IR 05000244/1983017
| ML20024F371 | |
| Person / Time | |
|---|---|
| Site: | Ginna  |
| Issue date: | 08/19/1983 |
| From: | Lazarus W, Zimmerman R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20024F366 | List: |
| References | |
| 50-244-83-17, IEB-83-03, IEB-83-05, IEB-83-3, IEB-83-5, NUDOCS 8309090321 | |
| Download: ML20024F371 (12) | |
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U.S. :oUCL E AR RE GUL A10RY CO:":!L51O!;
50244-830613 50244-830618 50244-830619 Region i Report tio. 50-244/83-17 DacI et tio.
50-244
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t iconse 1;o. DPR-18 Priority
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Category C
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Licensee:
Rochester Gas and Electric Corporation 49 East Avenue
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Rochester, New York 14649 racility flame:
R. E. Ginna Nuclear Power Plant
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inspection at:
Ontario, New York Inspection conducted: June 17, 1983 through August 7, 1983 Inspectors:
8 9 le f//7/65 date signed R. P.' Zim6dnan, Senior Resident Inspector date signed
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date signed Approved by:
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W. N azar d/, Acting Chief, Reactor Projects Section 2C, Division of Project & Resident Programs Insoec tion Summary:
Inspection on June 17, 1983 through August 7, 1983 (Report No. 50-244/83-17)
Areas inspected:
Routine, onsite, regular and backshift, inspection by the resident inspector (138 hours0.0016 days <br />0.0383 hours <br />2.281746e-4 weeks <br />5.2509e-5 months <br />). Areas inspected included: plant operations; surveillance testing; followup on Integrated Plant Safety Assessment items, followup on Bulletins & Circulars; Inservice Inspection Program review; annual emergency exercise review; Licenset Event Reports; periodic and special reports and accessible portions of the facility during plant tours.
Results: No violations were identified during this inspection.
8309090321 830823 PDR ADOCK 05000244 G
PDR r.cc ion I rom 12 (6v. April 77)
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t DETAILS
1.
Persons Contacted The below listed technical and supervisory level personnel were among those contacted:
E. Beatty, Operations Supervisor L. Boutwell, Maintenance Supervisor C. Edgar, Instrument & Control Supervisor D. Filkins, Health Physics and Chemistry Manager D. Gent, Results and-Test Supervisor G. Larizza, Operations Manager T. Meyer, Technical Manager R. Morrill, Training Manager T. Schuler, Maintenance Manager B. A. Snow, Plant Superintendent S. M. Spector, Assistant Plant Superintendent W. Stiewe, Quality Control Engineer R. Wood, Supervisor of Nuclear Security The inspector also interviewed and talked with other licensee personnel during the course of the inspection.
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2.
Licensee Action on Previous Inspection Findings (Closed) Unresolved Item (244/77-21-01): Vendor report on DB-50 breaker malfunction. Westinghouse inspected and electrically tested the breaker
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without any failures observed through the range of minimum, normal and maximum control voltages. The overcurrent tripping devices were also verified to be within the current characteristic curve.
No apparent cause for the failure to close on the first two attempts could be identified.
(Closed)UnresolvedItem(244/79-15-02): Licensee to inventory all spare
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overcurrent devices to ensure all devices have been inspected and the l
results properly documented. The inspector reviewed Preventive Action Report 27-79 and verified that all overcurrent devices were inspected with a 5X magnification glass, with no crac! s identified.
3.
Review of Plant Operations
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a.
Throughout the reporting period, the inspector reviewed plant operations i
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associated with the completion of the annual refueling outage on June
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25, 1983 and the return to full power operation which was maintained I
for the remainder of the inspection period. Activities in progress in-cluded primary system hydrostatic testing, startup physics testing; and turbine control system troubleshooting and repair.
l Following completion of low power startup physics testing, an inter-mediate range high flux trip (24%) occurred on June 18 at 6:50 P.M..
