IR 05000219/1981011
| ML20009B808 | |
| Person / Time | |
|---|---|
| Site: | Oyster Creek |
| Issue date: | 06/30/1981 |
| From: | Briggs L, Greenman E, John Thomas NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20009B797 | List: |
| References | |
| 50-219-81-11, NUDOCS 8107170188 | |
| Download: ML20009B808 (15) | |
Text
50219-810522
.50219-810528.
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U.S. NUCLEAR REGULATORY COMMISSION OFFICE OF INSPECTION AND ENFORCEMENT Region I
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Report No.
50-219/81-11 Docket No.
50-219 License No. DPR-16 Priority Category C
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Licensee:
Jersey Central Power and Light Company Madison Avenue at Punch Bowl Road Morristown, New Jersey Oyster Creek Nuclear Generating Station Facility Name:
Inspection at:
Forked River, New Jersey Inspection conducted 4 May 1 - 31,1981 A bm cli'7 /sr Inspectors:
dats signed A. Thomas, Resident Reactor Inspector AE8 4 L /wk/
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L. E. Brig ( W Project Inspector
'date sicjned n
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datesjgned
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du om Approved by:
u x-es E'. ' G'.' Greenma n, C h f, Reactor date signed Projects Section 2 Inspection Summary:
l Inspection on May 1 - 31, 1981 (Report No. 50-219/81-11)
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Areas Inspected:
Routine inspection by the resident inspector (103 hours0.00119 days <br />0.0286 hours <br />1.703042e-4 weeks <br />3.91915e-5 months <br />) of:
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licensee action on previous inspection findings, tours of the facility, log and record review, followup of onsite events, in-office LER review, on-site LER followup, and review of periodic reports.
Results:
Noncompliance - None in 6 areas, one in one area (failure to adhere to i
ecuipment control procedural requirements in controlling electrical jumpers -
detail 3.b(8)).
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8107170188 810701
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PDR ADOCK 05000219 G
PDR Region I Form 12
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(Rev. April 77)
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DETAILS 1.
Persons Contacted T. Brownridge, Area Supervisor, M&C J. Carroll, Director, Oyster Creek Operations K. Fickeissen, Manager, Plant Engineering M. Laggart, Supervisor, Licensing W. Popow, Director M&C, Oyster Creek A. Rone, Engineering Manager W. Stewart, Plant Operations Manager J. Sullivan, Manager, Operre'ons D. Turner, Radiological Con ^. ois Manager The inspectors also interviewed other licensee personnel during the course of the inspection including management, clerical, maintenance, and operations personnel.
2.
Licensee Action on Previous Inspection _Findinos (0 pen)
Inspector Follow Item (219/77-25-02):
Adequacy of control room multipoint recorders.
The inspector discussed this item with members of the plant engineering staff and learned that the licensee intends to place all data currently input to the multipoint recorders on a new computer system. The computer s'ystem will have the capability of trending and storing the data now printed on the multipoint recorders. The installation of the computer system will be a phased operation with the first phase to be completed during the 1981 refueling outage.
This system will eliminate the multipoint recorders.
This item will be examined in a subsequent inspection following installation of the computer system.
(Closed)
Inspector Follow Item (219/79-14-01):
Verify breaker alarm installation completed for auto-op safeguards breakers per LER 78-10/1T and Engineering Task 325-78. The inspector reviewed Job Order 1181E (QASL 2597)
completed May 6,1980, and Special Procedure 79-16, revision 0, dated May 11,1979, "4160 Volt Switchgear Breaker Permissive Indication Modifications."
The inspector verified that control alarms have been installed for all automatically operated 4160 volt safeguard breakers as committed in Licensee Event Report number 78-10/lT.
An annunciator will alarm in the control room if the key locked permissive switch is not closed for Emergency Service Water Pump breakers, the Core Spray Pump breakers, or 4160 volt bus breakers SlA or S1B.
