IR 05000254/1986013
| ML20203M467 | |
| Person / Time | |
|---|---|
| Site: | Quad Cities  |
| Issue date: | 08/22/1986 |
| From: | Boyd D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20203M459 | List: |
| References | |
| RTR-NUREG-0737, RTR-NUREG-737, TASK-2.F.1, TASK-2.K.3.28, TASK-3.D.3.4, TASK-TM 50-254-86-13, 50-265-86-12, GL-85-03, GL-85-22, GL-85-3, IEB-86-001, IEB-86-002, IEB-86-1, IEB-86-2, NUDOCS 8609030477 | |
| Download: ML20203M467 (14) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Reports No. 50-254/86013(DRP); 50-265/86012(DRP)
Docket Nos. 50-254, 50-265 Licenses No. DPR-29; DPR-30 Licensee:
Commonwealth Edison Company Post Office Box 767 Chicago, IL 60690
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Facility Name: Quad Cities Nuclear Power Station, Units 1 and 2 Insp'ection At: Quad Cities Site, Cordova, IL Inspection Conducted: June 8 through August 9, 1986 Inspectors:
A. L. Madison A. D. Morrongiello 8.
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Approved By:
D. C. Boyd, 'hief 17 - e 2 - FC Reactor projects Section 2D Inspection Summary Inspection on June 6 through August 9,1986 (Reports No. 50-254/86013(DRP);
50-265/86012(DRP))
Areas Inspected:
Routine, unannounced inspection by the resident inspectors of actions on previous inspections findings; operations; radiological controls; emergency preparedness; security; refueling / outages; quality assurance; quality control; administration routine reports; LER review; regional requests; training; and independent inspection.
Results: Orie'vio.lation was identified with two examples of failing to follow procedures.
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DETAILS 1.
Persons Contacted R. Bax, Station Manager
- T. Tamlyn, Production Superintendent
.T. Lihou, Technical Staff Supervisor
- R. Robey, Technical Services Superintendent
- M. Kooi, Compliance Coordinator
- C. Norton, Quality Assurance
- Denotes those present at the exit interview on August 11, 1986.
The inspectors, through direct observation, discussions with licensee personnel, and review of applicable records and logs, examined the areas stated in the inspection summary and accomplished the following inspection modules.
37700 Design Changes and Modifications 42700 Plant Procedures 61726 Monthly Surveillance Observations 62703 Monthly Maintenance Observations 71707 Operational Safety Verification 71710 ESF System Walkdown 90713 Review of Periodic and Special Reports 92700 Onsite Review of LERs 92701 Followup on Inspector Identified Problems and Unresolved Items 92703 Generic Letter Followup 92705 Followup - Regional Requests 92706 Independent Inspection 93702 Onsite Followup of Events The insp'ctors verified that activities were accomplished in a timely e
manner using approved procedures and drawings and were inspected / reviewed as applicable; procedures, procedure revisions and routine reports were in accordance with Technical Specifications, regulatory guides, and industry codes or standards, approvals were obtained prior to initiating any work; activities were accomplished by qualified personnel; the limiting conditions for operation were met during normal operation and while components or systems were removed from service; functional testing and/or calibrations were performed prior to returning components or systems to service; independent verification of equipment lineup and review of, test results were accomplished; quality control records and logs were properly maintained and reviewed; parts, materials and equipment were properly certified, calibrated, stored, and or maintained as applicable; and adverse plant conditions including equipment malfunctions, potential fire hazards, radiological hazards, fluid leaks, excessive vibrations, and personnel errors were addressed in a timely manner with sufficient and proper corrective actions and reviewed by
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appropriate management personnel.
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Further, additional observations were made in the following areas:
a.
Action on Previous Inspections Findings (1) (Closed) Violation (254/86002-04; 265/86002-02 (DRP)):
Inadequate Design Review.
The inspectors have reviewed the licensee's response dated July 21, 1986 and verified that the actions stated therein had been accomplished. No further actions are required.
(2) (Closed) Violation (254/86002-03 (DRP)):
Failure to Follow Procedures.
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The inspectors reviewed the licensee's response dated July 21, 1986 and verified that the actions stated therein had been
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accomplished. No further actions are required.
(3) (Closed) Violation (254/86002-02 (DRP)):
Failure to Report.
The inspectors reviewed the licensee's response dated July 21, 1986 and verified that the actions stated therein had been accomplished. No further actions are required.
(4) (Closed) Violation (254/86002-01; 254/86002-01 (DRP)):
Inadequate Design Review - Station Batteries.