At the time of the trip, the control room operators were perfonning
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a calorimetric to detemine the accuracy of the power range instru,
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mentation with the new low leakage fuel configuration. The licensee
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had not bypassed the intemediate range trip because the accuracy of _
the power range instrumentation had not yet been verified. A unit startup was commenced with criticality achieved on June 18 at 9:15 P.
M..
A turbine trip occurred while synchronizing the unit to the grid _
at 10:15 A.M., June 19, due to a fault in the turbine electro-hydraulic control (EHC) system. With tro'ubleshooting of the turbine EHC system ongoing, a reactor trip from 15% power occurred on June 20 at 12:14 sA.M., while attempting,to transfer control of the 'A' feedwater reg-
.ulating valve from manual to automatic. The reactor trip occurred on slow level in the 'A' Steam Generator coincident with a steam flow /
feedwater mismatch. The, reactor was again taken critical on June 20
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at 6:50 A.M., and following completion of repairs to the EHC system, the unit was ' synchronized to the grid'en June 25 at 12:17 A.M.. No further problems were encountered during the return to full power op-eration.
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b.
During the course of the inspecti,cn, tours of the following areas were
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conducted:
Control Room
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Containment
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-7 -Auxiliary Building Intermediate Building (including control point)
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Service Building
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Turbine Buildi~ng'
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Diesel Generator Rooms
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Battery Rooms
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Screenhouse
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i Yard Area and. Perimeter"
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Thefollowingareasjwe'reobservedduringthetours:
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Operating logs and records.
Records were reviewed against Technical
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Specification and administrative procedure requirements.
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Monitoring instrumentation.
Process instruments were observed for.
correlation between channels and for confomance with Technics 1
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Specification requirements.
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Annunciator alarms. Various alam. conditions which had been received and acknowledged were observed. These were discussed with shift i
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personnel to verify that the reasons for the alarms were uncerstood and corrective action, if required, was being taken.
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Shift manning.
Control room and shift manning were observed for confomance with 10 CFR 50.54 (K), Technical Specifications, and
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administrative procedures.
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Radiation protection controls. Areas observed included control point operation, posting of radiation and high radiation areas,
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compliance with Radiation Work Pemits (RWPs) and Special Work
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Permits (SWPs), personnel monitoring devices being properly worn, and personnel frisking practices.
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Equipment lineups. Valve and electrical breakers were verified to be in the position or condition required by Technical Speci-
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fications and plant lineup procedures for the applicable plant
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mode. This verification included routine control board indication review and conduct of a partial system lineup of the Auxiliary
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Feedwater System on June 29; portions of the fire protection system on June 29 and July 22; and partial lineups of the Safety
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Injection, Containment Spray and Component Cooling Water Systems
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on August 8.
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Equi 3 ment tagging.
Selected equipment, for which tagging requests had acen initiated, was observed to verify that tags were in place and the equipment in the condition specified.
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Fire protection.
Fire detection and fire fighting equipment and controls were observed for confomance with Technical Specifications and administrative procedures.
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i. -Security. Areas observed for confonnance with regulatory require-
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ments, and implementation of the site security plan and administra-
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tive procedures included vehicle and personnel access, and both
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protected and vital area integrity.
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j Plant housekeeping. Plant conditions were observed for conformance
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wTth administrative procedures. Storage of material and components
was observed with respect to prevention of fire and safety hazards.
Hou'sekeeping was evaluated with respect to controlling the spread of surface and airborne contamination.
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No violations were identified.
4.
Surveillance Testing and Calibration y,
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The inspector witnessed the performance of surveillance testing and cali-bration of selected components to verify that the procedure in use was prop-erly approved and adequately detailed to assure satisfactory perfomance;
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test instrumentation required by the procedure was calibrated and in use; work was perfomed by qualified personnel; and results satisfied Technical Specifications and procedural acceptance criteria or were properly dis-
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The ins,pector witnessed the performance of the following activities:
Periodic Test Procedure (PT)-3, Containment Spray Pumps and NaOH
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Additive System, Revision 33, February 15, 1983, performed August 4, 1983.
