IR 05000271/1981019
| ML20039E421 | |
| Person / Time | |
|---|---|
| Site: | Vermont Yankee File:NorthStar Vermont Yankee icon.png |
| Issue date: | 12/17/1981 |
| From: | Collins S, Galla R, Gallo R, Raymond W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20039E419 | List: |
| References | |
| TASK-1.C.1, TASK-2.B.1, TASK-2.B.2, TASK-2.B.3, TASK-2.F.2, TASK-2.K.3.13, TASK-2.K.3.15, TASK-2.K.3.22, TASK-2.K.3.27, TASK-TM 50-271-81-19, IEC-79-05, IEC-79-5, NUDOCS 8201070271 | |
| Download: ML20039E421 (25) | |
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U.S. NUCLEAR REGULATORY COMMISSION OFFICE OF INSPECTION AND ENFORCEMENT Region I Report No. 81-19 Docket No.
50-271 License No. DPR-28 Priority Category C
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Licensee:
Vermont Yankee Nuclear Power Corporation 1671 Worcester Road
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Framingham, Massachusetts 01701 Facility Name:
Vermont Yankee Inspection at:
Vernon, Vennont Inspection conducted:
November 3-30, 1981 Inspectors: Afn/hn3 fn1 8%)llle f W.' J. Raym6nd, Senior Resident Inspector-date signed SW l1\\lllbf S. 'J. Collins, Resident Inspector date signed date signed Approved by:
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R. M. Gallo, Chief, Reactor Projects-date 51gned Section IA, Projects Branch #1
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Inspection Summary:
Inspection on November 3-30, 1981 (Report No. 50-271/81-19)
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Areas Inpsected: Routine announced inspection'-on regular and backshifts by Resident
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Inspectors of: action taken on previous inspection findings; IE Circular followup;
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review of shift logs and operating records; plant' tours; review of radioactive waste system controls; followup of refueling activities; observations of physical security; surveillance testing; refueling outage maintenance activities; review of plant-opera-l tions; inspector actions based on a review of the status of licensee implementation l-of.NUREG 0737 requirements; and, inspector actions based on. Region initiated inspection
requests. The inspection involved 145 inspector hours onsite by two resident inspectors.
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Results: Of the twelve areas inspected, no items of noncompliance were identified.
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Region I Form 12
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PDR-l (Rev. April 77)
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W DETAILS
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Persons Contacted The below listed-technical and supervisory level personnel were among those contacted:
Vermont Yankee Nuclear' Power Corporation
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-Mr. D.-Allen, Reactor Engineer Assistant-Mr. L. Anson, Plant Training Supervisor Mr. E.' Bowles, Training Supervisor
Mr. R. Branch, Operations Supervisor Mr. F. Burger, Quality Assurance Coordinator
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Mr.-B. Buteau, Reactor Engineering and Computer Supervisor Mr. P. Donnelly, Instrument and Control Supervisor
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Mr. R. Kenny, Engineer, Assessment Coordinator Mr. D. Girroir, Mechanical Engineer Mr. L.'Goldthwaite, Instrument and Control Foreman Mr. S.' Jefferson, Technical Services-Superintendent Mr. B. Leach, Health Physicist n
Mr. M. Lyster, Operations Superintendent i
- Hr. W. Murphy, Plant Manager Mr. J. Pelletier, Assistant Plant Manager Mr. D. Reid, Engineering Support Supervisor Mr. S. Vekasy Senior Systems Engineer-
- denotes those present at management meetings held periodically during-the inspection.
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Action Taken on Previous Inspection Findings a.
.(Closed) Unresolved Item (50-271/80-04-02): Torus Level Indication -
Power Supply. Torus wide range level instruments were installed during the 1980 refueling outage per EDCR 79-57 Post-Accident Monitor Torus Level and Drywell Pressure. The inspector noted by review of VY Drawing B191301, Sheet 1232 that LT 16-19-10A is powered from 120 volt Instrument AC and LT 16-19-10B is powered from 120 volt Vital AC, thus assuring at least one channel of torus ' level indication is available, assuming the failure of the~most limiting instrument power supply.
Power supply for Condensate Storage Tank levelLindication is accepta-ble. This item is closed.
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(Closed) Followup Item (50-271/80-06-01): -Requalification Program Conformance with March 28;:1980 NRC Requirements. 'AP 0711, Licensed Operator Retraining, Original, dated July 24, 1981, now contains written instructions covering situations wherein~a licensed operator doessnot attain a grade of 80% overall or 70% in any section:in the annual requalification exam. The Training Department will provide written notification to the individual and the Operations Supervisor that the individual shall be removed from licensed duties pending satis-1 factory completion of an accelerated retraining. program. A ~second
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notification will be sent to the individual and the Operations Supervisor to allow resumption of licensed duties upon completion of the accelerated training. This item is closed, c.
(Closed) Followup Item (50-271/80-17-03):
Inspection of Refueling Platform Cable and Grapple Checks. Plant procedures were changed to eliminate conflictirg inspection requirements. AP 1000, Refueling, Revision 8 (DI 81-9) requires grapple and cable inspection be conducted daily and that the results be logged in the Control Room Log. All grapple and cable inspection requirements were deleted from OP 1100, Revision 10 and OP 1410, Revision 10. This item is closed.
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(Cpen) Unresolved Item (50-271/80-18-01): Perfonnance data for Typical H Configuration Penetration Seals. The licensee has con-tracted Chemtrol Corporation to conduct an ASTM E-119 test on the Typical H Type penetration at the Portland Cement Company (Skokie, Illinois). The schedule for conducting the test is as follows:
11/27: assemble materials required for testing and ship to
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test facility; 12/7-12/11: finalize test procedures and assemble test pad;
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12/14-12/18: conduct test at test facility; and,
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1/1/82: test report due at Vermont Yankee.
