IR 05000298/1989018
| ML20246A719 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 06/15/1989 |
| From: | Bennett W, Constable G, Greg Pick NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20246A714 | List: |
| References | |
| 50-298-89-18, NUDOCS 8907070069 | |
| Download: ML20246A719 (10) | |
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APPENDIX B U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
NRC Inspection Report: 50-298/89-18 Operating Licelise: DPR-46 Docket: 50-298 i
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Licensee: Nebraska Public Power District (NPPD)
P.O. Box 499 Columbus, Nebraska 68602-0499 Facility Name: Cooper Nuclear Station (CNS)
Inspection At: CNS, Nemaha County, Nebraska
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Inspection Conauttid-Ap *1 16-May 31, 1989 Inspcctors: -
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17889 G. A. Pfyk(kstdent Inspector, Project Section C,
' Date Divis1on of Reactor Prcjects l
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W. R. Bennett, Senior Resident Inspector, Project Date'
Section C, Division of Reactor Projects
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Approved:
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G. LTtonstatAF,~~ Chief, Project Section C, Division Date ~
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of Reactor Projects 8907070069 890622 PDR ADOCK 05000298 g
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Inspection Summary
' Inspection Conducted April 16 through May 31, 1989 (Report 50-298/89-18)
Areas Inspected: Routine, unannounced inspection of plant status, operational safety verification, monthly surr.illance and maintenance observations, installation and testing of modifications, Ond refueling activities.
lResul'r s: The NRC inspectors observed that plant activities were controlled.in a sdre, conservative manner. The licensee was researching methods to-reduce the number of inadvertent engineered safety features (ESF) actuations. A need exists for long-range scheduling of design modifications which would allow for field walkdowns under favorable plant conditions. The licensee briefed NRR and'
the resident inspectors on their method of core reloading.
Witnin the areas inspected, two apparent violations were identified (failure to follow a safety procedure, paragraph 3, and inoperable reactivity. control
- system, paragraph '4).
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i-DETAILS
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- Persons Contacted Principal Licens'ee Employees
+*G. ' R. Horn, Division Manager of Nuclear Operations
- V. L. Wolstenholm, Division Manager. of Quality' Assurance
+ J. M. Meacham, Senior Manager, Technical Support
-+*E. M. Mace,' Engineering Manager
+*R. L. Gardner, Maintenance Manager
+ R. A. Jansky, Outage and Modification Manager
+ G. E. Smith, Quality Assurance Manager i'
.+ J. Sayer, Radiological Manager
+*H. T. Hitch, Plant Services Manager
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+ R.- Brungardt, Operations Manager
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- D. R. Robinson,- Quality Assurance Acting Manager
. + R. D. Black, Operations ~ Supervisor
- R. L. Beilke, Radiological Support Supervisor
+ P. L. Ballinger, Operations Engineering Supervisor
- L. E. Bray, Regulatory. Compliance Specialist NRC-
- M. E. Murphy, Reactor Inspector
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+ Denotes those present 'during the pre-exit interview conducted on May 22, 1989.
- Denotes those present during the exit interview conducted on June 9,1989.
The NRC inspectors also interviewed other licensee employees and contractors during the inspection period.
2.
Plant Status-
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The plant remained shut down, undergoing its 12th core reload. The core was completely off-loaded and reloaded during;this period.
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3 Operational Safety Verification (71707)
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The NRC inspectors observed operational activities throughout the inspection' period.
Proper control room staffing was maintained and control room activities and conduct were observed to be well controlled.
The NRC inspectors observed selected shift turnover meetings and noted that information concerning plant status was properly communicated to the oncoming operators.
Control room access was controlled during the outage.
Discussions with operators determined that they were cognizant of plant status. Limiting Conditions for Operations were properly entered when
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equipment was declared inoperable for maintenance, and acceptance testing was properly performed and reviewed prior to declaring equipment operable.
During a control room tour on May 18, 1989, the NRC inspector observed that MS-M0-77, the main steam line drain outboard isolation valve indicated shut. The valve was danger-tagged "open" by Cleurance Order (CO)89-442.
When the NRC inspector questioned the control room operators, they immediately opened the valve. The valve apparently had automatically shut when a Group 1 isolation was inserted for testing about 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> previously.
During a review of CDs on May 21, 1989, the NRC inspector found several examples, including CO 89-827, which utilized one tag to isolate several valves for performance of maintenance. CNS Procedure 0.9, " Equipment Clearance and Release Orders," Revision 7, dated February 23, 1989, specifies that the C0 procedure is to provide a means of safely isolating equipment for repairs which requires that the equipment not be in service or used without the knowledge of the person workino on that particular piece of equipment.
In this case, the position of the valve was not controlled,- therefore, the equipment was not isolated as recuired by the procedure.
In addition, the use of one tag 10 isolate multiple valves does not appear to meet the intent of the procedure in tnat assurance that equipment is isolated cannot be provided unless the valve position is specified at each boundary valve.
In cases where electrical signals, or other remote means, may affect valve position, then that signal should also be disabled and tagged. The above weaknesses in your tagging program led to an apparent violation (298/8918-01) of CNS Procedure 0.9.
During the outage, a number of engineered safety feature (ESF) actuations occurred due to pce!.onnel error. Three of the ESF actuations resulted in containment group isolations and one resulted in inadvertent injection of water into the reactor vessel by a core spray pump. Of particular concern was the recurrence of actuations which occurred during the previous outage. The repeat occurrences were the inadvertent injection of water into the vessel by a core spray pump and Group II, III, and VI isolations due to loss of ground to relays.