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Noviolationspereidentified.
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-Iniervice Inspection Program Tech'nical Specification 4.2.1 specifies the inservice inspection program requirements for Quality Group A, B and C components.- During a review of
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the licensee's inservice inspection program, the inspector was unable to
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verify whether the licensee had properly implemented the above requirements
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due/to the lack of readily available documentation.' The licensee has not
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maintained a current inspection status or schedule, and has not indepen-dently verified compliance with Technical Specification 4.2.1.
In addition,
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'the'. inspector noted a discrepancy between the Ginna Station Quality Assurance Manual Appendix B and Technical Specifications 4.2.1.1 and 4.2.1.2 in de-
fining when the ten year inspection interval comenced for Group B and C
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compcnents. I f censee management committed to perfoming a complete review rof the inservice inspection program for Quality Group A, B and C components
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_to determine the current program status. The licensee representative stated that the program review will be ccupleted by September 9,1983. This item is considered unresolved pending further NRC review. (83-17-01)
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6.'
Integrated Plant Safety Assessment Review
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The inspector reviewed the below listed items which were identified during the Systematic Evaluation Program review to require equipment and/or procedural i
l changes. The topic numbers refer to paragraph designations in NtJREG-0821, Integrated Plant Safety Aisessment Final Report for the R. E. Ginna Nuclear
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. power Plant, December,1982.
a.
Alterr. ate Diesel Generatoi Cooling' Connection (3.3.1.1) The licensee agreed to install a hose connection from the, f1re-water system to each diesel generator to provide an alternate source of cooling water in the
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-event of a loss of service water. The inspector verified that modifi-
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D cations had been adequately performed on the service water supply to both
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L diesel generators to pemit attachment of fire hoses from the town fire
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hydrant located outside the Diesel Generator Building.
g xThe following procedural coments generated during the review of the diesel generator cooling modification were found to require further licensee atten-
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tion.' The inspector will follow the licensec actions with regard to the
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i Emergency Procedure (E)-4.3, Loss of All A.C. Power, steps 3.1
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through 3.1.2.2, should be clarified to ensure that a service water
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pump is automatically loaded or is loaded first if manually perform-ed, to protect the diesel generator from damage due to loss of cool-
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E-38, Loss of Service Water, should be revised to include the steps
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necessary to tie-in the fire water hose to the diesel generators if a loss of service water has occurred.
References:
1.
2.
RG&E Drawing 33013-529, Station Service Cooling Water, Revision I.
3.
System Modification Procedure (SM)-3021.2, Alternate Cooling Water Supply Installation for the 'B' Diesel Generator, Revision 0, May 18, 1982.
4.
SM-3021.2, Alternate Cooling Water Supply Installation for the 'A'
Diesel Generator, Revision 0, May 14,1982.
5.
SM-3021.1A, Valve Installation and Hydrostatic Testing for the '8'
Diesel Generator Modification, Revision 3. March 31,1983.
6.
SM-3021.2A, Valve Installation and Hydrostatic Testing for the 'A'
Diesel Generator Modification Revision 3, March 31, 1983.
7.
Design Criteria and Safety Analysis-EWR 3021, Diesel Generator Cool-ing,' Revision 0, November 9 1981.
8.
Emergency Procedure (E)-4.3, Loss of All A.C. Power, Revision 5, July 26, 1983.
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E-38, Loss of Service Water, Revision 4, March 2, 1983.
10.
J. Maler (RG&E) letter to D. Crutchfield (NRC), dated March 22, 1983.
b.
Alternate Water Supply to Standby Auxiliary Feedwater Pumps (SAFWP) (4.14) - -
The licensee agreed to install a hose connection from the fire water system to the standby auxiliary feedwater pumps to provide a means of decay heat removal in the event of a loss of service water.
