated design parameters, the design basis tornado was acceptable.
The inspectors reviewed the McGuire SER and FSAR Section 3.3.1 Wind Loading and noted that the design wind velocity for all Category I structures is 95 miles per hour at 30 feet above the nominal ground elevation corresponding to the fastest wind within a recurrence interval of 100 years.
l The inspectors reviewed the natural disaster procedure and found several inadequacies.
For example, the procedure did not instruct licensee per sonnel to take steps to restore important plant systems and components to service, realign ventilation systems, stop fuel handling activities, or conduct an inspection of the site for loose objects that could become potential missiles and damage equipment.
The inspectors also noted that the procedure was not specifically written to mitigate the effects of a tornado but other natural disasters as well.
The inspectors reviewed procedures from similarly designed nuclear stations and found that measures such as realigning or shutting down ventilation were implemented during a tornado warning to minimize the effects of the tornado generated differential pressure.
The inspectors concluded that the licensee failed to take adequate measures to protect the facility and personnel from a possible tornado threat by having inadequate procedures and by failing to implement the plant's natural. disaster procedure.
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inspectors also concluded that the licensee needs to evaluate the adequacy of their' procedure for a tornado watch and warning.
This is identified as Unresolved Item 50-369,370/94-08-02, Natural Disaster Procedur.
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One unresolved item and two inspector follow-up items were identified.
3.
Surveillance Testing (61726)
Observed Surveillance Tests Selected surveillance tests were reviewed and/or witnessed by the resident inspectors to assess the adequacy of. procedures and performance as well as conformance with the applicable TS.
Selected tests were witnessed to verify that (1) approved procedures were available and in use, (2) test equipment in use was calibrated, (3)
test prerequisites were met, (4) system restoration was completed, and (5) acceptance criteria were met.
The following selected tests were reviewed or witnessed in detail:
a.
Auxiliary Feedwater Pump #2 Operability Test, PT/2/A/4252/18 The inspectors observed the implementation and completion of the operability testing of the Unit 2 turbine driven auxiliary feedwater pump.
Procedure PT/2/A/4252/18, Auxiliary Feedwater Pump #2 Discharge Pressure Verification, was used.
This test ensured that the licensee complied with technical specifications by verifying, every 31 days, that the steam-driven auxiliary feedwater pump could develop a discharge pressure equal to or greater than 1,210 psig at a flow of equal to or greater than 900 gpm. The test was conducted while the unit was in Mode 1 with the secondary steam supply pressure greater than 900 psig.
The inspectors were in the control room during the test ar.d cbserved the reactor operator conducting the required valve manipulations and valve position verifications, and controlling the auxiliary feedwater pump.
The assigned technical staff acquired the data for pump discharge pressure and flow rate.
Pump vibration measurements were also taken while the pump was running.
The vibration data were recorded by the test technicians for equipment performance trending.
The inspectors verified that the
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operability test was adequately performed by competent personnel and was conducted in accordance with the prescribed procedural requirements.
b.
2B Diesel Monthly Operability Test. FT/2/A/4350/02B While performing muthly surveillance, PT/2/A/4350/02B, the licensee shut down the 28 diesel generetor when an acoustical transducer was inadvertently dropped into the generator housing
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during testing. An operations technician was attempting to reposition the acoustical transducer when it fell into the grating covering the generator. The acoustical transducer was used during the start of the diesel to verify the operability of the air starting solenoids.
The crew performing the test heard a loud banging noise and immediately shutdown the diesel.
The licensee
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declared the diesel inoperable and performed a verification of off-site power as required by technical specifications.
The inspectors reviewed the technical specification surveillance log and noted that the monthly surveillance had not been recorded.
The inspectors revealed this to the licensee, who promptly corrected the 109 The failure to log this surveillance was a contributor to an earlier failure to perform this surveillance when required.
The inspectors examined the generator internals.
The damage was minor with some slight scarring on some of the internal surfaces.
The object was retrieved; however, a tiny amount of metal from the transducer was not found.
In addition, the licensee performed meggering and potential testing and observed no abnormalities.
The inspectors observed a repeat of the diesel generator operability test.
No discrepancies were noted.
The inspectors noted that the licensee immediately took actions to restore the diesel to operable status.