The inspectors reviewed the licensee's response dated July 21, 1986 and verified that the actions stated had been accomplished.
No further actions are required.
b.
Operations (1) Unit At the beginning of the inspection period Unit 1 was at full power. At various times during this period the unit operated on Economic Generation Control (EGC).
On July 8, Unit l's reactor water conductivity increased signifi-cantly. This problem was caused by leaking main condenser tubes.
The unit was shut down and the leaking tubes were plugged. The unit was made critical on July 9 at 1844 hours0.0213 days <br />0.512 hours <br />0.00305 weeks <br />7.01642e-4 months <br />. During the start up an edge rod was left at position 12 instead of being fully withdrawn.
It was discovered when the Unit Operator
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withdrew a rod in another group to position 04 and it settled at position 06 giving a rod withdraw error as indicated by the Rod Worth Minimizer (RWM), which was operational throughout the event. The o~perator acknowledged the RWM and corrected the error by placing that rod in position 04. At this time, the operator noticed an insert error. The operator checked the full core display, discovered the mispositioned rod, and halted
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further rod movements.
The rod was mispositioned due to failure to follow procedures. He then called a Qualified Nuclear Engineer who advised him on rod movements to reposition the edge rod. The rod was repositioned (but not according to station procedures) and the start up continued.
The duration of this event was approximately 20 minutes and no adverse' core effects resulted. The licensee gave both the operator and the Qualified Nuclear Engineer a letter of reprimand and a day off without pay for failure to follow procedures. Since rod pulls during a startup is a tedious process, a second operator is assigned to periodically relieve the first operator to lessen the possibility of making a mistake. The second cperator was given a letter of reprimand for not identifying. the error. The SCRE was given a letter of reprimand for not being fully aware of the activities on the unit in startup.
Additionally, the Shift Engineer was counseled regarding the performance of his crew during this startup. The licensee has also revised their procedures to include the following:
(1) Operators will no i
longer be allowed to relieve cach other until they are finished moving the group they are in, (2) more detail has been provided on how to verify the rod pulls, and (3) the procedure on returning rods to their in-sequence position will be modified to give Qualified Nuclear Engineers more options in repositioning rods. The operator had tried several times during the event to call an 00-7 (a process computer display of Present Control Rod Positions) but the system rejected his requests.
Now to verify rod positions after each group the operator will call an OD-7, or select each rod, or examine the full core display.
Additionally the RWM system will be changed. The new RWM system will give a rod block on any withdraw or insert error. The failures to follow procedures constituted the violation described in Appendix A (254/86013-01(DRP)).
Due to the extensive actions taken to correct the violation no reply to this violation is required.
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(2) Unit 2 At the beginning of this inspection period Unit 2 was in a scheduled maintenance outage. The unit was back on line on June 5 at 0356 hours0.00412 days <br />0.0989 hours <br />5.886243e-4 weeks <br />1.35458e-4 months <br />. At various times during this period the unit operated on Economic Generation Control (EGC).
On July 30 the licensee discovered a leak in the Reactor Water Cleanup System (RWCU) The system was isolated.
Investigations by General Electric revealed a crack on the pipe side of a pipe to elbow joint on the 4 inch return li.ne.
This area is upstream of the outboard containment isolation valve and this pipe is not Safety-Related. The pipe was repaired by weld overlay. The weld tested by visual means, by dye penetrant and ultrasonic means and finally by a hydrostatic test. Those tests showed the pipe was repaired and the RWCU System was returned to service August 5 at 0550 hours0.00637 days <br />0.153 hours <br />9.093915e-4 weeks <br />2.09275e-4 months <br />.
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For the report period the unit operated at full power or on EGC.
(3) Both Units The station has instituted a 0730 hours0.00845 days <br />0.203 hours <br />0.00121 weeks <br />2.77765e-4 months <br /> morning meeting. The participants in this meeting include the work planners in the various work groups and the Shift Engineer. The purpose of these meetings is to better coordinate maintenance activities with operations.
~ During plant tours of Units 1 and 2, the inspectors walked down the accessible portions of the Standby Liquid Control System and the Standby Gas Treatment System.
c.
Radiation Protection The fuel dec~ontamination project reached another milestone with the transfer and solidification of the resin. The transfer and solidification was performed without incident.
d.
Maintenance The following maintenance activities were observed / reviewed:
(1) Observed the installation of new check valve on the 2A Service Air Compressor.
(2) Observed portions of weld overlay repair to RWCU line.
e.
