IR 05000282/1990002
| ML20012D745 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 03/16/1990 |
| From: | Burgess B NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20012D743 | List: |
| References | |
| 50-282-90-02, 50-282-90-2, 50-306-90-02, 50-306-90-2, IEB-89-003, IEB-89-3, NUDOCS 9003280319 | |
| Download: ML20012D745 (13) | |
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!U. S.: NUCLEAR: REGULATORY COMMISSION:
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REGION III
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ReportsNo.f50-282/90002(DRP);50-306/90002(DRP)
,7 Docket'Nos. 50-282;-50-306 License Nos. DPR-42;'DPR-60 Licensee:. Northern States Power Company w
L414 Nicollet Mall Minneapolis, MN 55401
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Facility Name: Prairie-Island Nuclear Generating Plant Inspection At: Prairie Island Site, Red Wing, Minnesota
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. Inspection Conducted:- ' January 17-through February 27, 1990
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. Inspectors:-
P. L. Hartmann
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- T.-J..O'Connor
'E. R..Schweibinz Approved By:.
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3/#/9a l-p Reactor Projects Section 2A Date.
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. Inspection Sunnary Inspection on January 17 through February 27,'1990(Reports
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L-No. 50-2BP/90002(DRP): 50-306/90002(DRP))-
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Areas Inspected:. Routine unannounced;1nspection by resident inspectors of plant operational safety, maintenance,' surveillance, radiological protection,.
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-industrial safety, Bulletins, Temporary Instructions, and LERs. Multiplant
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Action'(NPA) Item B-03, PWR Moderator Dilution was closed.
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~Results: Unit I connenced the Cycle 13 to 14 refuelin outage with the removal of the-unit from'the grid at approximately 221 hours0.00256 days <br />0.0614 hours <br />3.654101e-4 weeks <br />8.40905e-5 months <br /> on R
. January 16,.1990. At approximately 1138 hours0.0132 days <br />0.316 hours <br />0.00188 weeks <br />4.33009e-4 months <br /> on February 23, 1990, Unit I reached criticality, and subsequently resumed -operation. The outage,
- originally scheduled for 32 days, was extended.to 38 days.
Unanticipated
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items which accounted-for the additional time included:.the discovery of
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loose bolting on the No. 12 steam generator (S/G) upper lateral support;
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partial core redesign; the lifting of a containment. spray suction relief valve i
during MOVATS testing; difficulties encountered in plugging No. 11 S/G hot leg
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tube located at Row 1/ Column 1; and the testing of the 11 accumulator check valves. Major accomplishments completed during this outage include the
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9003280319 900319 PDR ADOCK 05300282 O
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installation of a digital feedwater control system, overhaul of the low-pressure. turbines,100 percent eddy current testing of the S/G's, removal of suspect Westinghouse tube plugs and overheul of the rod control system.
During the entire outage the. licensee's actions can be characterized as.
thorough and conservative with impact on the outage schedule receiving minor consideration.
Unit 2 operated continuously at 100% power during this inspection period.
Unit 2.has reached 48 days of continuous operation at the end of the report period.
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Of the seven areas inspected, one violation of NRC requirements was identified.
During'a surveillance test, a technician removed power to control rod lift coils on the wrong unit. The root cause was personnel error.
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DETAILS
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Persons Contacted Licensee Employees j
- E. Watzl P l
- D.Mendele,lantManager General Superintendent, Engineering and Radiation Protection
- M. Sellman, General Superintendent, Operations i
G. Lenertz, General Superintendent, Maintenance i
- A. Smith, General Superintendent, Planning-and Services
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R. Lindsey, Assistant to the Plant Manager
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D. Schuelke, Superintendent, Radiation Protection i
G. Miller K.Beadell, Superintendent,OperationsEngineering Superintendent, Technical Engineering
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S. Schaefer, Superintendent, Technical Engineering
iM. Klee,in,perintendent, Quality EngineeringSupervisor, Security and Services Su R. Conkl M. Wadley, Shif t Manager G. Eckholt, Nuclear Support Services
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J. Leveille, Nuclear Support Services
- A. Hunstad, Staff Engineer
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t Denotes those present at the exit interview of March 2, 1990.
2.