The inspectors concluded that human performance errors are continuing to contribute to safety system unavailability.
c.
Ice Condenser Intermediate Deck Door and Monitoring System, PT/2/A/4200/14A The inspectors observed the performance of PT/2/A/4200/14A, Ice Condenser Intermediate Deck Door and Monitoring System Inspection.
The inspection was performed in accordance with Technical Specification Surveillance requirements 4.6.5.3.2a and 4.6.5.4.a.
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The surveillance requirement was used to verify the operability of the ice condenser intermediate deck doors and the operability of i
the ice condenser inlet door position monitoring system.
The procedure required that each ice condenser intermediate door be
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checked closed and free of ice.
The inspectors observed that the operation performance technician
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used a thinners hammer to remove ice, which may have prevented the doors from opening, from the surface of the doors, joints and hinges.
The inspectors questioned if the surveillance properly demonstrated that the doors would open when required due to ice accumulation between the deck plate and door seal.
The accumulation would not be visible during this surveillance.
The inspectors reviewed the technical specification surveillances and noted that the 18-month surveillance was designed to ensure that the doors would open as required.
However, because of the extended time interval of the surveillance, and the possible ice accumulation, the inspectors questioned if the licensee should demonstrate that the doors would open on a shorter frequency.
The inspectors reviewed the technical specification surveillance interpretation for the 18-month surveillance and verified that its
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purpose was to prove operability of the doors.
The inspectors noted that the interpretation referred to a corrective maintenance procedure instead of a performance test to accomplish the surveillance.
The inspectors showed this discrepancy to the licensee, who promptly corrected the interpretation.
The inspectors also observed the inlet door monitoring panel and found no discrepancies.
The licensee is evaluating the inspectors'
concern about ice accumulation preventing.the doors from opening as required.
d.
4 kV Unit 1 Sequencer Undervoltage Detector Actuating Device Operability Test, PT/1/A/4350/04
,l The inspectors observed the performance of PT/1/A/4350/04, 4 kV j
Unit 1 Sequencer Undervoltage Detector Actuating Device i
Operational Test.
The test was designed to functionally test the 4 kV bus undervoltage relays used to sense degraded bus voltage (station blackout) and meet technical specification requirements.
Each sequencer undervoltage relay was tested at the value associated with the undervoltago condition.
The inspectors observed that each relay tripped and that the appropriate sequencer relay energized.
The inspectors noted that, although the test had been scheduled, a 45-minute delay occurred because the VC/YC system had to be realigned.
No other discrepancies were observed during the test.
i The inspectors concluded that some work coordination problems
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between operations and other station groups continued to exist.
l e.
Nonconservative Reactor Coolant Unidentified Leakage Calculation
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On December 7, 1993, during an investigation of a stem packing leak on 2NI-54A, Cold Leg Accumulator 2A Discharge Check Valve, the licensee discovered that the valve stem leakoff had a direct flow path to the reactor coolant drain tank (NCDT). As a result,
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water from the refueling water storage tank (FWST) was added to the NCDT via the cold leg accumulators.
The licensee initiated i
Problem Investigation Process (PIP) 0-M93-1253 to investigate the i
circumstances surrounding the problem and to determine the appropriate corrective actions.
The volume from the NCDT was used as part of the identified leakage calculation and was used to calculate the unidentified leakage rate.
The addition of the water from the FWST changed the volume in the NCDT and the results of the calculations.
Upon further review, the licensee identified other inputs to the NCDT and PRT that added water from sources other than the reactor l
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coolant (NC) system or interconnected auxiliary systems containing NC system water.
The licensee generated Licensee Event Report (LER) 94-01 in response to these findings.
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Technical Specification (TS) 3 4.6.2 required that the NC system unidentified leakage not exceed one gallon per minute (gpm) during Modes 1, 2, 3, and 4.
In the past, the licensee calculated total
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NC system leakage by adding the NC system mass change, the volume control tank (VCT) mass change, and the pressurizer mass change.
The identified leakage was determined by adding the NCDT mass change and the pressurizer relief tank (PRT) mass change.
The unidentified leakage was the difference between the total leakage
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and the identified leakage.
The licensee performed past and present operability evaluations of the NC system leakage calculation program for both units.
Present operability was determined to be conditional; both units were operable as long as total leakage remained less than 1 gpm.