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The inspector noted that VY will provide a copy of the test procedure to American Nuclear Insurers for review and a msnber of the VY staff will witness the test. The licensee provided a copy of the test pro-cedure for NRC staff review. This item remains open pending comple-tion of the test, submittal of the test results to the NRC and NRC staff review of the test results.
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(Closed)UnresolvedItem(50-271/80-18-02): Adequacy of GE RTV 6428 Seal Material. Test results on two cured samples of RTV 6428 Penetrant Sealant were reported by letter dated March 13, 1981. One sample was obtained from the CR-8000 test of October 27, 1980. Analysis of its constituents showed indications of improper preparation such that the material would not perform properly, the test was considered invalid.
A second sample was removed from a penetration installation at Vermont Yankee. Analysis of its properties showed proper color, oxygen index and specific gravity.
Based on the above, and a review of the March 13, 1981 test report by NRC Region I and NRC:NRR staffs, use of RTV 6428 as a penetration sealant is considered acceptable. Further evaluation of the VY penetrations will be accomplished through per-formance testing (see Item 80-18-01 in paragraph 2.d.).
This item is closed.
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(Closed) Noncompliance (50-271/80-19-01): Unapproved Valve Lineup and Documentation of Changes. Corrective actions specified in VY letter FVY 81-42 dated March 16, 1981 and NRC letter date May 14, 1981, were reviewed and found complete. The inspector reviewed the November 1980 routing list of procedures with pending revisions, along with the valve lineup index for procedures referenced by Inspection Report 80-19. This review showed that all procedures referenced by Report 80-19 were reviewed by the PORC and approved by the Operations Supervisor and the Plant Superintendent. Only Manager of Operations approval was missing. Management policy prohibiting the use of advanced working copies of procedures was transmitted to all Station Department Heads, and station personnel have been trained in accordance with its instructions.
AP 0155, Valve Identification and Current Valve Lineup Book, was changed by Revision 7 on August 19, 1981, to incorporate require-ments specified in VY's March 16, 1981 letter. The requirements of former procedure AP 0156 were incorporated in AP 0155 as well.
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AP 0155 now limits exceptions to valve positions to those that must be different as dictated by system status. A procedure change must be processed for those valves that must be added or deleted from j
the lineup listing.
This item is closed.
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(Closed) Noncompliance (50-271/80-19-02): Adherence to AP 0156 Requirements and Procedure Categories. Corrective actions specified in letter FVY 81-42 dated March 16, 1981, were reviewed and found complete. Revision 7 to AP 0155 requires the shift supervisor to review, annotate and initial each line item change to a valve lineup check off list. Plant personnel were trained on the new requirements, I
which became effective September 1, 1981. The inspector reviewed the status of valve check off lists available and in use in the control room on November 20, 1981, for startup from the 1981 Refueling Outage.
Of the 16 check off lists in use, all were found with revision numbers that matched the corresponding Operating Procedures. Valve lineups for 10 of the 16 check off lists were still in progress. The 6 check off lists that were complete as of November 20, 1981, were reviewed in detail and were found completed in accordance with AP 0155 requireme7ts.
The inspector also noted the action taken by the licensee to review and re-categorize procedures, as necessary, to assure conformance with AP 0001 requirements. Department Procedures 1412, 2430, 2445 and 5334 were converted to Operating and/or Routine procedures, and reviewed by the PORC. The inspector also reviewed listings of plant procedures submitted by each Plant Department for conversion to proper AP 0001 categories. All procedures were updated by August 15, 1981.
This item is closed.
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(0 pen) Unresolved Item.(50-271/81-05-08):
Implementation of NUREG 0737 Item I.C.6.
Revision 5 of AP 0140 incorporated changes to clarify independent verification requirements for switching and tagging orders. Form VYAPF 0140.04 requires documentation of whether independent verification was invoked for each tagging order issued, along with the method used.
Incorporation of these requirements-into AP 0140 resolves the inspector's concerns as identified in paragraph 2.j.(3) of Inspection Report 50-271/81-15. The inspector reviewed the following tagging orders for conformance with AP 0140 requirements: 81-549,81-505, 81-525,81-567, 81-572,81-592, 81-625 and 81-649. No inadequacies were identified. Tagging Orders81-649, 81-592 and 81-625 were also reviewed for proper implementation and completion of retest requirements. No inadequacies were identified.
For.all orders reviewed above, either no independent verification was required or functional testing was an acceptable substitute.
The unresolved item remains open pending further NRC review of con-cernsidentifiedbyparagraphs2.j.(1)and2.J.(2)ofInspection Report 50-271/81-15.
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(Closed) Noncompliance (50-271/81-08-02): AP 0020 Requirements for Jumpers and Lifted Leads (J/LL). Corrective actions specified in letter FVY 81-136 dated September 15, 1981 were reviewed and found complete. Department Instruction (DI) 81-7 to AP 0020 clarified instructions and requirements for the installation and removal of jumpers, independent verification of jumper installation and re-moval is now required.
Request fonns 80-0083, 80-0035 and 81-0017 were updated to show appropriate dispositioning. Personnel were retrained on AP 0020 requirements. This item is closed.
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(Closed) Deviation (50-271/81-08-03): Compliance with Pass-Fail
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Criteria on Annual Requalification Exams. Corrective actions specified in letter FVY 81-136 dated September 15, 1981 and NRC: Region I Inspection Report 50-271/81-08 were reviewed and found complete. The new 80-70% grading criteria has been incor-porated into training procedure AP 0711, Licensed Operator Retrain-ing Original Revision dated July 24, 1981. This item'is closed, k.
(Closed) Noncompliance (50-271/81-08-13): Visitor Escorting. The inspector has noted during routine (daily) observations of plant activities that visitor escorting has been conducted in accordance with requirements of the Security Plan and the NRC's August 12, 1981 letter. This item is closed.
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3.