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(Closed)
Inspector Follow Item (219/79-14-02):
Verify reactor building to torus vacuum breaker r.alenoids replaced by ASCO Nuclear Grade per LER 79-09/3L. The ingactor reviewed job order number 2583E (QASL 3149), completed July 17, 1980, and verified that the solenoids on valves V-26-16 and V-26-18, reactor building to torus vacuum breakers, were replaced with nuclear grade valves. The inspector reviewed the Environmental Qualification of Safety Related Electrical Equipment Report, dated October 31, 1980 and determined that the solenoids on valves V-26-16 and V-26-18 are listed as ASCO Model NP8344A70E, a nuclear grade valve.
(0 pen) lJnresolved Item (219/79-21-01):
Replace CRD flow control valves and replace drive pressure instrument. The inspector reviewed the follcwing documentation associated with task number 80.54 for the replacement and calibration of the drive pr3ssJre transmitter:
Engineering Specification 380-79-1, " Installation of Rosemont
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Series 1153 DA8 transmitter."
Special Procedure 80-39, revision 0, dated April 28, 1980,
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" Replacement of RD04 Differential Pressure Transmitter."
Job Order 2892I (QASL 3604), " Replace defective transmitter RD04
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with 3 Rosemont Transmitter", completed May 9,1980.
Job Order 6119M (QASL 3609), " Weld procedure WPS 37.2",
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completed May 7,1980.
The inspector determined that the control rod drive pressure transmitter and the control room indicator have been replaced and now provide accurate control red drive pressure indication in the control room with adequate correlation existing between the local and control room indicators.
In addition, the inspector reviewed job order records pertaining to control rod drive system valves and could find no records indicating replacement or rebuilding of the flow control valves (NC-30A and NC-308). A licensee l.
representative stated that an engineering evaluation is being performed to determine the feasibility of replacing these valves during the 1981 refueling outage.
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This item will remain open pending replacement of the control rod drive flow control valves.
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(Closed)
Item of Noncompliance (219/81-03-01):
Failure to issue dosimetry or sign the dosimetry exception log. The inspector reviewed the licensee's corrective actions as stated in his letter to NRC:R1,
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dated May 29, 1981.
The inspector verified that the " Dosimetry Exception Log" had been deleted by a revision to procedure 903.2,
" Personnel Dosimetry."
In addition, a sign has been mounted at the security badge issue counter giving notice that personnel are not permitted to enter the radiation control areas without dosimetry. The visitors sign-in log has been revised to include a statement that the visitor acknowledges awareness of the dosimetry requirements.
3.
Plant Tours During the course of the inspection, frequent tours were conducted a.
in the following areas:
Augmented Off-Gas Building;
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New Rad-Waste Building;
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Cooling Water Intake and Dilution Plant Structure;
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Monitoring Change Areas; 4160 Volt Switchgear, 460 Volt Switchgear, and Cable Spreading
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Rooms; Diesel Generator Building;
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Maintenance Work Areas; and,
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Yard Areas.
In addition, tours of the control room were conducted at least once per day when the inspector was on site. Tours of the reactor building and turbine building were conducted at least four times a week.
b.
The following determinations were made:
(1) Monitoring instrumentatior.-
All control room panels were examined to verify that required instrumentation was functional, that proper correlation between instrument channels existed, and that indicated parameters were within Technical Specification limits.
Control room indications were examined to verify that system alignments and availability complied with Technical Specification Limiting Conditions for Operation.
Local plant
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instrumentation was selectively examined to verify instrument operability and correlation between channels. During the maintenance outage that occurred during this inspection, Core Spray System High Drywell Pressure Sensor RV46B was removed for analysis as part of an engineering evaluation of set point drift on ITT Barton snap action switches. Performance of this evaluation was a licensee comittment made to NRC:R1, following an inspection in which snap action switch set point drift was discussed at Jersey Central Power and Light Company corporate offices in March 1981.
The inspector verified that the licensee adhered to the core spray system " reduced system availability" requirements of Technical Specification 3.4.A while the sensor i
was removed.
(2)
Control room annunciators and alarms: Lit control room annunciators were reviewed with operators r.nd shift supervisors to u ify that the reasons for the alarmed conditions were understood and that corrective action, if required, was being taken.