System modifications removed all inputs from sources other than the NC system or auxiliary systems containing NC system water to the NCDT.
Similar inputs to the PRT from other sources
. unaccounted for could not be removed at the time. The licensee procedurally eliminated the PRT mass change from the identified leakage calculation and compared the unidentified leakage results prior to and after the modifications and procedure change.
The licensee determined that the unidentified leakage difference were approximately 0.13 gpm for Unit I and 0.34 gpm for Unit 2.
These differences were added to previous unidentified leakage calculations for the associated units.
The results indicated that there were at least twelve occasions during which the unidentified leakage had' exceeded TS 3.4.6.2 limits for both units in the past twelve months. The licensee declared the NC system leakage calculation program past inoperable.
The inspectors have reviewed LER 94-01' and the licensee's past and present operability evaluations.
This condition was identified as Unresolved Item 50-369,370/93-29-02, Calculating the unidentified reactor coolant leak rate.
Due to the numerous examples of exceeding TS 3.4.6.2 in the past twelve months, this is identified as Violation 50-369,370/94-08-01,'Nonconservative unidentified reactor coolant leakage calculation.
Therefore, Unresolved item 50-369,370/93-29-02 will be closed and is now identified as a Violation.
One violation was identified.
4.
Maintenance Observations (62703)
Resident inspectors reviewed and/or witnessed routine maintenance activities to assess procedural and performance adequacy and conformance with the applicable TS.
The activities were witnessed to verify that, where acceptable, approved procedures were available and in use, prerequisites were met, equipment restoration was completed, and maintenance.results were adequate.
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The following maintenance activities were reviewed or witnessed in detail:
a.
Standby Shutdown Facility Diesel Generator (SSF)
The inspectors evaluated work order 94000429-01 and procedure IP/0/B/3061/20, Standby Shutdown Facility Diesel Generator NICAD Battery and Charger Maintenance.
During the week of March 14, the maintenance staff performed an annual inspection and cleanup of the SSF diesel generator battery.
The inspectors observed the work activities and determined that the inspections and clean-up
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activities were conducted in accordance with the work order and maintenance procedure.
b.
Ice Condenser Refrigeration Sub-System Insulation Upgrade The Ice Condenser (NF) Refrigeration Sub-System was divided into three stages:
the refrigeration loop, the glycol loop, and the air cooling loop.
The glycol loop used six glycol pumps to transport the heat removed from the NF air handling units, the floor cooling coils, and the ice machines to the chillers.
The chillers maintained glycol outlet temperature at s 5'F.
In October,1993, the licensee began to replace the insulation on portions of the Units 1 and 2 NF glycol loops. The upgrade was a challenge to the insulation team since the NF system could not be isolated during the process.
The old insulation was made of polyurethane, which retained moisture from the air when cracked or damaged. Minor leakage from-1 elbows and valve connections in the piping also caused. damage to the insulation. The retained moisture froze to the piping and the insulation, allowing leakage to migrate to other portions of the
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system.
The frozen insulation and ice had to be chipped away and j
the piping had to be thawed before the new insulation was
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installed.
The new insulation was made of foam glass, which had a lower water permeability.
In dense piping areas where cutting the foam glass insulation would compromise its effectiveness, elastomer rubber insulation was used.
Foil paper and vinyl mastic were applied to the outside of the foam glass and elastomer rubber insulation, respectively, to provide more protection against water vapor.
The licensee stated that the insulation upgrade was on-going and the entire NF system insulation outside of containment would be replaced.
The installation crews have become specialized at the time consuming installation technique.
The inspectors examined the upgraded sections of the glycol loop, which included the glycol pumps, the area around the glycol pumps, and portions of the supply and return piping up to the outside of
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containment. The inspectors concluded that the new insulation substantially improved the material condition of the system.
In addition, the licensee stated that the upgrade increased the efficiency of the system and reduced some safety concerns.
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Diesel Fuel Oil Storage Tank Level Indication Modification Installation The inspectors observed the installation of the new tank level instrumentation for the diesel fuel oil storage tanks lA and IB.
The new instrumentation was being installed because of reliability
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problems associated with the existing Barton instrumentation.
Technical Specifications LCO 3.8.1.1 required a minimum of 39,500 gallons of fuel oil in a diesel fuel oil storage tank.