The inspector verified that modifications had been adequately perfone' e the suction piping to the standby auxiliary feedwater pumps to pemit sha-ment of a fire hose from the town fire hydrant, located outside the SAFh; building.
References:
1.
NUREG 0821 2.
J. Maier (RG&E) letter to D. Crutchfield (NRC), dated March 22,1983.
3.
System Modification Procedure (SM)-3021.3, Alternate Cooling Water Supply to the Standby Auxiliary Feedwater Pumps, Revision 0, November 18, 1982.
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RG&E Drawing 33013-545 Auxiliary Feedwater and Standby Feedwater Systems, Revision 1.
c.
Inservice Inspection Program for Water Control Structures The licensee agreed to modify the existing inspection program for water control struc-tures to conform with specifications of Regulatory Guide 1.127 Inspection of Water Control Sturctures Associated with Nuclear Power Plants. The inspector verified that implementation of the inspection program included the following:
Approved procedures were used for the inspection of water control
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structures and the completed inspection reports were reviewed by the appropriate engineering discipline; A comprehensive file of engineering drawings for safety-related water
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control structures is being maintained; Procedures include requirements for the performance of special in-
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spections after extreme events such as floods and seiches; and Completed procedures, inspection reports, and photographs taken during
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the inspections are maintained on-file by the Maintenance Department.
At present the inspection program does not specify routine inspection frequencies, although reference (3) listed below stated that inspections of the intake structure would be perfcmed on a ten year interval. The licensee agreed to incorporate annual inspection frequencies into the ap-propriate procedures for the discharge canal, revetment, redundant ser-
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vice water return structure, and the Screenhouse. The inspector reviewed contractor licensee reports from inspections of the intake structure and
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Screenhouse, completed in June,1983. Although no structural deterioration was observed, photographs from the Screenhouse inspection, showed a signi-ficant amount of marine life and small debris on the individual service water pump suction screens, requiring opening of the screen passive bypass port in at least one instance. The licensee representative believed the source of the screen fouling was due to material which had passed through holes in the traveling screens. The holes have subsequently been repaired.
The service water pump suction screens were thoroughly cleaned prior to the conclusion of the inspection.
References:
1.
2.
3.
J.Maier(RG&E)lettertoD.Crutchfield(NRC),datedMay 26, 1983.
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4.
Maintenance Procedure (M)-92, Underwater Inspection of Mechanical-Equipment and Structures in the Screenhouse, Revision 1. May 12, 1983.
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M-92.1, Underwater Inspection and Maintenance of the Intake Tunnel Structure and Shaft, Revision 0, May 12, 1983.
6.
M-92.2, Inservice Inspection of Miscellaneous Water Control Structures at Ginna, Revision 0, May 18,1983.
7.
Followup of IE Bulletins and Circulars The inspector reviewed facility records, interviewed licensee personnel and observed facility equipment / components to verify that:
licensee management received the below-listed bulletins and circulars,
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and designated individuals responsible for review; licensee corrective / preventive actions, as appropriate, were taken based
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on the applicability of the subject matter; and, information discussed in the licensee's bulletin response was accurate
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and submitted within the required time period.
The following bulletins and circulars were reviewed.
IE Bulletin 83-03: Check Valve Failures in Raw Water Cooling Systems of Diesel Generators. The licensee perfomed a complete walkdown of all service water supply and return piping to and from both diesel generators. The four service water pump discharge check valves were the only ch::ck valves identified in the flow path. These valves are considered Category 'C' check valves and are test-ed quarterly to verify check valve opening by obtaining a specified total flow.
In addition, a leak check to verify closure tightness is performed during each refueling outage.
During the 1982 refueling outage the 'D' service water pump discharge check valve was disassembled and inspected as a result of observable backflow through the check valve causing the service water pump to rotate in the reverse direction.