(3) Plant housekeeping conditions:
General cleahliness, material storage, and control of materials to prevent fire hazards were ex mined for conformance to licensee administrative procedure lli " Housekeeping", and procedure 120, " Fire Hazards". The inspector noted a deterioration in the housekeeping conditions
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on the reactor building 23 foot elevation due to the drywell maintenance in progress during the outage. However, conditions are better than those observed during previous outages.
The inspector also noted that the interiors of breaker enclosures on some of the motor control centers on the 23 foot elevation have become radioactively contaminated, requiring the use of protective clothina when racking out breakers for maintenance.
This was discussed'with the Radiological Controls Manager who stated that attempts would be made to decontaminate the breaker enclosures during the 1981 refueling outage when the motor control centers can be deenergized.
(4)
Fluid leaks and system integrity:
Systems and equipment in the areas toured were examined for evidence of fluid leaks and abnormal piping vibration.
(5) Radiation Controls: The inspector made observations to verify that control point procedures and posting requirements were being followed.
Personnel were observed to verify that dosimetry was worn when required. Work in radiation controlled areas was observed for adherence to licensee procedures and for compliance with the requirements of applicable radiation work permits.
(6)
During tours of the facility, valves and components in safety related systems were checked to verify proper system alignment.
Selected valve positions were checked in the core spray and
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containment spray systems, standby liquid control system, and I
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control rod drive hydraulic systen All breakers in the 4160 volt switch gear room and selected breakers in the 460 volt switch gear room were verified for proper alignment.
(7)
During tours of the facility, selected active equipment tagging requests were examined to verify that the tags were in place on the proper equipment and that tagged valves and breakers v:ere in the positions specified. Portions of the following tagging requests were verified:
78-948 dated November 3, 1978, 125 VDC Battery Static Charger
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79-94 dated.'anuary 29, 1979, Spare Exciter
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80-916 dated June 6,1980,
"A" Cleanup System Pump
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81-246 dated March 17,1981, "B" Shatdown Cooling Pump
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81-597 dated May 13, 1981, Breathing Air System
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81-706 dated May 29,1981, "A" CRD Filter No discrepancies were found.
(8)
During tours of the facility, selected electrical jumpers were examined to determine if the jumpers were in place on the proper terminals in the proper electrical panels. The following jumpers were examined:
Check Off Sheet 77-37 dated January ll,1977, Jumper 3 on
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3F-TB1-3 and 3F-TB1-4 to jumper out a Nitrogen Pakeup High Flow Alarm.
Check Off Sheet 78-110 dated June 14, 1978, Jumper 52 in
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USS 182 to jumper out the suction pressure and temperature trip relay on pump NUO2C ('C' Shutdown Cooling Pump).
Check Off Sheet 79-151 dated January 12, 1979, Jumper 60
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on terminals 187 and 189 in the condensate demineralizer panel to bypass the low water flow trip on the caustic pump.
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Check Off Sheet 79-157 dated March 21, 1979, Jumper 6 on 4F-TB27-9 and 4F-TB27-12 to defeat the low suction pressure trip on the 'A' Control Rod Drive Hydraulic Pump.
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Check Off Sheet 79-190 dated August 7,1979, Jumper 18 on
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7F-TB2-50 and 7F-TB2-51 to bypass the vapor extractor low discharge pressure alarm.
Check Off Sheet 80-290 dated August 1,1980, Jumper 21 in
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USS 1A2 and Jumper 22 in USS 182 to bypass the suction temperature trip on pumps NUO2A and NUO2B ('A' and 'B'
Shutdoum Cooling Pumps)
Check Off Sheet 80-291 dated August 11, 1980, Jumper 13 in
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panel 13R to silence a faulty turbine thrust bearing metal temperature alarm.
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Check Off Sheet 81-338 dated March 3,1981, Jumper 34 on 7F-TB6-34 and 7F-TB1-52 to defeat steem gland exhauster 1-2 clarm circuit.
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Check Off Sheet 81-342 dated April 24, 1981, Jumper 74 on 7F-TB18-35 and 7F-TB18-38 and Jumper 75 on 7F-TB17-36 and 7F-TB17-48, to allow operation of the turning gear and lift pumps while performing 230 KV ACB line modifications.