The licensee discovered that tank level was below this TS limit for over five months.
The existing instrumentation sensed pressure using a capillary gauge.
The new instrumentation is a MTS Level Plus Gauging System that uses a programmable monitor and gauging system which senses fuel oil level using a probe / float arrangement.
The new instrumentation is highly accurate and has been used extensively in the chemical and petroleum industry where it has performed well.
The MIS level instrumentation monitored fuel oil tank level and provided an OAC and local annunciator alarms at a level that corresponded to a usable tank volume of approximately 41,000 gallons.
The modification was completed under W.0. 94016238 and W.O.
94015155.
The inspectors observed the complete installation of one of the level instruments. The inspectors also observed the installation and functional verification tests.
These tests were
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designed to verify proper operation through manipulation of the float, verification of the alarm setpoint, and verification that actual level was obtained on the monitor display.
No discrepancies were observed.
The inspectors reviewed the 50.59 evaluation for the modification and found no discrepancies.
The inspectors also observed good coordination among the station groups involved in the installation of the fuel oil tank monitor.
After installation, the inspectors performed frequent periodic observations of the new gauge and found no discrepancies; however,
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a few problems have been experienced with the level
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instrumentation sensing wiring, which caused a loss of indication.
The licensee is evaluating the problem.
The inspectors concluded that the level gauge modification should-provide a more reliable and accurate measurement of the fuel-oil level in the diesel fuel oil storage tanks.
No violations or deviations were identified.
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5.
Licensee Quarterly Emergency Drill (71707)
On March 16, 1994, the inspectors observed the Technical Support Center (TSC) personnel during their quarterly emergency drill.
The basic scenario consisted of a 60 gpm tube leak-detected in the "lC" steam generator with the 1A diesel generator, the 1A motor driven auxiliary
"eedwater pump, and the lA centrifugal charging pump out of service.
Since reactor coolant system leakage was greater than 50 gpm, an Alert was declared and the TSC and the OSC were activated.
Fifty minutes into the scenario, a Site Area Emergency was declared when the power operated relief valve (PORV) and the block valve on the "C" steam generator failed in the fully open position.
The inspectors noted that the licensee was confused about whether the PORV was open or just leaking by. At one hour and thirty minutes into the scenario, a loss of off-site power (LOOP) to Unit 1 occurred because of a power grid instability.
Normal-and backup power did not automatically swap to Unit 2 and the IB diesel generator did not start.
The Unit 1 turbine driven auxiliary feedwater pump failed to start because of a failed stop valve.
A General Emergency was declared two hours into the drill event.
The transition of control from the control room to the TSC was complicated because the Site Area Emergency was declared at approximately the same time.
After the LOOP, the inspectors noted that communications among the TSC staff members was difficult, and only two internal assessments were held during the 3.5-hour scenario.
Furthermore, the inspectors noted that Operations did not have enough personnel, especially non-licensed operators (NL0s), to respond to the event.
The inspectors reviewed the licensee's critique of the drill and found that it adequately recognized these and other deficiencies and proposed solutions for the next emergency drill.
6.
Information Meetings With Local Officials and Members of the Public (71707)
On March 29, 1994, the inspectors attended a meeting between the NRC and Duke Power Company management.
The meeting was open to the public and was held to allow open discussion between members of the NRC and Duke Power concerning the conclusions of the SALP Board, which were documented in Report 50-369,370/94-01.
Following the SALP Report discussion, the inspectors attended a meeting that was held between the NRC, the public, and local officials.
During this meeting, several of the local representatives made positive
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comments about the licensee's cooperative and responsive attitude toward public safety and emergency preparedness.
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In the afternoon of March 29, the inspectors attended a public briefing that was held in the Federal Building in Charlotte, North Carolina, by the NRC Regional Administrator.
Representatives from the State of North Carolina, Duke Power Company, the press, and members of the public were present.
During the briefing, the Regional Administrator provided:
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(1) the general status of the nuclear power plants located in North Carolina, (2) comments about the N.C. State College reactor, (3) the status of the General Electric Fuel Facility in Wilmington, N.C.,
and (4) comments about low level waste storage,.as it may affect N.C.
A public citizen from Iredell County made comments and asked questions about the emergency evacuation plans for the McGuire site.