Licensee Action on Previous inspection findings (92701)
Paragraph 2 of Inspection Report Nos. 282/89031 and 306/89031 documented the closure of Unresolved Item 282/89028-01; 306/89028-01 which examined the licensee's surveillance of the hot shutdown panels.
Further clarification by the licensee has revealed that all instruments associated with the hot shutdown panels are routinely calibrated. The licensee further
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stated that all of the local / remote switches are not tested in the local
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position. Pending further review of the acceptability of current testing practices of the local / remote switches, this issue is reopened as an Unresolved Item (Unresolved Item 282/90002-01;306/90002-01(DRP)).
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In response to the NRC Fitness for Duty (FFD) rule, the licensee is in the process of revising SP-1744, Semi Annual Emergency Organization
Augmentation Response Test. The purpose of this test is to determine the number of licensee personnel who would be available and the time required to respond to the plant once the individuals are notified. The planned revision will specifically ask the individual if they are able to respond to the plant ta king into consideration FFD and other personal responsibilities.
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The licensee notified the inspectors that Paragraph 7 of Ins)ection Report Nos. 282/8903) and 306/89031 incorrectly attributed t1e development of the FFD training to the licensee's corporate security department.
In actuality, FFD training was developed by the licensee's
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production training department, at the request, direction and review of
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corporate security. Practice training sessions were critiqued by corporate security and quality assurance departments for both Prairie
Island and Monticello.
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3.
Operational Safety Yerification (71707. 93702)
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Routine-Inspection
The inspector observed control room operations, reviewed applicable logs, conducted discussions with control room operators and observed i
shift turnovers. The inspector verified operability of selected i
emergency systems, reviewed equipment control records, and verified l
the proper return to service of affected components, conducted tours
of the auxiliary building, turbine building and external areas of
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the plant to observe plant equipment conditions, including potential fire hazards, and to verify that maintenance work requests had been
initiated for the equipment in need of maintenance.
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Unit 1 Startup from Refueling On February 23, 1990, at approximately 1138 hours0.0132 days <br />0.316 hours <br />0.00188 weeks <br />4.33009e-4 months <br />. Unit I reached criticality, commencing cycle 14 operation. The inspector monitored the licensee's approach to criticality and portions of zero power l
physics testing.
Testing of the new digital feedwater system was
conducted at 6 and 12 percent reactor power.
Unit I was originally placed on line at 0000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> on February 25, 1990.
During testing for the recently installed l
digital feedwater system, problems were encountered with both main
feedwater regulation valves, forcing the unit (turbine generator)
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off line at approximately 1925 hours0.0223 days <br />0.535 hours <br />0.00318 weeks <br />7.324625e-4 months <br />. During repairs, the reactor I
was maintained at approximately 1% reactor power using the
-atmospheric steam dumps. Both main feedwater regulation valves experienced valve stem separation from both the valve plug and the
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actuator. The main feedwater re containment isolation functions.gulation valves do not provide The inipector monitored the repair i
and recalibration of the valves.
The unit was placed back on line
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at approximately 0518 hours0.006 days <br />0.144 hours <br />8.564815e-4 weeks <br />1.97099e-4 months <br /> on february 27, 1990, and power ascension occurred without incident.
Root cause for the stein separation from the plug and the actuator was attributed to a loose fit in the stem to actuator coupling,
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and failure to torque the stera into the plugs as specified by I
the vendor manual. Other instances of non-safety related maintenance being performed without the aid of vendor manuals or vendor / industry accepted torque values was previously noted in Paragraph 4 of Inspection Report 50-282/89003(DRP)and 50-306/89003(DRP),and
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Paragraph 4 of. Inspection Report 50-282/89017(DRP)and 50-306/89017 (DRP).
The inspector will continue to monitor licensee activities in this area.
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Auxiliary Building Special Vtnt11ation_ Zone Integrity (ABSVZ)
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On February 13, 1990, the inspector obtained from the control room a I
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copy of the ABSVZ log and performed a walkdown of the ABSYZ boundary.