IE Circular Followup The following IE Circular was reviewed to detemine whether the actions listed below were taken by the licensee:
Corporate management forwarded the Circular to the facility for
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review; A review for applicability was perfomed; and
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Appropriate corrective actions have been taken or are scheduled
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to be taken by the licensee.
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IE Circular 79-05, Moisture Leakage in Stranded Wire Conductors, dated March 20, 1979 The inspector reviewed the status of actions taken in response to the IEC 79-05 File Meno dated July 18, 1979. These actions were discussed with the Instrument and Control Supervisor on November 10, 1981. No conditions of equipment configurations were identified wherein moisture leakage through stranded conductors would create a problem. No sensor transmitters are located inside the drywell.
Drywell atmosphere themocouples use solid wire conductors.
Stranded wire conductors used to feed the solenoid valve for the 4 ADS operators and the sample system valves have heat shrink tubing at the termination points. Stranded wire used in the conductors for the MSIV position switches are equalized to preclude development of a differential pressure that could cause moisture leakage. Licensee action on this item is complete.
This item is closed.
4.
Shift Logs and Operating Records a.
The inspector utilized the following plant procedures to determine the licensee established administrative requirements in this area in preparation for review of various logs and records.
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AP 0831, Plant Procedures, Revision 8, dated November 24, 1981 AP 0150, Responsibility and Authority of Operations Department
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Personnel, Revision 16, dated October 21, 1981
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AP 0153, Maintenance of Operations Department Logs, Revision 9, dated August 17, 1981 AP 0140, VY Local Control Switching Rules, Revision 5, dated
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October-16, 1981
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AP 0020, Lifted Lead / Installed Jumper Request Procedure,
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Revision 4, dated October 16, 1980-
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AP 0021, Maintenance Requests, Revision 9, dated September 25, 1980
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AP 0030, Plant Operations Review Committee, Revision 6, dated '
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January 7, 1980
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The above procedures, Technical Specifications, ANSI N18.7-1972
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" Quality Assurance Requirements for Nuclear Power Plants" and 10 CFR 50.59 were used by the inspector to detennine the accepta-
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bility of the logs and records reviewed.
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Shift logs and operating records were reviewed to verify that:
Control Room logs and surveillance sheets are properly
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completed and that selected Technical Specification limits were met.
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Control Rooti1 log entries involving abnonnal conditions pro-
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vide sufficient detail to concunicate equipment status, lockout status, correction and restoration.
Log Book reviews are being conducted by the staff.
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Operating and Special orders. do not conflict with Technical
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Specifications requirements.
Jumper (Bypass)1.ogdoesnotcontainbypassingdiscrepancies
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with Technical Specification requirements and that jumpers areproperlyfapprovedpriortoinstallation, c.
The following plant logs and operating records were reviewed periodically during the period of November 3-30, 1981:
Shift Supervisor's Control Room Log
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Night Order Book. Entries
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NSE Refueling Log
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Safety Related (taintenance Requests
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Control Room.0pegat'or Round Sheet
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Auxiliary Operator Rounds Sheet
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8 EquipmenthStatus Log
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Control Room Chemistry Log Sheets
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No items of noncompliance were: identified, d.
Certain items noted during reviews of' licensee logs and records.
required additional followup, as discussed below.-
(1) Flushing of the RHR Loop A piping was completed per'OP 2124 at 8:55 P.M. on November 3, 1981,.Following'this operation, a high radiation alarm was. received.at 9:20 P,M,-on~the service water effluent monitor, RAM 17-332, RAM 17-332 radiation level increased from a background level.of 4 cps to 55 cps, Plant operators res >onded to an assumed. tube _
leak in the A loop RHR heat exc1 anger by de)ressurizing the~RHR side of the heat exchanger at 9;30 ),M, Subsequent to this action, the high radiation alann cleared; howeyer..
analysis of RHR heat exchanger water were taken, ples and..
indication from RAM 17-332 remained erratic, Sam Initial analysis results reported to the control room at 9:40 P.M,.
showed activity in the water just into the MDA range ~ with a gross l gamma level of.5.S6XE-6 mci /ml, _A second set of samples were ordered, station management was notified.and I&C was requested to perform a functional check of the monitor.
Functional testing of RAM 17-332 was completed at 9:50 P,M,-
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and no electrical malfunctions were identified, Analysis results from a second set of samples were reported at 10:35 P.M. and showed no activity in the water,- Further investigation by the licensee and a third set of samples reported at 3:00 A.M.' onf Novanber 4,1981 could.not con-finn a leak in 'the heat exchanger, Contamination of the containers used forithe first set of samples was assunted to cause the initial positive activity results, Erratic indication from RAM 17-332 was attributed to an intrusion in the sample level.. Normal operations were resumed without incident.
The inspector i terviewed licensee personnel and reviewed n
radiation monitor traces, and the analysis results from.the RHR heat excbar.ger, and the.0P 2124 flush flow path, 'No indications of increased activity-in.the discharge canal effluent mon'tcr were observed, Following a period of erratic indication on November 3,.1981, RAM 17-332 ~showed normal ' background. levels.' No change in system status was-identified; that would account for negative results on the
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secand and third samples, assuming the first sample showing
't positive results was valid. No anomalous indications were
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h y subrequently observed on the effluent monitors.
g k lTheI nspector had no further questions on this item.
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(2) Curing operations to re-assemble the reactor vessel upper internals on Noverber 23, 1981, a " garlock" gasket becama detached from the. vessel service platfom at 8:40 A.M. and fell into the reactor. The gasket was subsequently retrieved, intact, gtsl:00 P W. and re-assembly operations resumed.
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The inspector had rio further comments on this item.
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L3) During prDarations to run In-Sequence Critical Testing on
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November 25, 1981, a break-down in communications occurred
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between control room personnel and a maintenance crew assigned to weld shut 4 roof hatch on the Reactor Building (RB). The
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maintenance crew-opened the hatch from 7:30 P.M. to 7:45 P.M.
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to instalPa strongback prior to welding the hatch closed.