During the inspection of the above electrical jumpers, the inspector found jumper number 60 bypassing the low water flow trip of the caustic pump (Check Off Sheet 79-151) disconnected from terminal 187 in the condensate demineralizer panel, and jumper number 75 allowing operation of the turning gear and lift pumps during 230 KV ACB line modifications (Check Off Sheet 81-342) disconnected from terminal 7F-TB17-48.
In addition, the inspector found jumper number 14 installed on terminals 7F-TB1-176 and 7F-TB1-184 to jumper the main flash tank high level alarm. There was no documentation in the jumper log or defeated alarm log on jumper 14.
These three discrepancies in the jumper control program constitute an item of noncompliance (219/81-11-01).
These three items were promptly identified to licensee management.
The licensee reviewed the maintenance work in progress and deter-mined that jumpers 60 and 75 were still required and they were reattached to the proper terminals. Jumper 14 was determined to be not required and was removed.
During the above review, the inspector determined that when electrical jumpers are installed in accordance with approved maintenance or modification procedures, a controlled and numbered jumper may be used without logging the jumper in the jumper control log in accordance with procedure 108, " Equipment Control."
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The inspector expressed concern that this practice prevents the operations department from adequately controlling and auditing the jumper control system. The licensee acknowledged the inspectors concern and ccmmitted to review the adequacy of the jumper control program, by June 30, 1981. This item is unresolved pending licensee and NRC review of the jumper control program (219/81-11-02).
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(9)
Security: The inspector verified that security posts were manned and that personnel and vehicle searches were conducted as rer.uired.
Vital areas were periodically checked to insure that they were locked or guarded and that positive control of access was exercised.
(10) By frequent observations during the inspection, the inspector verified that control room manning requirements of 10CFR 50.54(k)
and Technical Specifications were being met.
In addition, the inspector observed shift turnovers to verify that continuity of system status was maintained.
c.
The following acceptance criteria were used for the above items:
Technical Specifications;
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Procedure 106, Conduct of Operations; Procedure 108, Equipment Control;
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10CFR 50.54(k); and',
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Inspector judgment.
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4.
Shift Loos and Operatino Records a.
The inspector reviewed the following plant procedures to determine the licensee established requirements in this area in preparation for review of selected logs and records:
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Procedure 106, Conduct of Operations; Procedure 108, Equipment Control; and,
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Procedure 115, Standing Order Control.
The inspector had no questions in this area.
b.
Shift logs and operating records were reviewed to verify that:
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Control Room logs were filled out and signed:
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Equipment logs were filled out and signed;
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Log entries involving abnormal conditions provided sufficient
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detail to communicate equipment status; Shift turnover sheets were filled out, signed, and reviewed;
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Operating orders did not conflict with Technical Specification
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requirements; and, Logs and records were maintained in accordance with the
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procedures in a. above.
c.
The review included the following plant shift logs and operating records as indicated, and discussions with licensee personnel.
Reviews were conducted on an intermittent selective I; asis:
Centrol Room Log, all entries;
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Group Shift Supervisors Leg, all entries;
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Control Room Alarm Sheets;
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Control Rod Status 5heets;
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Technic cification Log;
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Reactor suxiliary Log;
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Reactor Log;
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Control Room Turnover Check List;
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Reactor Building Tour Sheets;
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Turbine Building Tour Sheets;
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Equipment Tagging Log;
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Lifted Lead and Jumper Loa;
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Defeated Alarm Log;
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Standing Orders, all active; and,
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Operational Memos and Directives, all active.
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d.
During reviews of the equipment tagging, lif'.ed lead and jumper, and defeated alarm log, the inspector noted several long standing entries indicative of a need for permanent modification, further follow up by the maintenance department, or parmanent procedure changes. Some examples are as follows:
Tagging Request 72-1 dated November 12, 1972.
A normal instrument
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root valve for sensors 1811A1 and 1BilA2 on RK03 was stuck in the open position. A new valve was installed in series with this valve and was tagged in the open position. The new valve has been included on the valve lineup procedures but the tag has never been cleared.
Tagging Request 75-380 dated May 19, 1975.