This walkdown showed that current openings were appropriately i
documented on the log sheet. The inspector questioned the opening
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created by removal of a blank flange, and subsequent installation of i
the eddy current cable connection flange. This modified flange is
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placed on the containment vessel pressurization line to allow
passage of eddy current cabling from the auxiliary building to the i
containment. The licensee has provided documentation of the
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administrative control of this opening. This matter is unresolved pending inspector review (282/90002-02(DPP)).
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Secure / Hold Card Tags
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The inspectors accompanied licensed operators on tours of containment after the reactor coolant system had reached operating l
pressure and temperature. This tour was designed to identify any j
sources of leakage which would need to be corrected prior to
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startup. This tour was performed after SP-1750, Post Outage
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Containment Closeout inspection, Revision 3.
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SP-1750 is to ensure materials that could reduce safeguaids systems operation / performance are removed from containment.
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course of this tour, two hold cards were located in containment.
The hold cards were found on new root valves for future level
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transmitters. The isolation, which permitted the valve installation
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and was part of the original work package, was correctly restored with the hold cards removed. Ar, additional isolation was created
for the new root valve which was not cross referenced to the original work package.
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Two additional cards were found by licensed operators on a previous tour. One secure card was found on top of a breaker box and not
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affixed to intended component, the polar crane knife switch.
Following discussions with the licensed operators, the inspectors
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concluded that the high frequency of polar crane secure tag's installation / removal accounted for the trg not being properly hung.
The second card, a hold card, was placed on the refueling crane.
All four cards were correctly accounted for in the control room open hold / secure tag books as being active. The licensed operators verified that the cards were no longer needed, removed the cards from containment and closed out the hold / secure log entries.
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action was appropriate.
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During a general tour of the plant by the inspector a secure card
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was discovered on Bus 13, Cubicle 6.
This breaker cubicle was originally a feed to the substation and is currently labeled as a spare with the substation feeder cables removed.
Review of secure card log indicated that the card was removed on March 22, 1989.
The licensee corrected the anomaly.
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l The licensed operators have suggested that SP-1750 be revised to ensure that hold / secure cards found in containment during the closeout inspection are identified and appropriate action
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ta ken. The ins)ector considers the licensee's secure / hold card program to be tiorough and usage to be effective. The inspectors note thousands of tags were placed and removed during this refueling outage. However, additional emphasis, as indicated by the above findings, can be utilized to ensure that 100 percent usage and card i
accountability is maintained at all tines.
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4.
MaintenanceObservation(71707,37700,62703).
Routine, preventive, and corrective maintenance activities were observed
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to ascertain that they were conducted in accordance with approved i
procedures, regulatory guides, industry codes or standards, and in
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conformance with Technical Specifications. The following items were j
considered during this review: adherence to limiting conditions for
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operation while components or systems were removed f rom service,
approvals were obtained prior to initiating the work, activities were accomplished using approved procedures and were inspected as applicable, functional testing and/or calibrations were performed prior to returning
components or systems to service, quality control records were
maintained, activities were accomplished by qualified personnel, radiological controls were implemented, and fire prevention controls were i
implemented. Portions of the following activities were observed.
FeedwaterRegulationValveRepairs(referenceParagraph3.b.).
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Containment Spray Pump Replacement (reference Paragraph 6.c.).
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' Steam Generator Support Bolt Replacement (reference Paragraph 6.d.).
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No violations or deviations were identified.
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5.
Surveillance (61726,71707)
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The inspector witnessed portions of surveillance testing of safety-related
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systems ard components, The insaection included verifying that the tests were scheduled and performed wit 11n Technical Specification requirements, by observing that procedures were being(followed by qualified operators, that Limiting Conditions for Operation LCOs)werenotviolated,that system and equipment restoration was completed, and that test results were acceptable to test and Technical Specification requirements.
Portions of the following surveillances were observed / reviewed during the inspection period:
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SP 1199 Overpressure Protection System Calibration, Revision 12.
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SP 1083 Unit 1 Response to the Safeguards Signal Test, Revision 12.
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ReaftorProtectionLogicResponseTesting, Revision 17.
SP 1008
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PE-0012-03T, 4.16KV Bus 12 Cubicle 3, 12 Feedwater Pump Electrical
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Maintenance - Test Tripping, Revision 3.
SP1174(20) Reactor Coolant System Hydrostatic Test, Revision 7.