Surveillance The following surveillance activities were observed / reviewed:
(1) Observed portions of QIS-40, Electromatic Relief Valve -
Surveillance on Unit 2.
(2) Observed portions of ST-60, Power Operations Functional Test on Unit 2.
f.
Procedure Review QAP 700-1, Station Training Program, Revision 17.
QAP 1500-2, Nuclear Work Request, Revision 22.
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QEP 3'10-T3, Prioritized Notification Listing, Revision 17.
QFP 600-3, IRM and SRM Handling, Revision 5.
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QIP 730-2, TIP Ball Valve Removal, Repair, and Installation, Revision 6.
QTS 170-S1, Penetration Firestops Data Sheet, Revision 10 QAP 900-7, * Control of Use and Accuracy of Measuring Equipment, Revision 1.
QCP 1400-12, Quality Control Program for Chemistry Instrumentation,
Revision 5.
QCP 700-34, Environmental Temperature Monitoring Program, Revision 1.
g.
LER Review (1) Unit 1 (Closed) LER 86-02, Revision 00 and 01: Excessive Leakage through U-1 MSIV's During LLRT.
This LER remained open pending receipt of a supplemental report describing the causes of failure and corrective actions taken including those planned for long term considerations.
No further actions are required.
(2)
U_ nit 2 (a) (Closed) LER 86007, Revision 1:
Failure of 2B Core Spray Room Cooler.
This revision was issued to correct a typographical error and as such no further actions are required.
(b) (Closed) LER 86008, Revision 00: Core Spray Inoperable.
On May 25, 1986, Unit 2 was operating in the RUN mode at approximately 92 percent of rated core thermal power. The Unit 2 Equipment Attendant discovered that the 2-5748A Core Spray System Room Cooler had frayed belts.
The 2A Core Spray room cooler was declared inoperable.
The required surveillances were initiated in accordance with Technical Specifications.
The Unit 2 Diesel Generator (DG) was started and loaded for the surveillance requirements.
The DG had rua for approximately one minute loaded to 1000KW when the DG output breaker to Bus 24-1 tripped.
The Unit 2 DG was declared inoperable, a shutdown initiated and Unusual Event declared (see Inspection Report No. 265/86008).
Fraying of the room cooler belts was attributed to normal wear. The belts were replaced, and as corrective action to prevent recurrence, the room cooler belts will be inspected monthly to detect wear before failure occurs.
The cause
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of the Unit 2 DG trip could not be determined and repeated attempts to duplicate the event were unsuccessful.
Loss of the emergency power supply for tha 2B Core Spray subsystem (Unit 2 DG) rendered the 28 Core Spray subsystem inocerable as per Technical Specifications.
This meant that both core spray subsystems were technically inoperable.
In an effort to determine the cause of the breaker failure, the Electrical Maintenance Department removed the diesel to Bus 24-1 KV breaker from its cubical and cycled it open and closed several times. The breaker operated properly every time. The Electrical Maintenance Department also checked the diodes at the exciter cabinet, the Potential Current Transformer at the Generator Connection panel, the voltage regulator at bus 24-1 and the maintenance switch, however, no problems were found. The diesel was then loaded to 1000 KW and the problem was simulated twice.
Since no problems could be found, the diesel was declared operable.
As a future corrective action, temperature surveys are going to be conducted of the Core Spray, HPCI, RHR, and RCIC rooms.
The test will be performed while the system pumps are running and while the ventilation and room coolers are off.
The purpose of the test is to determine whether or not the room coolers are necessary for the operation of the Emergency Core Cooling Systems.
No further actions are required.
(c) (0 pen) LER 86009, Revision 00: 28 Core Spray Room Cooler Inoperable.
On June 26, 1986, Unit 2 was in the RUN Mode operating at 92 percent of rated core thermal power. An Equipment Operator on his rounds discovered that the 2B Core Spray Room Cooler had a broken drive belt and that the remaining belt had come off the pulleys. The 2B loop of the Core Spray System and the Unit Two Reactor Core Isolation Cooling System (RCIC) were declared inoperable. The 2B Core Spray pump and the RCIC turbine are located in the same room.