Control room personnel first became aware of the condition
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at 9:35 P.M. when the maintenance crew requested a Fire
\\ Permit frca the STA to proceed with welding. The on-shift STA noted that openir,g the hatch would violate RB integrity,
'a condition not allowed with In-Sequence Critical testing in ordered all control rodservisor was notified, who in turn progress. The shift sup to be inserted and the mode switch
put to the SHUTDOWN position. Notifications were made to the
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NRC Duty Officer and licensee management. Operability testing
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e of the Standby Gas System was subsequently completed satisfactorily.
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Based on a review of the control room log, the inspector noted
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that local criticality checks per OP 4426 started at 8:41 P.M.
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and continued until 9:35 P.M.
Prior to 8:41 P.M., except for the mode switch positioned to startup, no activity was in
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. progress to (i) move a cask or irradiated fuel; (ii) increase reactor temperature above 2120F or (iii) take the reactor i
critical or otherwis'e reduce the shutdown margin. Thus,
'y secondary containment integrity was not required by Technical
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Specificatiori 3.7.C during the period when the RB hatch was opened.
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Licensee management' review of the event concluded that the
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breakdown of come.unications~on the requirements of AP 0025,
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Plant Equipment Coritrol, constituted a situation wherein personnel erroPcould have prevented the fulfillment of the
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functional requirements of the secondary containment, a
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system required to cope with accidents in the SAR. LER 50-271/81-33/IP was submitted on November 27, 1981 to meet the requirements of Technical Specification 6.7.C.1.f.
Members of the maintenance crew were counseled in regard to their actions.
This item is considered unresolved pending submission of the 14-day followup report to LER 81-33 and subsequent NRC review of licensee corrective actions (UNR 50-271/81-19-01).
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Operational Safety Verification During the period of November 16-19, 1981, the inspector conducted
l a review of the SLC system status following installation of the
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Standby Liquid Control Clean-up System per PAR No. 81-17 and con-duct of SLC system surveillance per OP 4114 and OP 5201. The re-
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view consisted of a _ complete walkdown of accessible portier.s of I
the system to confirm that the licensee's system lineup procedure, OP 2114, Standby Liquid Control System, Revision 9, DI #81-36, is consistent with plant Flow Diagram 191171, Revision 10, and the as-built configuration.
Inspector review identified the following:
SLC-11, ID tag broken off - not attached
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SLC-25, shown closed on print 191171, OP 2114 shows locked closed
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SLC-20, shown locked closed on print 191171, OP 2114 shows closed
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SLC-22, shown locked closed on print 191171, OP 2114 shows closed
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SLC-13B, shown locked open on print 191171, OP 2114 shows open
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SLC-448, print 191171 shows as downstream accum vent, is
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actually upstream valve SLC-12B, no ID tag
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SLC-13A, shown locked open on print 191171, OP 2114 shows open
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SLC-46A, -46B, no required position shown on print 191171, OP 2114
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shows open. OP 2114 description misleading, valves are actually in-line will allow either pump discharge pressure through sensing line. OP 2114 labels -46A as Pump 'A'
Disch. Press., and -46B as 'B' Discharge Pressure.
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SLC-18, not listed in OP 2114 as a (CRP 9-5) position
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verification SLC-478, print 191171 shows as upstream accum. vent, is actually
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downstream The following vent or drain valves are shown on print 191171 but not listed in OP 2114:
SLC-47A, -48A, -48C, -47B, -48D, -48B, and -46
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The pump controller for the Standby Liquid Control Cleanup
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System is not laLeled.
The Standby Liquid Control ion exchange vessel relief valve
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does not discharge into bem area.
The above items were identified to the Operations Supervisor for action on November 19, 1981. The inspector had no further coments.
5.
Plant Tour The inspector conducted a tour of accessible areas of the plant including the Control Room Building, Turbine Building, Reactor Building, Diesel Rooms, Intake Structure, Security Gate House 2 and Alarm Station, Radwaste Building and Control Point Areas, a.
Monitoring Control Room Panels Rcutinely during the inspection period, the inspectors conducted re-views of the control rocm panels. The following items were reviewed to determine the licensee's adherence to Licensee Technical Specifica-tion - Limiting Conditions _for Operation and to verify the licensee's adherence to approved procedures.
Switch and valve positions required to satisfy LCO's, where
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applicable, personnel knowledge of recent' changes to procedures, facility configuration and existing plant conditions.
Alams or absense of alams. Acknowledged alams were reviewed
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with on shift licensed personnel as to cause and corrective actions being taken where applicable.
Review of " pulled alarm cards" with on shift personnel.
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Meter indications and recorder values,
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Status lights and power available lights.
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Front panel bypasses.
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Computer printouts,
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Creparison of redundant readings,
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No items of noncompliance were identified, b.
Radiological Controls Radiation controls established by the licensee, including; posting of radiation areas, radiological surveys, condition of step-off pads, and disposal of protective clothing were observed for.confonnance with the requirements of 10 CFR 20 and AP 0503, Establishing and Posting Controlled Areas, OP 4530, Dose Rate Radiation Surveys, OP 4531 Radioactive Contamination Surveys, AP 0504, Shipment and Receipt of Radioactive Materials.
Confimatory surveys were conducted in the following areas to verify licensee posted results:
Reactor Building general areas -
all elevations. The inspector witnessed a survey of LSA Shipment No. 81-80 by licensee personnel on November 24, 1981, Data was recorded on VYOPF 0504.02 and survey meter VY 2407 was within its calibration interval, Periodically, Radiation Work Pemits were reviewed by the inspector to verify confomance with licensee procedure AP 0502, Radiation Work Pemits. Controls established in accordance with the following RWPs were reviewed: RWP 81-619, 960 and 1057, No inadequacies were identified.