His concerns focused on proposed housing developments to be located across Lake Norman in Iredell County, along Pinnacle Shores near N.C. Road 150 and at the Brawley School Peninsula.
The Regional Administrator provided a
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response to the citizen's comments.
Several questions were asked by the media; many were about recent changes within the Duke Power organization.
7.
Assessment of Licensee's Use of Overtime (71707)
l In response to a Region II initiative, the inspectors conducted an evaluation of the site contrels for the use of overtime by staff members who perform safety-relate:d funv. ions.
The evaluation included reviewing:
1) the TS section 6.2.2.3, 2) the administrative procedures
that implemented the TS, 3) the audits and safety evaluations conducted by the licensee as they affect the use of overtime, and 4) the overview of overtime by station management.
The inspectors evaluated the time card Records and Requests for Work Hours Extension which allowed the use of overtime.
The specific times evaluated were between March 1993 and October 1993.
Groups that were evaluated included operations, engineering, maintenance, eddy current test personnel and radiation protection personnel.
Generally, the maintenance staff worked a nominal 40-hour work a.
week during the period with some exceptions.
The inspectors found that there were 21 maintenance personnel who worked most of the overtime during the period. Those 21 were primarily assigned to work on upgrading the emergency diesel generators.
This small group averaged 7.9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> of overtime, each, per week.
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With few exceptions, the operators (SR0(s), R0(s), and NLO(s)),
worked nominal 40-hour weeks during the 36 week period.
For example, there were only 35 instances when operators requested to work more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> during a seven day period.
The inspectors determined that in each instance the request forms.were submitted and approved, as required by Duke Power Company Nuclear Policy Manual, Volume 2, Section 200, prior to the extension of work hours, when applicable.
c.
The radiation protection staff, totaling 272 people, averaged less than 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> per week of overtime per person.
d.
The crews performing eddy current testing on the plant steam generators, consisting of 33 people, averaged 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br /> per week-per person.
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Other work groups, such as work planning, engineering, and other support groups, were evaluated for expenditure of overtime.
Generally, their use of overtime was liinited to scheduled and forced outages.
Many of these groups averaged as little as zero, and as much as six, hours overtime per person for the entire seven month period.
The amount of overtime used by the eddy current test and radiations protection personnel indicates an upward trend.
However, the inspectors noted that Unit I has experienced three forced outages during the time period evaluated, in addition to the refueling outages.
These forced outages were caused by leaking steam generator tubes.
Unit 2 has also experienced forced.
outages that required these two groups to expend additional man-hours to make repairs. The use of overtime was consistent with the need for man-hours incurred by the number of outages that
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occurred during the 36-week period.
The inspectors determined that the staff's use of overtime was not excessive.
8.
Assessment of the Standby Shutdown System Testing (71707)
The inspectors conducted an evaluation of the performance testing (PT)
of the standby shutdown system (SSS) dedicated components.
These components included the SSS diesel generator, the standby makeup pump, and the turbine driven auxiliary.feedwater (CA) pump.
Additionally, the applicability of Oconee's standby shutdown facility (SSF) findings, inspection Report 50-269, 270, 287/93-25, was considered with respect to McGuire.
The SSS provides a means to achieve and maintain hot standby conditions for 3.S days on both units following a fire incident or a plant security emergency in which the control room and auxiliary shutdown panel are unavailable.
The dedicated portions of the SSS were not designed to meet the consequences of design basis accidents.
The SSF and the dedicated portions of the SSS were not designed to seismic Category I or safety-related criteria except where the dedicated systems interfaced
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with safety-related systems. The SSF housed the dedicated diesel generator and its supporting equipment, batteries, switchgear, and control room, and was physically separated from other plant buildings.
The standby makeup pumps, one per unit, were located in the annulus l
below the fuel pool in the containment building and supplied normal RCP seal and system leakage makeup during SSS operation.
Unlike Oconee's SSF, the existing turbine-driven CA pump was considered part of the SSS
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and was used to feed the steam generators during SSS operation.
Since
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this pump was used during abnormal operations other than a fire or security emergency, Oconee's SSF findings were not applicable.