In the event of actuation of either system, the heat loading in the room could result in equipment
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damage without the room cooler. Technical Specification 3.5/4.5. A.2. states that. when one Core Spray subsystem is inoperable, the operable Core Spray subsystem, the Low Pressure Coolant Injection (LPCI) mode of the Residual Heat Removal (RHR) System, and the Diesel Generators required for operation of such components if no external source of power were avail:ble shall be demonstrated to be operable immediately. The operable Core Spray subsystem
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shall be demonstrated to operable daily thereafter. These surveillances were immediately performed and the associated systems demonstrated operable. Also, Technical Specifica-tion 3.5/4.5.E.2 states that when it is determined that the RCIC system is inoperable, the High Pressure Coolant Injection System (HPCI) shall be demonstrated to be operable immediately and daily thereafter. The required HPCI surveillances were immediately performed and HPCI was demonstrated to be operable. The Operating Department presently performs a daily check of the ECCS room coolers to verify that the belts are intact. This check has successfully identified frayed or worn belts in the past.
There is currently a study being performed to determine whether ECCS systems can safely perform as designed independent of the room coolers.
10 CFR 50.72(b)(2)(iii) requires a four hour notification to the NRC of any event or condition that alone could have prevented the fulfillment of the safety function of systems needed for core cooling. The 10 CFR 50.72 notification was made via the Emergency Notification System (ENS) six hours and fifteen minutes late, after a review the following day determined that the notification had not been made.
To prevent the recurrence of a late or missed NRC ENS notification associated with ECCS system inoperability the licensee has committed to revise the applicable equipment outage procedures.
Notes will be added to these procedures to clarify that a four hour ENS notification is required when a single train system is inoperable.
In addition, this event was discussed at the weekly Operating Department meeting, stressing the need to promptly notify the NRC when a single train system is inoperable, and the importance of careful inspection of ECCS room cooler belts during operating rounds.
Because the failure to report was self identified and also because of the prompt and effective corrective action, no enforcement action will be taken by NRC. However, this LER will remain open pending completion
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of the above procedure revisions.
(d) (Closed) LER 86010, Revision 00: Group III Isolation.
On June 27, 1986, while Unit Two was operating in the RUN mode at 99 percent of rated core thermal power, the Reactor Water Clean-up System isolated. The cause of the isolation was due to spurious actuation of the Clean-up System non-regenerative heat exchanger outlet temperature switch due to an electrical short.
Instrument Maintenance personnel were replacing a differential pressure switch when a wire they were feeding through a conduit shorted causing the spurious isolation. The root cause of the occurrence is personnel error. The Instrument Maintenance personnel were attempting to route the wire while it was
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still energized instead of performing the work with the equipment de-energized.
Corrective action was to counsel the involved personnel to de-energize equipment before performing such repairs in the future. This occurrence was also, discussed with the Instrument Maintenance Department during a weekly meeting.
.No further actions are required.
h.
Generic letters (1) (0 pen) Generic letter 8503: Clarification of Equivalent Control Capacity for Standby Liquid Control Systems.
The licensee has initiated a modification to this system to provide 80 gallons per minute (gpm) of 14 weight percent sodium pentaborate solution - the equivalent in control capacity to 86 gpm of 13 weight percent sodium pentaborate solution. The modification for Unit 2 will be completed by the end of Fall 1986 Refuel Outage while Unit I will be completed by the end of the Spring 1897 Refuel Outage.
This Generic letter will remain open pending completion of the modifications.
(2) (0 pen) Generic letter 8522: Potential For Loss of Post-LOCA Recirculation Capability Due to Insulation Debris Blockage.
Quad Cities Station has agreed to use Reg Guide 1.82 Rev. I as a guide for the conduct of 10 CFR 50.59 reviews dealing with modifications of thermal insulation installed on primary system piping and components.
However, Station Nuclear Engineering Department (SNED) does most safety evaluations for modifications involving primary coolant piping and no formal guidance exists to ensure that Reg Guide 1.82 Revision 1 will be utilized. The licensee is aware of this deficiency and the inspector's concern.
This Generic Letter will remain open pending resolution of this issue.
1.
Bulletin Followup (1) (0 pen) IE Bulletin 86-01, Revision 00: Minimum Flow Logic Problems That Could Disable RHR Pumps.
Issued May 23, 1986.
This bulletin identified a potential single failure vulnerability of the Residual Heat Removal (RHR) pumps minimum flow valve which could result in " dead heading" the RHR pumps.
Licensees were directed to:
(a) Promptly determine whether or not the facility had this single failure vulnerability.
(b)
If the prcblem existed, immediately instruct all operating shifts of the problem and measures to recognize and mitigate the problem.