Survey instruments were reviewed for operability and current calibra-tion during inspection tours throughout the period. Additionally, on November 13, 1981, the following radiation Instruments were re-viewed for operability: VY Instrument No, 2452, 279, 283, 427, 51225, 1017, 294, 293, 431 and 3163. The instruments were verified operationally (ready by (1) battery check; (ii) response to a checkiii) review source; and, VYDPF 4540.01.
Except as noted below, no inadequacies were identified, VY Instrument No. 1017 (RO-1) was found with its control switch in the "0N" position and unable to pass a satisfactory battery check, Health Physics personnel replaced the batteries for the unit, However, subsequent response checks with a source were not satisfactory and the unit was removed from service and sent to the Instrument Department for calibration / repair.
The inspector had no further questions in this area.
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Plant Housekeeping and Fire Prevention
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Plant housekeeping conditions, including general cleanliness and storage of materials to prevent fire hazards were observed in all areas toured for confonnance with AP 0042, Plant Fire Prevention and AP 6024, Plant Housekeeping, Welding activities in progress in the Main Steam Tunnel on November 13, 1981, were reviewed for conformance witti Fire Control Permit 81-460. No inadequacies were identified, d.
Fluid Leaks and Piping Vibrations Systens and equipment in all areas tourad were observed for the
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existence of fluid leaks and abnormai~ piping vibrations.
No inadequacies were identified.
e, Pipe Hangers / Seismic Restraints During routine tours of the plant, pipe hangers and restraints installed on various piping systems were observed for proper installation, tension, and condition.
No iaadequacies were identified, f.
Control Room Manning / Shift Turnover Control Room Manning was reviewed for confonnance with the require-ments of 10 CFR 50,54 (k), Technical Specifications, AP 0152, Shift Turnover, AP 0150, Responsibility and Authority of Operations Depart-ment Personnel and AP 0036, Shift Staffing, The inspector yerified,.
during the inspection, that appropriate licensed operators were.on
shift. Manning requireme-as were met at all times. Several shift
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turnovers were observed cu m g the course of the inspection. All were noted to be thorough and orderly.
No items of noncompliance were identified, g.
Equipment Tagout and Controls Tagging and controls of equipment released from service were reviewed during inspection tours to verify equipment.was controlled in
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accordance with AP 0140, VY Local Control Switching Rules. Tags
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and equipment control established per Orders81-666, 693, 656, 690, 592, 625, 512, 500, 553, 691, 518 and 481 were reviewed and found to be proper.
No inadequacies were identified, i
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Analyses of Process Liquids and Gases Analyses results from samples of process liquids and gases were re-viewed periodically during the inspection to verify confomance with regulatory requirements. The results of isotopic analyses from reactor coolant, off-gas and stack samples were reviewed routinely from the " Daily Plant Status Report" to verify that Technical Speci-fication Limits were not exceeded and that no adverse trends were apparent.
No inadequacies were identified, 6.
Radioactive Waste System Centrols
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a.
During routine review of licensee's radiation protection controls on November 19, 1981, the inspector conducted a survey of the rad-waste storage area located on the east side of the reactor building.
A summary of the inspector's findings is provided below:
A High Radiation Area Boundary previously established by the
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licensee to control access to radwaste LSA wooden boxes await-ing shipment was found blown down, with licensee contractor work material inside the previously established area. The inspector temporarily re-established the boundary and questioned contractors in the area in regard to their access to the posted area.
It could not be discerned how the material was trans-
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ported inside the controlled area, and all contractors questioned
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stated they had not crossed the High Radiation Area boundary.
It is noted that in accordance with licensee practice at the time, not all of the contractors working in t M general area of rad-waste storage were trained in radiation protection or issued radiation measuring devices. The licensee was notified of the finding and took imediate corrective action to pennanently establish the controlled area, remove all contractor matarial from within the High Radiation Area boundary and initiate training for the contractors in radiation protection. Discussions with contractors working adjacent to the radwaste storage area on November 23, 1981, established they had been issued and were wearing personnel monitoring equipment. A confinnatory survey
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conducted on November 19, 1981, with the licensee's and an NRC issued instrument verified that radiation reading at the boundary of the High Radiation Area and at the contractor work material location were less than 5 mrem /hr.
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The inspector also conducted a review of compacted waste boxes located outside the radwaste area. The boxes contained dry compacted LSA waste being made ready for shipment. The inspector noted one wood shipping box that was not labeled and indicated a
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reading of greater than 100 mrem /hr on contact as measured with the inspector's NRC issued instrument. The inspector imediately notified the health physics control point'of the finding, a licensee technician was dispatched to the area where confirmatory measurements were taken resulting in a hot spot reading of 150 mrem /hr on contact and 40 mrem /hr at 18 inches. Other readings on the container ranged from 8 to 30 mrem at 18 inches and less than 30 mrem on contact, la inspec-tion of the area around the box revealed a " Radioactive LSA" late 1 that had apparently been attached to one side of the box and subsequently had fallen off, the second required label was not found. The licensee imediately relabeled the box and placed it inside the LSA storage area boundary. T x in-spector reviewed the finding with licensee management who initiated the following corrective action.
Requirements for labeling, surveying and temporary
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storage of wooden shipping boxes per OP 2153, Solid Radwaste, have been reviewed with operations, main-tenance and health physics department personnel.
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The plant personnel respn31ble for the waste box in question have been reinstructed.
All wooden crate LSA labels are now being applied with
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a staple gun, Dedicated, trained personnel have been assigned to
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radwaste compacting duties for the remainder off the 1981 refueling outage.
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Access to and from the radwaste compacting areas has been restricted to improve work area controls, The inspector toured the radwaste compacting area with the licensee health physics department iapresentative on November 20, 1981 and had no furthet questions. As noted in Inspection Report 50-271/81-16, 1he licensee has a long-term commitment to establish a perminent radwaste storage area onsite for material awaiting offsite disposition, b.