Valves V-1-20 and
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V-1-29, turbine light load valves, are no longer used so they were tagged shut and the breakers racked out. No permanent modifications have been initiated or procedural. precautions ir.stituted to remove the need for this tagging request.
Tagging Request 76-1657 dated March 8,1976. Valves V-20-12 and
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V-20-18, Core Spray Isclation Valves, are tagged open with the breakers and control switches off, and valves V-20-27 and V-20-26, Core Spray System Test Valves, are t**ged hut with the breakers off.
Valvos V-20-12 and V-20-18 are mote-.perated valves with position indication and control switches in the control room. Valves V-20-26 and V-20-27 are motor operated valves with position indication in the control room and local key lock operating switches. They perform no automatic safety functions and are locked in their normal operation positions. TPt positions of these valves and breakers are now controlled by operating and surveillance procedures but the tagging requests were never cleared.
Tagging Request 77-132 dated April 27, 1977. The electrical' leads
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to the sewage treatment foam spray pump are lifted because the pump was permanently removed. The modification did not include removal of the electrical wiring so that the tagging request could be cleared.
Tagging Eeouest 77-813 dated July 20, 1977. The service air valve to
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the radwaste filters is tagged shut with a notation that it may be opened to backwash filters. This valve is closed because s downstream valve, NV-97, leaks. No maintenance action has bee 6.
initiated to repair NV-97.
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Tagging Request 79-245 dated March 26, 1979. The sewage
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treatment system sand filter pumps were removed from service for maintenance. Maintenance action has not yet been completed.
Tagging Request 79-630 dated August 6, 1979.
The sewage
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treatment system sand filter was tagged out for replacement.
Replacement has not been completed.
Electrical Jumper Sumary Sheets78-110 dated June 14,1978,
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and 80-290 dated August 1, 1980. These jumpers bypassed the low suction pressure trips on the Shutdown Cooling (SDC) pumps.
Due to the location of the suction pressure sensors, the starting surge that results from starting a second SDC pump causes spurious low suction pressure trips of the running pumps.
No action has been initiated to either modify the system to alleviate the condi-tion or te pemanently remove the low suction pressure trips if not required. The inspector detemined that cavitation is not likely since pump suction head is approximately 47 feet of water during operation.
The low suction trip point of the disabled switch was 4 psig (approximately 10 feet of water).
Electrical Jumper Sumary Sheet 77-37 dated January 11, 1977.
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This jumpers out a Nitrogen Makeup High Flow Alam which is no longer used.
No pemanent wiring changes have been made to per-manently remove the alarm circuit.
The inspector discussed the above examples with the licensee management and expressed concern that there is apparently inadequate followup and correction of such system dificiencies which are not of immediate safety concern. The licensee committed to assign a member of the plant staff to review and evaluate all active tagging requests, lifted leads and jumpers, and defeated alams; to clear those that are no longer necessary; to initiate maintenance for those requiring repairs; to submit engineering requests for those requiring further evaluation or system modificaticn; and that this raview and evaluation will be com-pleted by June 30,1981.
This item will be reviewed in a subsequent inspection (219/81-11-05).
5.
Follow-up Of On-site Events a.
On May 22, 1981 at about 2:00 p.m., a spill of contaminated water from the feedwater system occurred while filling and venting the "A" feed-water heater string. The water spilled in the feedwater heater bay and leaked through the floor to the feedpump room. The water
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spilled from an open drain valve on the "A" feed regulating valve and an open sample valve on the 'lA3' heater vent line. The inspector reviewed a ccmpleted valve lineup check sheet on the feedwater heater system and found that these valves cre required to be shut for system operating but were noted and verified to be tagged open when the valve lineup was conducted. The tagging request was subsequently cleared on May 15, 1981. The inspector reviewed the documentation associated with the tagging request and determined that the valves had been left open when the tags were cleared. The documentation showed that the valves were left open and this position was independently verified as re.uired by procedure 108, " Equipment Control." Discussions with operations department personnel revealed that when valve lineup checks find valves out of position ~due to system tagging requests this fact is noted on the check sheet and clearance of the tagging request is relied upon to restore the valve to its proper position. There is no mechanism to review the tagging documentation to ensure that the documented position of a valve after tag removal conforms to the position specified on the valve lineup check sheet. Also, there is no mechanism of documenting the evaluation and correction of discrepancies noted on valve lineup check sheets. The inspector noted that this event was not the result of procedural violations. It resulted from procedural inadequacies that allow insufficient followup and resolution of discrepancies. These inadequacies in the valve lineup procedures were discussed with licensee management. The licensee acknowledged the inspectors concern and stated that the valve lineup procedures would be evaluated and revised if necessary to assure adequate review and correction of discrepancies. This review will be completed by June 30, 1981. This : item is unresolved pending further review by the licensee and the NRC (219/81-11-04).