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(c) Within seven days of receipt of this bulletin, provide (a) a written report to the NRC which identifies whether or not this problem existed at the facility, (b) if the problem exists, identify the short-term modifications to plant operating procedures or hardware that have been or are being implemented to assure safe plant operations.
(d) If the problem existed, provide a written report within 30 days of receipt of this bulletin informing the NRC of the st.hedule for long-term resolution of problems that are identified as a result of this bulletin.
The licensee immediately identified that the potential single failtre vulnerability did exist at Quad Cities and took the actions required by Item 2 above. Upon automatic initiation of RHR pumps, the operators were directed by temporary procedure to:
(1) Immediately verify a pump flow path is available via the minimum flow valves or the injection valves, (2) If-no flow path exists, manually open the minimum flow valves, and (3) If the minimum flow valves will not open or do not stay open, stop the RHR pumps and place the control switches in the PULL-TO-LOCK position. The pump should be monitored and restored to operation when a flow path is established.
By letter dated May 30, 1986, the licensee reported that upon reviewing the Station response with the corporate of fice and Dresden Station, the Station decided to amend its short term response.
Instead of stopping the RHR pumps upon loss of all flow paths, the " Containment Cooling Permissive" and the " Cont.
CLF 2/3 Level and ECCS Initiation Bypass" keylock switches will
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be used to allow opening the 1001-34 and 36 valves to establish a flow path to the torus.
Should a flowpath via the minimum flow valves or the vessel injection valves be established, the keylock switches shall be returned to their normal position and the 1001-34 and 36 valves closed. A temporary procedure was written stating these actions, and will be maintained until a long term solution is completed. The operating shifts were trained on the revised operator actions.
The resident inspectors verified that the above actions were completed.
By letter dated June 23, 1986, the licensee reported that their'
long term resolution involves performing a hardware modification to the LPCI/RHR pump minimum flow valve control logic. The conceptual design for this modification includes removing interlocks between divisions.
Currently the "A" and "B" minimum flow valves are both controlled by either flow sensor in the "A" or "B" loop (through auxiliary relay contacts). A failure of either of these sensors could close both minimum flow valves.
The modification will result in the "A" loop flow
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sensor controlling only the "A" valve, and similarly, the "B" loop sensor controlling the "B" valve. When the modification is implemented, the single failure concern addressed in IEB 86-01 will be eliminated.
At present, the modifications are scheduled for completions on both units by November 1, 1986. This Bulletin will remain open pending completion of said modifications.
(2) (Closed) IE Bulletin 86-02, Revision 00:
Static "0" Ring Differential Pressure Switches.
The Quad Cities Station does not use the subject models in safety-related applications.
Therefore, no further actions are required.
j.
TMI Action Plan Followup (1) (Ciosed) Item II.K.3.28. " Verify Qualification of Accumulators on Automatic Depressurization System Valves."
The subject of item II.K.3.28 of NUREG-0737 is the qualification of accumulators for the automatic depressurization system (ADS)
valves to perform their function for an extended period of time following an accident.
In the case of Quad Cities 1 and 2, four of the five ADS valves for each of the units are electromatic relief (EMR valves, which do not use pneumatic actuation, thus they do not have accumulators. The conditions necessary for acceptability of accumulators for ADS valves as stated in Item II.K.3.28 do not apply to EMR valves.
By letter dated January 18, 1980, Commonwealth Edison provided small break LOCA analyses with only four EMR valves operable.
In the analysis of the event, the four EMR valves are shown to provide the necessary depressurization capability for an extended period following the accident. The qualification of the accumulator associated with the single Target-Rock valve is not a factor in the capability of the remaining ADS valves to depressurize following the accident.
Item II.K.3.28 addresses the qualification of accumulators to perform for an extended period of time following an accident.
Such accumulators have been showr. not to be required for long term depressurization of the Dresden 2 and 3 and Quad Cities 1 and 2 units.
By letter dated June 16, 1986 NRR declared that this was acceptable and that no further review work was required.
No further actions are required.
(2) (Closed) Item II.F.1.3:
" Containment High-Range Monitor."
This licensee's responses to this item have been found
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acceptable and by letter dated June 10, 1986, NRR has issued applicable Technical Specification amendments. No further actions are required.
(3) (Closed) Item II.F.1.6:
" Containment Hydrogen Monitor."
This licensee's responses to this item have been found acceptable and by letter dated June 10, 1986, NRR has issued applicable Technical Specification amendments. No further actions are required.
(4) (Closed) Item III.D.3.4:
By letter dated October 31, 1984, the licensee stated that the work for this item would be completed on or about December 31, 1984. All work was completed on January 18, 1985.