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SP 1083. Unit 1 Response to Safeguards Signal Test
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This test inserts a safeguard signal with a coincident station blackout to initiate operation of the various safeguards com)onents.
All affected equipment responded satisfactorily.
It should ae noted i
that the actual performance of Sp 1083 was preceded by a planning j
meeting during which the participants' responsib111 tics and anticipated results were outlined. This planning meeting permitted
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the test to be conducted in an expedient and well coordinated
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manner.
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SP1174(20), Reactor Coolant System (RCS) Hydrostatic Test This test.is conducted to ensure the integrity and leak tightness of
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the reactor coolant system. This surveillance also examines back
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leakage through the series double check valves which isolate the RCS from the Residual Heat Removal (RHR) and Safety Injection (SI)
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systems. As a result of excessive leakage across SI-6-4, outboard
accumulator check valve, noted during the performance of SP-1269,
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Accumulator Check Valve Leak Test, Revision 2, an additional
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surveillance was conducted via the work request process to further assess the back leakage across SI-6-4.
With RCS pressure at
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2280 psig. MV-32071, No.11 Accumulator to Cold Leg Isolation Valve
was closed at approximately 2216 hours0.0256 days <br />0.616 hours <br />0.00366 weeks <br />8.43188e-4 months <br /> on February 21, 1990. The section of pipe between MV-32071 and $1-6-4 was then depressurized
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and monitored 1or leakage. While activities associated with
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back leakcge were being conducted, licensed operators became
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concerned with the length of time the testing was taking and the i
T.S. requirements on accumulator operability.
T.S.(Safety Injection)3.3.A.2.cstatesthatduringstartupoperation one accumulator may be inoperable for one hour whenever pressurizer
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pressure is greater than 1000 psig, provided startup operation is t
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If operability is not
restored within the time specified, the requirements are to be in at
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least hot shutdown within the next six hours, and in cold shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. Approximately 56 minutes after the
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initial closure of HV-32701, the shift su)crvisor ordered the testing halted and MV-32701 reopened to restore tle accumulator to operability.
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T.S. requirements of 1270(+/-20) cubic feet. The accumulator water level was restored and the accumulator declared operable at approximately 2335 hours0.027 days <br />0.649 hours <br />0.00386 weeks <br />8.884675e-4 months <br />.
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Additional testing for back leakage across SI-6-4 placed the 11 accumulator out of service at 1012 hours0.0117 days <br />0.281 hours <br />0.00167 weeks <br />3.85066e-4 months <br /> on February 22, 1990.
r At approximately 1110 hours0.0128 days <br />0.308 hours <br />0.00184 weeks <br />4.22355e-4 months <br /> the licensed operators were unable to reopen MV-32071. Troubleshooting determined that the seal-in circuitry had f ailed. Licensed operators held the control switch in
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the open position thereby opening the valve. The accumulator was declared operable at 1145 hours0.0133 days <br />0.318 hours <br />0.00189 weeks <br />4.356725e-4 months <br />. Work request was initiated and the problem corrected.
Licensee review determined that thernal gradients between the check valve seat and disc and the resulting differences in thermal growth were the reason for the back leakage. Once plant heatup was completed, the back leakage ceased.
Review of the licensee's actions and T.S. 3.3.A.2.e confirmed that the limiting conditions of operation were not exceeded.
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SP-1546. Rod Drive Mechanism Timing Test (COLD)
On February 21, 1990, the licensee was conducting SP-1546. Rod Drive Mechanism Timing Test, Revision 8.
This procedure verifies the proper timing of each full length Control Rod Drive Mechanism with a Rod Control Cluster Assembly attached. The procedure requires one rod in a group to be cycled with the remaining rods disconnected.
The lift disconnect switches are located behind the main control boards in a small cabinet. The IAC technicians conducting this surveillance incorrectly entered the Unit 2 rod lif t coil disconnect -
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cabinet and disconnected the rods not being tested. When the aroser
test response was not obtained, an investigation was started w11c1 determined that the IAC technician entered the Unit 2 rod disconnect
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cabinet instead of the Unit I cabinet. The shift supervisor immediately directed the rod disconnect switches restored and SP-1546 suspended until the situation could be completely assessed.