During the inspection period, the inspectors verified the licensee's controls for radioactive waste shipments were being implemented by reviewing labeling, surveys and records for the shipments of rad-waste noted below:
LSA Shipment No. 81-80 The inspector reviewed the documentation and final exit survey results for LSA Shipment No. 81-80 on November 24, 198 _
The inspectcr witnessed the radiation measurements taken on the external: surfaces of the HN 100-1 low level, cask, underneath the transport vehicle and inside the vehicle cab. All radiation levels observed were within applicable limits. Documentation associated with the shipment, including VYAPF 0504.02, Shipment Record No.
81080-01 and VYOPF 2511.01 were reviewed and found proper.
No inadequacies were identified.
LSA Shipment No. 81-82 On November 23 and 24, 1981, the inspector reviewed radioactive materials Shipment No. 81-82 consisting of 20 LSA boxes, each containing 105 cu. ft of com) acted trash being made ready for shipment to U.S. Ecology, Ric11and, Washington. The inspector witnessed portions of the loading operation during which the boxes were placed on an open flatbed trailer provided by Tri State Transportation Service. The inspector reviewed the loaded trailer on November 24, 1981, and verified crate loading and labeling was in accordance with VYOP 2511, Radwaste Cask, Drum and Box Handling.
The inspector witnessed the final trailer surveys, tie-down, covering and labeling prior to the shipment leaving the site, and conducted confirmatory surveys to verify licensee data.
Following the departure of Shipment No. 81-82, the inspector reviewed the licensee's Radioactive Materials Shipment Report, Shipment No. 81-82, consisting of the following documents:
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VYAPF 0504.02, Radioactive Shipment Record. Exclusive use Radioactive Material Shipment Truck Survey
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VYAPF 0504.04, Radioactive Materials Shipment Report
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TMST Certification for Placarding and Secure Loading
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VYAPF 2511.02, Drum and Box Handling
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VY Radioactive Shipment Record
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State of Washington, Deparfment of Social and Health Services -
Low-Level Radioactive Waste Shipment Certification No inadequacies were identified, 7.
Followup of Refueling Activities
Refueling and related activities in progress during the period were re-viewed to verify compliance with licensee adr'nistrative and regulatcry i-- -
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requirements. The specific areas reviewed are discussed below.
(1) Core Alterations Activities in the control room and on the refueling floor were observed by the inspector on November 17, 1981, to verify com-pliance with OP 1410 Fuel Loading. Fuel cells around control rods 34-27 and 26-23 were off-loaded for work on the control rad drives. The inspector noted the following:
(a) Refuel interlock checks were completed in accordance with YYOPF 4101,02;
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(b) Staffing of the control room and the refueling floor met Technical Specification requirements;
.(c) Fuel status boards on the refuel floor were maintained; and, (d) Approved procedures were available and in use, No items of noncompliance were identified.
(2) SFR Operability SRM operability was reviewed during periods when core alterations were in progress to verify the requirements of Technical Specifica-tion 3,12,B were met (reference: NRC Region I Ihspection Report 50-271/81-18), On those. occasions when one SPR channel was not operable, the inspector noted that core alterations were prohibited in the affected quadrant and were limited to core locations where the core monitoring requirements of TS 3,12,B were satisfied. The fuel loading schedule was changed as required to accommodate the alternate loading sequence, No items of noncompliance were identified.
(3) Stuck Control Rod Folicwing control rod blade replacernent for rod 34-27, testing was conducted on November 14, 1981, to verify proper operation of the control rod, Control rod 34-27 was found to be stuck when selected for withdrawal, The rod was declared inoperable and electrically disarmed. An adjacent fuel bundle was removed to allow underwater CCTV examination of the blade, which confinned that the rod was fully inserted. The other three adjacent fuel assemblies were lifted and re-inserted to verify no mechanical interference with the fuel existed,
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Several attempts to move rod 34-27 using elevated drive pressure per OP 2111 were unsuccessful. The entire control cell was off-loaded on November 17, 1981, to allow complete inspection of the blade and fuel support casting. Examination of the fuel su) port casting showed that it was improperly seated, as noted by tie misalignment between the casting locking ears and the alignment pin. Misalig rent of the fuel support casting was sufficient to cause mechanical interference between the blade and the casting, and hold the blade in position with the weight of 4 fuel bundles supported by the casting. Rod 34-27 was subsequently moved on November 18, 1981 using its drive mechanism, with the cell off-loaded. The fuel support casting was removed for inspection,.
found acceptable and reinstalled. The drive and blade for control rod 34-27 were replaced.
Based on discussions with licensee personnel, it was noted that the fuel support casting most likely became misaligned during the initial blade exchange operation.
It was postulated that following blade and casting installation, when the drive was inserted, it " caught" on the double blade guide, which in turn lifted and rotated the support casting a sufficient amount to cause misalignment.
Such a sequence has been reported to have occurred at other facilities.
Proper alignment of the fuel support casting is nomally verified by underwater CCTV examination following blade replacement. The licensee stated that the applicable procedures (OP lill, Control Rod Removal and Installation) would be changed to require an additional verification of the casting orientation be made following completion of blade coupling with its drive, and insertion to position 00.
No items of noncompliance were identified.
8.
Observations of Physical Security The inspector made observations, witnessed and/or verified during regular and offshift hours that selected aspects of plant physical security were in accordance with regulatory requirements, the physical security plan and approved procedures.
a.
Physical Protection Security Organization observations indicated that a full time member of the security
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organization with authority to direct physical security actions was present as required.
manning of all shifts on various days was observed to be as
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require.
b.
Access Control identification, authorization and badging,
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access control searches, including, when applicable, the use
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of compensatory measures during periods when equipment was inoperable.
escorting.
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c-Physical Barriers selected barriers in the protected areas and vital areas were
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observed and random monitoring of isolation zones was performed, Observation of vr.hicle searches were made, inspector tours of gate house 2, the Central and Secondary Alarm
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Stations were conducted at random periods, No items of noncompliance were identified, 9.