The inspectors reviewed the work performed and confirmed that it agreed with the licensee's submittal and with the intent of this item. No further actions are required.
k.
Review of Routine and Special Reports The inspectors reviewed the monthly performance report for the months of June and July,1986. The inspectors also reviewed Quad Cities Unit 1 Cycle 9 Startup Test Report Summary for compliance with Technical Specifications.
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1.
Independent Inspection While in cold shutdown for maintenance on July 14, 1986, the Licensee at Palisades identified a problem with the weight used in the s31smic analysis for valve operators supplied by Limitorque.
A-rebuilt motor operator was procured as a replacement and was weighed to assure correct weight for seismic analysis purposes. The weight was found to be 260 pounds, while the vendor drawing listed it as 168 pounds.
Further ccnfusion was provided by Limitorque who stated that their valve operator (SMB-00) weighs 190 pounds.
Preliminary detailed seismic analysis showed the piping over stressed by about a factor of three.
The inspectors have determined that a similar condition could exist at Quad Cities.
The figures used for seismic analysis at this station are also derived from vendor supplied data and were not verified by weighing the actual valves.
The licensee is aware of
the potential problem and is reviewing options for action available to them.
This item will be tracked as an Unresolved Item (254/86013-02; 265/86012-01(DRP)).
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Regional Requests (1)
Information from Monticello indicated the possibility that under certain circumstances the Intermediate Range Monitor (IRM) trip function could be inoperable without that fact being
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annunciated. Trouble. shooting of these circuits revealed that the circuits appear to be normal and operable even when the 24 volt negative fuse is blown.
The licensee performed a special test, reviewed and observed by the resident inspectors, that showed if that fuse were blown two annunciators functioned to alert operators of a malfunction
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in the IRM circuitry.
(2) During testing of Standby Liquid Control (SBLC) System at Monticello, the pump motor tripped after running several minutes.
Investigation revealed a blown fuse in the control power transformer circuitry.
The fuse size and blow characteristics were not correct for the application.
This problem was originally brought to light in IE Circular 77-09.
A review of Quad Cities response to this Circular and a review of the pertinent SBLG System electrical prints confirmed that this problem does not exist at this station.
(3) Analysis of an event that occurred at LaSalle 2 on June 1, 1986, revealed that Static "0" Ring Differential pressure switches exhibited erratic behavior during that event.
The problem with Model 102 and 103 switches is setpoint drift.
Each switch has unique characteristics and switches with the same model number do not all behave the same way.
Investigations at this site revealed that no Model 102 or 103 switches are in use. A low pressure switch (Model 12N-AAS-PP)
is used in some Safety Related applications.
It was determined by a review of the calibration data that setpoint drift was not a problem.
n.
Fire Protection-The inspectors reviewed the licensee's implementation of fire watch requirements. Technical Specifications Section 3.12/4.12 requires that fire watches be established under certain conditions (e.g.
inoperable detectors, etc.). Guidance for fire watches were in place in the licensee's Quality Assurance program, however, no station implementing procedures existed. The licensee has agreed to correct this oversight. This issue will be tracked as an Open Item (254/86013-03; 265/86012-02(DRP)).
o.
Headquarters Request A Temporary Instruction was issued by Headquarters giving guidance for the inspection of Limitorque motor valve operator internal wiring. The inspector determined that 122 10CFR50.49 designated Limitorque valve operators are in use at the site. A review was conducted of the licensee's documentation for the qualification of
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the installed wires. A sampling of the work requests showed that qualified wire was installed in the operators (Rockbestos Firewall i
Type SIS 600V 14 gauge wire). A physical inspection of four Limitorque operators on each unit confirmed the qualified wiring was present.
2.
Open Items Open items are matters which have been discussed with the licensee, which will be reviewed furt;ier by the inspectors, and which involve some action on the part of the NRC or licensee or both. The open items disclosed during the inspection are discussed in Paragraph 1.n.
3.
Unresolved Items
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Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, items of noncompliance, or deviations. Unresolved items disclosed during the inspection are discussed in Paragraph 1.1.
4.
Exit Interview
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The inspectors met with licensee representatives (denoted in Paragraph 1)
throughout the inspection period and at the conclusion of the inspection on August 11, 1986, and summarized the scope and findings of the inspection activities.
The inspectors also discussed the likely informational content of the inspection report with regard to documents or processes reviewed by the inspectors during the inspection.
The licensee did not identify any such documents / processes as proprietary.
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