I Wear consistent with length of service was observed on the bushings, hinge pins and shaft area. Although the valve internals were completely intact, the entire valve internals were replaced as part of the preventive maintenance program.
During the 1983 refueling outage the three remaining check valves were disassem-bled and inspected. Similar wear was observed, and the valve internals were re-placed as preventive maintenance. Subsequent leakage tests indicated no observ-able leakage.
In accordance with the bulletin, the licensee intends to submit a revision to the Inservice Test (IST) Program by December 31,1983 to reclassify the above check valves as Category A valves, and require leak testing that confirms the integrity of the valve internals. This bulletin will remain open pending re-vision of the IST program, c
IE Bulletin 83-05: ASME Nuclear Code Pumps and Spare Parts -Manufactured by the
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Hayward Tyler Pump Company (HTPC). The licensee conducted an investigation and l
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determined that there are no ASME Code pumps manfactured by HTPC installed at Ginna.
In addition, no spare parts manufactured by HTPC are in use or planned for use in pumps important to safety. This bulletin is closed.
Circular 79-19: Loose Locking Devices on Ingersoll-Rand Pump Impellers.
The i
licensee has added a step in the precaution section of Maintenance Procedure
(M)-ll.14. Inspection and Maintenance of Ingersoll-Rand Pumps, to inspect the
impeller locking device. The inspector stated a concern that the step might be overlooked in its present location in the precaution section. The Main-tenance Manager acknowledged the inspector's coninent and stated the procedure would be reviewed to detemine if the step should be relocated in the instruc-tion section. This circular is closed.
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8.
Annual Emergency Exercise-June 22, 1983 i
The scenario comenced with the unit at a stable, full power condition. The l
enruing events included a fire, a loss of all A.C. power, and a primary leakage path of approximately 50 gallons per minute to the environment. The inspector observed the exercise from the Control Room where a full training shift partici-pated in the exercise. The following observations were made during the exercise and were discussed with licensee management.
Further details regarding the over-all exercise, as witnessed by an NRC observation team, are documented in NRC~
Region I Inspection Report 50-244/83-15.
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Operations personnel demonstrated good knowledge of emergency procedures
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and interaction of plant systems.
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Initial notifications, including classification of events, to outside
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agencies were generally well perfomed.
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Actions taken in response to various exercise emergency situations demon-
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strated good use of primary and alternative methods of mitigating the
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l scenario events.
Weaknesses were identified in the flow of information between the Control
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Room, Technical Support Center (TSC) and Emergency Operations Facility (EOF).
i For example, details regarding the location and size of the primary leakage path were determined by TSC and EOF personnel, but were not communicated to the Control Room operators. The Control Room shift correctly analyzed and independently came to a similar conclusion regarding the leakage location
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Much of the plant parameter infomation requested of the Control Room by the
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TSC_was already available in the TSC from the plant computer printout.
The completion of routine paperwork, such as A-25.1 & A-52.4 reports and
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temporary procedure change foms appeared to detract from the analysis l
and control of ongoing events.
No violations were identified; however, the inspector will follow the licensee's l
actions regarding the above areas where improvements appeared warranted. (83-17-03)
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9.
Licensee Event Reports (LER's)
The inspectur reviewed the following LER's to verify that the details of the events were clearly reported, the description of the cause was accurate, and adequate corrective action was taken. The inspector also detennined whether further information was required, and whether generic implications were in-volved. The inspector further verified that the reporting requirements of Technical Specifications and station administrative and operating procedures had been met; that the event was reviewed by the Plant Operations Review Com-mittee; and that continued operation of the facility was conducted within the Technical Specification limit.
83-19_: Containment Spray Pumps Inoperable Above 2000F-June 13, 1983. This event is documented in NRC Region I Inspection Report 50-244/83-13.
83-20: Primary Coolant Chloride Concentration-June 13, 1983.