In response to this event, the licensee has installed padlocks on
u ch of the rod lift coil disconnect cabinets. Each cabinet has a
padlock opened by a different key. The padlock keys are kept under
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administrative control in the shift supervisors office. Although
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the Unit 2 disconnect switches were moved to the disconnect position,
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the control rods never lost their ability to trip the reactor, and
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actual rod position was unaffected.
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i Technical Specification 6.5, Plant Operating Procedures, requires:
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Detailed written procedures, including the applicable checkoff lists and instructions, covering arear listed below shall be prepared and followed:
Technical Specification 6.5.A, Plant Operation, requires that:
Surveillance and testing requirements that could have an effect on
nuclear safety be accomplished.
- On February 21, 1990, technicians deenergized Unit 2 control rod lift coils rather than Unit 1 as required by Procedure SP-1546. The apparent
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root cause was personnel error which was induced by the lack of cabinet labeling and the experience level of one technician involved. During
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inspector review and closeout of the violation response, root cause will be analyzed in detail. This is an apparent violation of NRC requirements (282/90002-03(DRP)).
Prior to the initiation of SP 1546, the reactor trip breakers must be r
closed in order to withdraw rods. The licensee encountered difficulties closing both reactor trip breakers for Unit 1. - following a cleaning of electrical contacts the breakers closed. The inspectors will follow this problem and will observe future cycling of these breakers during monthly reactor protection functional testing. During these tests the reactor trip breakers are actually cycled while rod control power is supplied by the reactor trip bypass breakers.
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RefuelingActivities(60710)
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Refueling Activities Observation The inspectors observed two shifts of refueling activities. The insSectors confirmed that:
core monitoring was in accordance with Tec1nicalSpecification(TS) requirements;fuelaccountability methods were in accordance with the fuel shuffle procedure; vessel and spent fuel pool water levels were maintained as required; and, boron concentration and boron flow path availability were checked on
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a per shift basis. The inspectors also confirmed that the TS required staffing was maintained, and that 1/m plots were updated with each fuel assembly insertion. Adequate radiation protection controls were observed in the refueling and spent fuel pool areas.
Provisions to protect against foreign objects falling into the open reactor vessel were adequate, b.
Damaged Fuel Assembly The inspectors reviewed activities related to the sipping and possible reconstitution of a fuel bundle that had been determined to contain leaking fuel rods. On January 31, 1990, a fuel assembly was identified as a " leaker" during sipping operations.
The assembly, Q-9, was a "once burnt" Westinghouse assembly.
The licensee performed an ultrasonic examination of the individual fuel rods to determine whether or not any of the fuel rods contained water which would be evidence of a loss of clad integrity. The ultrasonic testing indicated that two adjacent fuel rods contained water and the licensee made plans to reconstitute the fuel fuel assembly by replacing the failed fuel rods with rods made of 100 percent Zircalloy. The licensee began preparations for the reconstitution activities that included an initial close-up inspection with an underwater camera to assess the material condition of the assembly and detect any imperfections that would have prevented the insertion of the assembly into the fuel repair basket. While performing the visual inspection, the licensee noted a foreign object protruding from the bottom of the fuel assembly. Further investigation revealed this object to be a shovel nosed chisel.
The location of the chisel was directly adjacent to the two failed rods, inserted through the bottom nozzle plate.
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i The licensee convened an Operations Committee (OC) meeting to determine a plan of action. There was considerable concern about-the other two adjacent fuel rods that had no indication of failure,
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but could have been damaged. The licensee considered removing the
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two leaking fuel rods and visually inspecting the other two. After
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further discussion, the licensee decided to remove the Q-9 fuel
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assembly, and the three other symmetrical assemblies. These i
four assenblies were off loaded and the core load.was redesigned
using four "twice burnt" fuel assemblies. The reshuffle to
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accomplish this was completed on February 2,1990.
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The preliminary review indicates two possible scenarios for the j
source of the chisel:
(1) the chisel was-dropped during past t
installation of steam generator nozzle dems and reactor coolant flow then passed the chisel to the bottom of the core and lodged the tool in the bottom of the fuel assembly; or (2) at some time in the past
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the chisel was dropped into the spent fuel pool, and during i
subsequent fuel handling operations, the chisel became lodged in the assembly when the assembly was setdown in the spent fuel pool. The
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licensee continues to investicate the root cause of the foreign
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objectpresentintheQ-9fuelassembly. The inspectors will review the licensee's investigative report for root cause analysis and i
corrective action. Open Item 282/90002-04(DRP).