Surveillance' Testing The inspector observed or reviewed portions of the following surveillance tests to verify that testing was performed in accordance with procedures, that results were in conformance with Technical Specifications and proce-dure requirements, that test instrumentation was calibrated, that redun-dant system (s) or component (s) were available for service, that work was t
being perfomed by qualified personnel, and that activities were in com-pliance with AP 4000, Surveillance Testing Control, a,
Snubber Surveillance
The inspector reviewed the results of snubber inspections and testing completed during the refueling outage in accordance with OP 5203, Shock Suppressors. The snubber inspection interval was at a six-month frecuency at the start of the outage due to previous failures identifiec and reported by the licensee, The following snubbers were removed and functionally tested in accordance with Technical Specification requirements: RR-78, MS-H127, MS-H128, CS-H868 and RHR-H193, No discrepancies were identified, the 5 snubbers were rebuilt, functionally tested again and re-installed, Environmentally qualified seal material was used to rebuild the snubbers. Replacement of the seals in snubbers MS-H127, MS-H128 and RR-78 constitutes the last of the snubbers in normally. inaccessible areas that required qualified seal material.
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Visual examination per OP 5203 of the remaining 45 hydraulic snunbers in the plant identified.no inadequacies, with the following exceptions. The reservoir for snubber MS -35 was found empty. However, the snubber was removed and tested in the as-found condition and determined to be functional, The unit was subsequently rebuilt and re-installed. Snubber RR-12 was also focad with an empty reservoir. Functional testing.in the as-found condition identified a lock-up rate of 6,3 inches / min, which was in excess of the maximum allowable valve of 3,8 inches / min specified in Table 1 of OP 5203. However, the Table 1 lock-up values are calculated for ambient conditions of 750F, After applying a :orrection factor for changes in fluid viscosity from 750F to 1800F, the maximum allowable lock-up rate for RR-12 was gecified at 7 inches / min, and thus, the as-found value was statermined to be acceptable. The viscosity calcula-tions were mpleted by a methodology described in a YAEC memoran-dum (MEG 257/78) dated September 1, 1978, and described to the NRC staf f in a letter dated September 5,1978. RR-12 was subse-quently reou.lt and re-installed.
A final visual inspection of all snubbers was conducted prior to plant startup(t or - 25%) from that date, or by March, 1983, on December 2, 1981. The next required inspection is 12 months The following snubbers and restraints located inside the drywell and the reactor building were examined by the ir.spector during the period from November 25-November 30, 1981. The snubbers /re-straints were reviewed for proper fluid level, orientation, physical condition, spring setting and absence of leakage, as oppropriate:
- CS-H 85
- RR-3
- MS-3
- RR-16
- MS-15
- RR-15
- MS-24
- RR-83
- RR-2
- RR-84
- RR-19
- RR-20
- RR-76
- RR-78
- RHR-H 183
- RHR-H 185
- RHR-H 188
- RHR-H 197A
- RHR-H 197B No items of noncompliance were identified.
b.
Standby Liquid Control System Surveillance During the inspection period, the inspector witnessed annual re-fueling outage surveillance testing of the Standby Liquid Control
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System (SLC). On November 7, 1981, the inspector witnessed OP 4114, Standby Liquid Control System, Procedure Step B, Flow Test Directly Into Reacte-Vessel.
This test manually initiates the SLC system with the explosion valve connected to a test firing block and con-ducts flow tests using demineralized water injected directly to the RV. The inspector observed spoolpiece installation, test block setup, and conduct of the test for each SLC subsystem per OP 4114 and Main-tenance Procedure 4203, Maintenance and Testing of SLC Squibb Valves.
The inspector reviewed VYOPF 4114.02, Flow Test Into Reactor Data Sheet dated November 7,1981, for completeness and acceptability of data per OP 4114 and TS 4.4.A.2 and had no further questions.
The inspector also reviewed OP 5201, Safety System Valves, checklist VYAPF 5201.02, Safety Relief and Safety / Relief Valve Checklist for performance of the SLC Relief Valve Test. Both SLC pressure relief valves SR-39A and 39B were tested on November 9, 1981, with the following results: SR-39A as found 1490 psig as left 1410 psig ard SR-39B as found 1540 psig as left 1410 psig. Per TS 4.4.A.2 the setting of the system pressure relief valve is 1400-1490 psig.
The inspector notes that setpoint drift of the SLC relief valves is addressed by PAR No. 81-17 which installed a Standby Liquid Control Clean-up System during the 1981 refueling outage in an attempt to eliminate the cause of SR-39A, -39B setpoint drift. The inspector had no further questions.
10. Refueling Outage Maintenance Activities Procedures governing two outage maintenance activities were reviewed to
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verify the following controls were established, as required:
administrative approvals for removal from and return of equipment
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to service hold points for QA, QC or supervisory review
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provisions for operation retesting following maintenance
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requirements to obtain special authorization for use of ignition sources requirements for establishment of a fire watch
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provisions for review of material certifications
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provisions for assuring Technical Specification LC0 requirements
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are established.
provisions for control of housekeeping
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provisions to maintain cleanliness of components
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provisions for reporting identified discrepancies to management.
Documentation of work completed in accordance with the follow g procedures was reviewed:
Safety Relief Valve Tec.ing, done in accordance with OP 5201, Safety,
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Relief and Safety Relief Valve testing MSIV reventative maintenance done in accordance with OP 5303,
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MSIV Numatics) Preventive Maintenance Maintenance Work Requests MR 81-1308, 1309 and 1182
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OP 4113, MSIV Stroke Time Testing
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No inadequaciei wce identified.
11. Review of Plant Operations - Startup Procedures and actions takan to startup from the refueling outage were reviewed to verify compliance with Technical Specification requirements.
Inspection of this area consisted of a review of startup procedures to verify changes had been incorporated, as required, to reflect outage modifications; a review of plant equipment alignment and status for systems required for startup; a review of surveillance testing completed prior to startup; and, a review of procedures in use to govern startup activities, a.