b.
During the inspection, the inspector was approached by two contractor employees who had been involved in maintenance on limitorque valve operators under job number C-92. The job involved replacement of the operators on valves V-5-148 and V-5-166 in the RBCCW system, valve V-16-1 in the RWCU system, valves V-17-19 and V-17-54 in the SD Cooling system, and valves V-14-36 and V-14-37 in the Iso-Cendenser system with environmentally qualified limitorque operators. The individuals stated that difficulty had been encountered in threading the new vhlve o,nerator's stem nuts onto the valve stems and that improper modifications had been made to the stem nuts to achieve a good fit. The inspec'or discussed the scope cf this job with the Director M&C, the M&C area supervisor, and the contractor's jeb supervisor to determina what problems had been encountered and how
.those problems had been resolved. The licensee representatives acknowledged that a good fit could not be achieved between the new i
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valve operator's stem nuts and the valve stems. The valve operators had been manufactured by Limitorque Corporation, but the stem nuts had been machined by Anchor Valve Company to insure a proper fit on the Anchor Valve valve stems. However, since the stems on the installed valves had been individually manufactured rather than being cut on a single die, a good match could not be achieved without taking direct measurements from the stems. The inspector reviewed a memo.to the Director M&C from the project engineer dated May 18,1981. The meno stated that an engineering review of the problem had been done and that based on discussions with the Limitorque Corporation representatives, an acceptable solution to the improper fit of the stem nut to the stem Wds to use the old stem nuts from the valve operators that were being removed. Since the reason for the replacement of the valve operators was to achieve acceptable environmental qualification of the operators electrical components, using the old stem nuts would not compromise the job's intent. The old stem nuts were removed and installed in the new valve operators for valves V-5-148, V-5-166, V-16-1, V-17-19, and V-17-54.
The old stem nut was also used on valve V-14-37, however, the threads were damaged when the nut was removed and required machining to repair.
The inspector reviewed Job Order 1341V (QASL 4668) and determined that about 3/16 inch of damaged thread had been removed from the nut.
This left a thread engagement of 2-15/16 inches which meets the minimum specified thread lenght of 2.35 inches (two stem diameters) specified by the Limitorque Corporation representative. The stem nut for valve V-14-36 was also damaged during remo/a1 and could not be repai ed. The new stem nut that was received witn the valve operator was internally threaded through its entire length of 8k inches and could not be installed on the valve stem due to a slight bow in the stem. Anchor Valve Company Drawing 2085-5, Revision
'C', shows the stem nut to have a threaded length of 3 3/4 inches with the remaining 4h inches relieved. The licensee relieved about 4h inches of the threads and achieved a satisfactory fit.
Based on the present review of job C-92, no items of noncompliance were identified. However, all of the doc.umentation associated with this job had not yet been completed and filed. The inspector will conduct another review of the completed job package in a subsequent inspectMn to insure that the completed document, tion accurately ref^ ects the work that was done (219/81-11-05).
j c.
At 4:48 p.m. on May 28, 1981, a reactor low level scram occurred while conducting turbine warmup. The following secuence of events occurred:
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The reactor had been started up and pressure raised to 1600
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psig and turbine warmup comenced. The reactor was then taken subcritical to perform a drywell inspection, and recirculation flow was increased to minimize the cooldown rate.
Upon completion of the drywell inspection, reactor pressure had
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decreased to about 450 psig. The control room operator reduced recirculation flow in p-eparation for control rod withdrawal.