The inspector also attended OC meetings on January 18 and 19, 1990,
end observed the reviews made on various plant procedures and i
proposed modifications. Good engineering judgment and safe, conservative operating practices were observed in all discussions, c.
Lifting of Containment Spray Suction Relief Valve f
On February 15, 1990, the licensee was conducting MOVATS testing on
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the 12 Containment Spray (CS) Pump Discharge Valve, MV-32105. Plant parameters included reactor coolant system temperature at
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approximately 160 degrees F and 359 psi with the RHR system in
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operation. When MV-32105 was manually stroked as p. art of the MOVATS
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testing, the 12 CS suction relief vehe lifted and Degan discharging
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to the floor drain. The operators ettempted to manually close down on the 12 CS suction valve from the RHR system, MV-32097. Concurrent with this activity, operators manually realigned the RHR system in order to isolate MV-32097 and opened the 12 CS min flow line to the RWST which allowed the relief valve to reseat. The licensee determined that approximately 1000 gallons of water was drained from the reactor coolant system with approximately 70 gallons going to the aerated sump tank via the relief valve and floor drain and the remainder returned directly to the RWST via the min flow line. At all times throughout this event RHR system flow was maintained.
Additionally, the Reactor Coolant system did not experience a
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temperature rise.
Subsequent maintenance activities replaced the MV-32097 valve discs and bench tested the relief valve and determined it to be operating correctly.
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Steam Generator Upper Latera1' Support Bolts l
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During this refueling outage the licensee continued to gather _
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baseline information for its ongoing erosion / corrosion study. Other examinationactivitiesincludedtheInserviceInspection(ISI)
program and S/G eddy current testing.
The ISI program conducted approximately 446 exams of which 22 required rework.
ISI discovered i
one loose bolt on the No.12 Steam Generator (S/G) upper lateral i
support. The upper lateral support is designed to limit S/G l
movement during a seismic or pipe rupture event, with a pipe rupture event being the most severe. The upper lateral support is located near the S/G's center of gravity below the transition cone.
i Additional inspection by the licensee determined that additional bolts on the upper lateral support, while not loose, were not
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tightened to the original design loading of 390 kips. Loading the
bolts to the specified value of 390 kips would have caused an elongation of.020 of an inch. Th~e additional inspection by the
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licensee:1dentified several bolts which were elongated.002 of an
inch. Preliminary calculations by the licensee have determined that i
the as found condition was acceptable due to the shear strength of the bolting material being greater than the shear loads imposed during accident conditions. Preliminary _ review by the licensee of the upper lateral support joint design indicates that the joint does i
not rely on frictional forces imposed by bolt tensioning to provide
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the joint with its shear strength. The inspector monitored the removal, cleaning and retorqueing of several bolts on the 12 S/G.
t The licensee has retorqued all bolts associated with the upper lateral support on both the 11 and 12 S/G. The licensee plans to
examine and retorque the upper lateral supports on the 21 and 22 S/G
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during the Unit 2 fall 1990 outage.
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During the course of the refueling outage, both S/G were 100% eddy current tested. As a result of problems associated with Westinghouse questionable heat tube plugs, the licensee removed 96 tube plugs.
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From this number, 26 tubes were able to be sleeved and returned to service. Difficulties were encountered in the replugging of the tube in Row 1 Column 1 in No. 11 S/G hot leg. A bur was raised on the tube during the removal of a questionable heat plug, which prevented the insertion of a mechanical plug. The licensee reamed the inside of the tube and inserted a mechanical plug. All other aspects of the eddy current testing and tube sleeving and plugging proceeded smoothly.
- The inspector observed Unit I steam generator manway removal and associated activities in the preparation for eddy current testing.
Appropriate radiation protection and safety practices were observed.
For additional information concerning the NRC inspection of the licensee's ISI activities, refer to Inspection Report 282/90003(DRP).