The inspectors did not evaluate the SSS design calculations.
l The SSS diesel generator and the turbine-driven CA pump were demonstrated operable once per 31 days per Selected Licensee Commitments i
(SLCS) 16.9-7, Standby Shutdown System, and Technical Specification (TS) 3.7.1.2, Auxiliary Feedwater System, respectively. The diesel was i
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required to start from ambient conditions and operate for at least 30 minutes at greater than or equal to 700 kW. The turbine-driven
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auxiliary feedwater pump was required to develop a discharge pressure a 1210 psig at a flow a 900 gpm when the secondary steam supply pressure was greater than 900 psig.
Additionally, SLCS 16.9-7 required that the turbine-driven CA pump be demonstrated operable at least once every 18 months through verification that the
"C" solenoid could be de-energized to open valve SA48AB to supply steam to the turbine-driven auxiliary
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feedwater pump.
SLCS 16.9-7 also required that the standby makeup pump develop a flow of 2 26 gpm at a pressure 2 2485 psig at least once every 92 days.
The inspectors reviewed the performance test procedures and did not observe any deficiencies.
The inspectors walked downed the SSF and the SSS components located outside of the SSF, except for the standby makeup pump.
The material condition of the SSF and the SSS components was acceptable.
9.
Followup on Previous Inspection Findings and Licensee Event Report (71707)
The following previously identified items and Licensee Event Reports were reviewed to verify that the licensee's responses, where applicable, and actions were in compliance with regulatory requirements and that corrective actions have been implemented.
This verification included
record review, observations, and discussions with licensee personnel.
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(Closed) Unresolved Item 369,370/93-29-02, Calculating the unidentified reactor coolant leak rate.
This unresolved item was identified as Violation 50-369,370/94-08-01 of this report.
Therefore, Unresolved Item 50-369,370/93-29-02 will be closed, and the issue will be identified as a Violation 50-369,370/94-08-01.
The following corrective actions have been implemented by the licensee:
a.
All inputs from sources other than the NC system or auxiliary i
systems containing NC system water to the NCDT were removed. The similar inputs to the PRT could not be removed at the time. The licensee procedurally eliminated the PRT mass change from the identified leakage calculation and compared the unidentified j
leakage results prior to and after the modifications and procedure l
change.
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b.
The licensee determined that the reactor coolant unidentified leakage calculation was past inoperable.
10.
Exit Interview (30703)
The inspection scope and findings identified below were summarized on April 12, 1994, with the Station Manager and member of his staff.
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The following items were discussed in detail:
Violation, 50-369,370/94-08-01, Nonconservative unidentified
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reactor coolant leakage calculation. (paragraph 3.e)
Unresolved Item, 50-369,370/94-08-02, Natural disaster procedure.
(paragraph 2.f)
Follow-up Item 50-369,370/94-08-03, Manual failures of main feedwater containment isolation valves. (paragraph 2.d.5)
Follow-up Item 50-369,370/94-08-04, Operation at reduced power levels with inoperable main steam safety. valves. (paragraph 2.d.6)
The licensee representatives present offered no dissenting comments, nor did they identify as proprietary any of the'information reviewed by the inspectors during the course of their inspection.
The licensee was informed by the inspectors that the item discussed in paragraph 9 was closed, 11.
Acronyms and Abbreviations
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American Society of Mechanical Engineers ATWS
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Anticipated Transient Without Scram BS
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Backshift CA
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Main Feedwater Control Isolation Valve DP
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Differential Pressure EMF
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Radiation Monitor Area FWST
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Refueling Water Storage Tank IAE
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Instrumentation and Electrical KC
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Component Cooling Water
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KCDT
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Component Cooling Water Drain Tank kV
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kilovolt kW
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kilowatt LCO
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Limiting Condition for Operation LER
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Licensee Event Report LOL/TT
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Loss of Load / Turbine Trip LOOP
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Loss of Off-site Power MSSV
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NCDT
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Reactor Coolant Drain Tank NCP
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Reactor Coolant Pump NF
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Ice Condenser Glycol NLO
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Non-licensed Operator
Nu' lear Regulatory Commission
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Nuclear Safety Advisory Letter NV Boric Acid Transfer
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National Weather Service OAC
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Operator Aid Computer OSC
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Operations Support Center PIP
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Problem Investigation Process
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Power Operated Relief Valve PS
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Pressure Switch PT
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Performance Testing RI
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Resident inspector Reactor Operator R0
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Relief Valve SLCS
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Sele-ted Licensee Commitments SRI
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Senior Resident inspector
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Senior Reactor Operator SSF
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Standby Shutdown Facility SSS
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Standby Shutdown System TEPR
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Top Equipment Problem Resolution Process TS
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Technical Specification TSC
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Control Area Ventilation VCT
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Volume Control-Tank WM
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Waste' Monitor and Disposal WO
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Work Order YC
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Control Area Chilled Water
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o UNITED STATES
. [Sa ato '%
NUCLEAR REGULATORY COMMISSION
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REGloN 11
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101 MARIETTA STREET, N.W., SUITE 2900 j
ATLANTA, GEORGIA 303234199
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May 061994 Docket Nos.