However, the operator had allowed reactor water level, which was being manually controlled, to drift high in the operating range, and the increase in annulus level that occurred when recirculation flow was reduced resulted in a high water level trip of the turbine.
During turbine warmup, the internal bypass on number 2 turbine
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stop valve was open, the control valves were throttled using the load limit setting, and the bypass opening jack was run up to 40 percent. When the turbine tripped, the nine bypass valves opened fully, resulting in a rapid depress'urization of the reactor. When saturation pressure wcs reached in the re-circulation loops, the recirculation pumps lost suction and fiow stopped.
The control room operator quickly shut the bypass valves with
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the opening jack stopping the depressurization of the reactor.
As pressure began increasing, the^ recirculation pumps regained suction. The sudden increase in recirculation flow caused a drop in annulus water level and the reactor scrammed.
The reactor scramed at a level of 51 inches indicated by inches above the top of the YARWAY level instrument (11 feet :2 active fuel).
Reactor water level dropped to 11 feet 4 inches above the top cf the active fuel.
At 4:51 p.m., reactor water level was restored to a normal
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level of about 14 feet above the top of the active fuel, the scram was reset, and the event terminated.
The inspector reviewed this event with on shift Group Shift Supervisor and Shift Technical Advisor and determined that the root cause of the event was operator error in allowing water level to go too high. All reactor systems functioned as expected during this transient.
No items of noncompliance were identified.
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6.
In Office Review of Licensee Event Reports (LER's)
The inspector reviewed LER's received in the NRC:RI and Resident Office to verify that details of the event were clearly reported including the accuracy of the description of cause and adequacy of corrective action.
The inspector also determined whether further information was required from the licensee, whether generic implications were involved, and whether the event warranted on-site followup. The following LER's were reviewed:
LER EVENT 50-219/81-08/3L Water seeped through west wall of New Rad-Waste
building following flooding of chemical waste collecting tank vaults.
50-219/81-09/3L Hydraulic snubber 23/3 found leaking oil and
failed subsequent test.
50-219/81-10/3L Main Steam Line High Radiation monitor RN06B tripped at a value higher than specified.
50-219/81-11/3L Isolation Condenser pipe break sensor 1BilB2 tripped at a value higher than specified.
50-219/81-12/3L EMRV high pressure sens :rs lA83C and 1A83E set points exceeded technical specification limit.
50-219/81-13/3L Core Spray System high drywell pressure sensor RV46B tripped at value higher than specified.
No unacceptable conditions were identified.
7.
On-Site Licensee Event Follow-up_
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l For those LER's selected for on-site followup, the inspector verified that reporting requirements of Technical Specifications and Regulatory Guide 1.16 hao been met, that appropriate corrective action had been taken, that the event was reviewed by the licensee as required by facility procedures,
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and that continued operation of the facility was conducted in accordance with Technical Specification limits. The LER's selected for on-site follow-up are denoted by an asterisk (*) in detail 6. above. The following specific observations were made and discussed with licensee management:
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'81-08 The details of this event were reviewed and documented in NRC inspection 219/81-03 conducted February 2-28, 1981.
81 -09 The details of this event were revieweo and documented in NRC inspection 219/81-03 conducted February 2-28, 1981.
The inspector had no further questions on these items.
8.
Review of Periodic and Special Reports Upon receipt, periodic and special reports submitted by the licensee pursuant to Technical Specification 6.9.1 were reviewed by the inspector.
This review included the following considerations: the report includes the information required to be reported to the NRC: planned corrective actions are adequate for resolution of identified problems; and that the reported information is valid. Within the scope of the above, the following periodic reports were reviewed by the inspector.
April,1981 Monthly Operating Data Report
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9.
Unresolved Items Unresolved items are mattersabout which more information is required in order to ascertain whether they are acceptable items, items of noncompliance, or deviations. The unresolved items identified during this inspection are discussed in paragraphs 3.b.(8) and 5.a.
10.
Exit Interview At periodic intervals during the course of this inspection, meetings were held with senior facility management to discuss inspection scope and findings.
Discussions with station management relative to the status of resident inspection efforts were held on May 5, 11, 15, 18, 21, 22, 27 and l
June 1,1981.
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