System Line-up Status The status of system valve lineups was reviewed to verify equipment required to support plant operations was available. Additionally, the inspector conducted an independent review, on a sampling basis, cf the valve line-up status for the following systems:
Containment Air Dilution System per OP 2125
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Diesel Generator Cooling, Lube Oil and Fuel Oil per OP 2126
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Core Spray System per OP 2123
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Residual Heat Removal System per OP 2124 No inadequacies were identifie r
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b.
Witness of Startup Activities Activities in progress, testing and surveillance results conducted in accordance witii the following procedures were reviewed and/or witnessed by the inspector:
OP 4126, Diesel Generator A Operational readiness testing
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following maintenance;
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OP 0100, Plant Startup from Cold Shutdown, including completion of prerequisites for startup; OP 2115, Drywell Close-out inspection and valve lineup
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verification; OP 4100, ECCS Automatic Initiation Test;
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OP 4200, Safety Relief Valve 67HH13 (D main steam line) and 67HH37 (B main steam line) lift setpoint testing, including Wyle Laboratory Certification Test Report No. 45922-2;
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OP 2404, Control rod withdrawal in sequence 9-A-1 for criti-cality and heatup from cold shutdown.
No items of noncompliance were identified. Except as discussed below, the inspector had ne further comments in this area.
Integrated ECCS testing wasscompleted satisfactorily per 0.' 000 on November 27, 1981, with two exceptions noted during the per-formance of the test. Upon initiation of the test, the HPCI Gland Exhaust pump did not start either automatically or through manual attempts after the start failure. Licensee personnel inspected the ACB for the pump, which was fcund to have tripped due to a themal overloat'.. The unit was reset and the initiation logic associated with '.ne pump was subsequently tested satisfac-
torily. A maintenance request was issued to investigate and re-pair the cause of the thermal overload trip.
l A second exception concerned a failure to receive the ADS Timer
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Start indication during the test. Further review of the method l
for initiating the test showed that the ADS Timer would not receive the start signal. Since ADS initiation logic is verified during
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l the conduct of OP 4343, inclusion of that portion of the ECCS l
logic is not required. OP 4100 will be revised to delete refer-l ences to the ADS portion of the logic.
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The inspector conducted an independent review of the start and loading times for the diesel generators and the. core spray and residual heat removal pumps. No inadequacies were identified.
12. Review of NUREG 0737 - TMI Action Plan Requirements Actions completed by the licensee to implement the requirements of NUREG 0737 Item II.K.3.27 were reviewed. New scale faces were inst., led on the following instruments on November 20, 1981, in accordance with MWR 81-1319:
LTZ-3-57A/B, LTZ-3-72A/B, LT2-3-5BA/B, LI2-3-57A/B, LI2-3-72A/B, LI6-94A/B and LR6-96. The scale faces were changed to provide a common reference indication for reactor vessel water level, Amendment 68 to DRP-28 was issued on November 16, 1981, to incorporate the appropriate changes in the plant Technical Specifications.
The inspector reviewed a licensee internal memorandum dated November 17, 1981 (File 3.1) which identified the operating procedures, manuals, drawings and FSAR pages that would be revised as a result of the changes. The inspector reviewed changes made to 23 operating proce-dures on November 20, 1981, to provide the appropriate corrections to specified level valves. Changes to the procedures and facility hard-ware were also incorporated in the outage training program provided to plant personnel. The inspector noted through an interview with one control room operator that he had received the subject training. The inspector had no further questions regarding Item II,K.3,27, Additionally, during this inspection, the inspector reviewed the status of licensee actions to complete NUREG 0737 items with a due date on or after January 1, 1982.
Items reviewed included I.C.1, II.B.1, II.B.2, II.B.3, II.F.1, II.K.3.13, II.K.3.15 and II.K.3.22.
No inadequacies were identified. The above items will be reviewed further on subse-quent inspections.
13. APRM Inputs to Reactor Manual Control System (RMCS)
The inspector reviewed the arrangement of APRM inputs to the RMCS rod block circuits for comparison with the channel operability requirements of Technical Specification Table 3.2.5.
GEK 32438A, 32416A and Elementary Drawings 197R10 and 730E328 were used for the review. The circuitry was discussed with the I&C Supervisor. Based on the review, the inspector determined that APRM Output trips are grouped by three's into two logic circuits fed through common fuse 3AF1. The APRM A, D & E channels are grouped in circuit 1, the APRM C, B and F channels are grouped in circuit 1.
Tripping of any one of the A, E or D channels will result in de-energizing relay 3AK1, whose open contacts will in turn de-energize relay 3A-K-6. Similarly, in circuit 2, tripping of any one of the C, B or F channels will result in de-energizing relay 3A-K-2,whose open contacts
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will also in turn de-energize relay 3A-K6, since contacts from 3A-K1 and 3A-K2 are in series in the 120 VAC circuit energizing relay 3A-K6, De-energizing relay 3A-K6 will result in a rod block being generated through the PNCS. Relay 3A-K6 is thus defined as the endpoint relay in tne trip system logic.
The inspector noted that by manipulation of the APPN bypass switches on CRP-9-5, up to 2 of the 3 APRM in auts in either circuit 1 or 2 could be bypassed. However, at least 4 otler APRM inputs could still be avail-able to generate a rod block through action on relay 3A-K6, Thus, the
" minimum channels available for operability" requirements ~ of Technical Saecification Table 3.2.5 could not be affected by the positioning of tie APRM bypass switches.
No items of noncompliance were identified.
14. Unresolved Items Unresolved items are items about which more information is required to ascertain whether they are acceptable items, items of noncompliance, or deviations. An unresolved item is discussed in Detail 4,d.(3) of this report.
15. Management Meetings During the period of the inspection, licensee management was periodically notified of the preliminary findings by the resident inspectors, A summary was also provided at the conclusion of the inspection and prior to report issuance.
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