50-369, 50-370 License Nos. NPF-9, NPF-17 Duke Power Company ATTN: Mr. T. C. McMeekin Vice President McGuire Nuclear Station 12700 Hagers Ferry Road Huntersville, NC 28078-8985 Gentlemen:
SUBJECT:
NOTICE OF VIOLATION (NRC INSPECTION REPORT NOS. 50-369/94-08 AND 50-370/94-08)
This refers to the inspection conducted by Mr. G. Maxwell of this office on March 13, 1994 - April 9, 1994. The inspection included a review of activities authorized for your McGuire facility.
At the conclusion of the inspection, the findings were discussed with those members of your staff identified in the enclosed report.
Areas examined during the inspection are identified in the report.
Within these areas, the inspection consisted of examinations of selected procedures and representative records, interviews with personnel, and observation of activities in progress.
Based on the results of this inspection, certain of your activities appeared to be in violation of NRC requirements, as specified in the enclosed Notice of
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Violation (Notice)., The violation is of concern because of the duration of noncompliance with the technical specification and the lack of sufficient oversight to identify this concern prior to December 1993.
You are required to respond to this letter and should follow the instructions specified in the enclosed Notice when preparing your response.
In your response, you should document the specific actions taken and any additional actions you plan to prevent ecurrence. After reviewing your response to this Notice, including your proposed corrective actions and the results of future inspections, the NRC will determine if further NRC enforcement action is necessary to ensure compliance with NRC regulatory requirements.
In accordance with 10 CFR 2.790 of the NRC's " Rules of Practice," a copy of this letter and its enclosures will be placed in the NRC Public Document Room.
The response directed by this letter and the enclosed Notice is not sub, ject to j
the clearance procedures of the Office of Management and Budget as required by the Paperwork Reduction Act of 1980, Pub. L. No.96-511.
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MAY 061994 Duke Power Company
Should you have any questions concerning this letter, please contact us.
Sincerely, dht%to d
Ght.L i
Marvin V. Sinkule, Chief Reactor Projets Brt.nch 3 Division of Reactor Projects Enclosures:
1.
Notice of Violation
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2.
NRC Inspection Report cc w/encls:
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R. O. Sharpe Compliance Duke Power Company 12700 Hagers Ferry Road Huntersville, NC 28078-8985 G. A. Copp Licensing - EC050 Duke Power Company P. O. Box 1006 Charlotte, NC 28201-1006 A. V. Carr, Esq.
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Duke Power Company 422 South Church Street Charlotte, NC 28242-0001 J. Michael McGarry, III, Esq.
Winston and Strawn 1400 L Street, NW Washington, D. C.
20005 Dayne H. Brown, Director Division of Radiation Protection N. C. Department of Environment, Health & Natural Resources P. O. Box 27687 Raleigh, NC 27611-7687 County Manager of Mecklenburg County 720 East Fourth Street'
Charlotte, NC 28202 cc w/encls cont'd:
(See page 3)
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Duke Power Company
cc w/encls cont'd:
T. Richard Puryear Nuclear Technical Services Manager Carolinas Oistrict Westinghouse Electric Corporation 2709 Water Ridge Parkway, Ste. 430 Charlotte, NC 28217 Dr. John M. Barry, Director Mecklenburg County Department of Environmental Protection 700 North Tryon Street Charlotte, NC 28203 Karen E. Long Assistant Attorney General N. C. Department of Justice P. O. Box 629 Raleigh, NC 27602 i
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