During startup from the 1983 refueling outage, the reactor coolant system chloride concen-tration exceeded the.15 ppm limit at greater than 250F.
The chloride concen-tration was returned to within specification in approximately three hours.
The maximum chloride concentration measured during this period was.19 ppm.
The licensee's evaluation determined the following causes for the increase in chloride concentration:
increased chloride solubility due to increasing temperature;
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contamination from opening the primary system; and
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reduced effectiveness of the primary mixed bed due to the high con-
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centration of borate ions.
The deborating demineralizer was placed in service to increase the anion removal capacity of the letdown cleanup system.
83-21: Pressurizer Low Level-June 18, 1983.
Following reactor trips on June 18 and 20, the pressurizer water level dropped below 12%. This degree of shrink in the pressurizer water level is not unexpected following a primary system cooldown after a reactor trip.
83-23:
Indicated Leakage Past Pressurizer PORV-June 19, 1983.
Following a turbine trip from 15% reactor power, Pressurizer PORV 430 lifted due to high pressurizer pressure. The relief valve reseated; however, a small amount of leakage was detected by the operator from PORC discharge temperature and remote valve packing leakage temperature indication. The associated block valve.
was closed as required. About 35 minutes after closure of the block valve, the PORV was cycled by the operator. The block valve was reopened and no indicated leakage through the PORV was observed.
During review of the turbine trip, the licensee detennined that the pressurizer spray valve proportional gains required adjustment to increase the valves' rate sensitivity.
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10.
Inservice Testing of Safety Injection Pump Bearing Temperatures On June 20,1983, the licensee submitted Revision 3A to the Ginna Station Quality Assurance Manual, Appendix C to the NRC for approval. The proposed change included deletion of the ASME Boiler and Pressure Vessel Code,Section XI, IWP-3000 requirement for annual pump bearing temperature measurements.
The submittal provided the licensee's justification why the measurement of bearing temperatures are either inconclusive or undesirable.
The inspector reviewed data from previously perfomed bearing temperature measurements of safety-related pumps and noted relatively high bearing stabilization temperatures, between 150-1700F, for the safety injection pumps.
The temperature measurements were recorded while at test flow conditions gen-erally between 50-85 gallons per minute (gpm). hwever, actual safety in-jection pump recirculation flow at pump shutoff Lead conditions is about 35 gpm, which may tend to increase the axial loading on the bearings. The ma-jority of tests were also noted to have been run during months when service water cooling to the bearing was between 35-400F. The inspector expressed concern to licensee management that safety injection pump operability may be questionable during extended periods of pump operation at shutoff head con-ditions during the months when service water cooling to the pumps bearings can exceed 700F. The licensee has agreed to review the circumstances surrounding the bearing temperature results from previous inservice tests of the safety injection pumps, and take appropriate corrective and/or preventive actions, if necessary, to assure the safety injection pumps can function properly when required. The initial phase of the licensee's review is expected to be com-pleted by the end of August, 1983. The inspector will closely follow the licen-see's actions.
(83-17-04)
11. Review of Periodic and Special Reports Upon receipt, periodic and special reports submitted by the licensee pursuant to Technical Specification 6.9.1 and 6.9.3 were reviewed by the inspector. This review included the following considerations:
the report contained the information required to be reported by NRC requirements; test results and/or supporting infor-r nion were consistent with design predictions and performance specifications; planned corrective action was adequate for resolution of identified problems; and the validity of the reported information. Within the scope of the above, the following reports were reviewed by the inspector.
Monthly Operating Reports for June and July, 1983.
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No violations were identified.
Jnresolved Items Unresolved items are matters about which more infomation is required in order to ascertain whether they are acceptable, a violation, or a deviation. An un-resolved item identified during the inspection is discussed in Paragraph 5.
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12.
Exit Interview At periodic intervals during the course of the inspection, meetings were held with senior facility management to discuss the inspection, scope and findings.
At no time during this inspection was written material provided to the licensee by the inspector.
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