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Regional Initiative Steam Generator Safety Relief Valves The system engineer contacted the manufacturer regarding the accuracy
of the conversion value used during the testing of the Dresser Safety
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Relief Yalves. The inaccuracy of the conversion value used at other
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nuclear plants with Dresser Valves prompted the inspector's question.
The conversion value is used to correlate the pressure on the hydroset testing device, which causes the safety relief valve to lift, to the
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steamline pressure which would cause the safety relief valve to lif t. -
Adjustments are made as necessary to ensure that the safety relief valve lifts at the required set points.
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The licensee had used a linear graph to determine the coaversion value of.350. The vendor modified this value to.352 following discussions with the licensee. This change was minor and resulted in a change of
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calculated relief steam pressure of approximately 1 psig.
The system
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engineer recalculated the relief setpoints for all affected valves on Units 1 and 2 and verified that the existing relief setpoints are all l
within the required acceptance criteria. The licensee's test procedures are being revised to utilize the most current conversion value.
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8.
IE Bulletins'(92703)
(Closed) Bulletin 89-03: Potential Loss of Required Shutdown Margin During Refueling Operations. The inspector reviewed the licensee's I
internal correspondence, draft response to this bulletin, and met with the nuclear engineers to discuss the subject and the licensee's training. The inspector also attended the operating comittee meeting in which the draft i
response was discussed. The licensee's formal response to this bulletin
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dated January 29, 1990, was also reviewed. Throughout all of the
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inspector's reviews, the licensee's actions and responses were found to be acceptable. This item is closed.
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9.
Temporary Instructions (71707)
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(Closed)TI 2515/93: Multiplant Action (MPA) Item B-03 PWR Hoderator Dilution.
In a September 15, 1977, letter, Operating Reactors Branch No. 2, Division of Operating Reactors (D9R), requested the licensee to evaluate a recent boron dilution incident to see if it or any similar event could cause a dilution accident more severe than those described in the FSAR. The licensee performed the requested analysis and responded in their letter of November 7,1977, that any such accident would be
" extremely remote" and that no changes to the existing procedures were necessary. On January 26, 1979, Reactor Safety Branch, DOR, requested Operating Reactor Branch No. 4, DOR, to request the licensee to verify
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that no single failure or operator error could cause a boron dilution accident. At the staff's request, the licensee responded to the Director of NRR on April 17, 1979, that their re-evaluation confirmed the above.
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In a April 3,1980, memorandum from. the Reactor. Safety Branch, DOR, to the I
Operating Reactors Branch No. 4, the submittals were found to be acceptable.
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r The inspector reviewed all the above documentation, discussed it with the i
licensee, and found the responses to be acceptable. This item is closed, t
10. Licensee Event Reports (LERs) (92700)
(0 pen)LERs 306/90002: Excessive Pressurizer Cooldown Rate. On January 17, 1990, Unit I was shut down for the Cycle 13-14, refueling
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outage. On January 19, 1990, review of the cooldown data showed that the
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cooldown rate of the pressurizer had exceeded the Technical Specification limit of 200 degrees F/hr., and the temperature difference between the pressurizer auxiliary spray and the pressurizer had exceeded the Technical Specifications limit of 320 degrees F.
The licensee made this determination based on a gathering of temperature indications on the
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pressurizer at two minute intervals, for a 36 hour4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> )eriod. The licensee
has initiated a fatigue and fracture analysis for t1e event.
l The Licensing Project Manager (LPM) has reviewed the LER, and has requested additional information regarding past cooldown cycles for both
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units. The LPM will consider past cooldown data and practices during the
review of the fracture analysis and LER.
Inspection resolution of this LER will be conducted by the LPM.
11.
Unresolved items Unresolved Items are matters about which more information is required in
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order to ascertain whether they are acceptable items, violations, or deviations.
Unresolved Items are discussed in Paragraphs 2 and 3.C.
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12. ExitMeeting(30703)
The inspectors inet with the licensee representatives denoted in Paragraph I
l at the conclusion of the report period on March 2,1990. The inspectors discussed the purpose and scope of the inspection and the findings. The
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inspectors also discussed the likely information content of the inspection report with regard to documents or processes reviewed by the
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inspector during the inspection. The licensee did not identify any documents or processes as proprietary.
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1
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