In both instances, the safety consequences to the plant were minor; however, actions taken to prevent recurrence had not been fully effective.
Discussions were conducted with licensee management regarding the actions taken to prevent recurrence. Management recognized the problem and stated that a team was researching methods to prevent recurrence and reduce the number of ESF actuations.
The NRC inspectors verified that selected activities of the licensee's radiological protection program were implemented in conformance with facility policies, procedures, and regulatory requirements. Radiation and/or contaminated areas were properly posted and controlled. Health physics personnel were prompt in reposting radiation areas affected by the shutdown. Radiation work pemits contained appropriate information to ensure that work could be performed in a safe and controlled menner.
Health physics personnel were observed to be touring work areas, ensuring
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i proper implementation of ALARA and radiological control requirements.
Radiation monitors.were properly utilized to check for contamination.
K The NRC inspectors observed security pers9nnel perform their duties of-vehicle, personnel, and packrga search. Vehicles were properly authorized and controlled or escorted within the protected area. The NRC inspectors conducted site tours to ensure that compensatory measures were properly implemented as required. The licensee continued impbmentation of the security equipment upgrade.
Personnel access was observed to be controlled in accordance with established procedures. _ Interviews with security
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personnel demonstrated that they were cognizant of their responsibilities.
The PA barrier had adequate illumination and the isolation zones were free of transient materials.
Problems. identified concerning the clearance order program were discussed with the. licensee. The licensee was actively trying to reduce the number of inadvertent ESF actuations which were occuring.
No other violations or deviations were identified.
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Monthly Surveillance Observations (61726)
The NRC inspectors observed and/or reviewed the performance of the following surveillance procedures (SP):
SP 6.3.8.4, "SLC Manual Initiation Test Tank to Reactor Vessel,"
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Revision 16, dated March 30, 1989. This test was performed on May 12 and 15, 1989, to meet TS 4.4.A.1.c requirements for verifying Standby Liquid Control (SLC) System availability. When p6rforming the test on May 12, the SLC "A" Squib Valve. failed to fire. The test was terminated and immediately performed for the "B" Squib i
Valve. The "B" Squib Valve was fired successfully. The licensee investigation into the "A" Squib Valve failure determined that a
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strand of copper wire was found interconnecting the pins of the
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firing mechanism, preventing current from flowing through the firing i
mechanism, thereby disabling the valve. The wire was apparently intentionally installed during installation of the anticipated-transient without scram (ATWS) modification (Design Change 86-034A) in May 1988. The licensee further determined that the reason the wire was left in place was inadequate instructions in the design change package.
Improper activities associated with performance of the I
design change lead to operation of the SLC-system with an inoperable l
squib valve which is an apparent violation of TS 3.4.b.1 (298/8918-02). SP 6.3.8.4 was successfully completed after i
replacement of the "A" Squib Valve on May 15. The NRC inspector j
reviewed all performances of SP 6.3.8.4.
SP i.2.2.4.1, "CS Loops A and B Flow Instruments Calibration and i
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Functional Test," Revision 21, dated August 11, 1988. This test was l
performed to verify operability of the core spray flow transmitter.
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The transmitter had been modified through Design Change (DC)89-036.
The DC added vents to the instrument to allow for better response.
A calibration check and subsequent calibration were performed, since the setpoints were not in their required tolerance band. The technician was knowledgeable about the purpose of the design change.
He conducted the calibration in accordance with procedures and followed proper radiological practices.
The licensee took prompt corrective action to identify and correct the failure of the "A SLC Squib Valve to fire.
No other violations or deviations were identified.
5.
Monthly Maintenance Observation (62703)
On May 8,1989, the NRC inspector observed performance of Preventative MaintenanceProcedure(PM)01452. The PM involved a calibration check and calibration of the trip instrument for tripping the diesel generator fuel oil booster pump on high pressure. The PM for this instrument is required every 24 months. The PM was conducted in accordance with SP 14.5.1, " Instrument Calibration Data Sheets," Revision 3, dated September 1, 1988.
The NRC inspector also observed a.plementation of the emergency diesel generator (EDG) annual inspection and overhaul. This activity is controlled by SP 6.3.12.6, " Diesel Generator Inspection," Revision 22, dated February 20,1989; SP 7.2.53.1, " Diesel Generator Engine Mechanical Inspection," Revision 0, dated October 27, 1988; and SP 14.17.2,
"DG-2 Annual Inspection," Revision 0, dated October 22, 1988.
After disassembly of the components, the mechanics inspected them for wear and/or damage. Components were replaced as needed. The instrument and control (I&C) technicians did component testing to assure that they actuated at the proper setpoints, with adjustments being made as necessary.
Credit was taken this year in SP 14.17.2 for testing conducted on components which were installed in the new instrument racks under the EDG design modifications. Proper safety precautions were taken.
All activities were conducted in accordance with procedures.
On May 22, 1989, the NRC inspector observed troubleshooting of reactor protection system (RPS) "B" control cabinet. The motor generator output breaker failed to tie onto the bus after it had tripped off on overvoltage. The output breaker and some burnt auxiliary contacts had been replaced. Further troubleshooting revealed that the voltage adjustment potentiometer in the control cabinet was intermittent. After i
l cleaning the potentiometer, the "B" RPS motor generator output breaker tied onto the output bus. Discussions with the electrician revealed that he was cognizant of the types of problems which might prevent the motor generator from tying onto the output bus.
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The NRC inspector observed in part, the 10-year Pli on the "B" Core Spray Pump. This activity was being implemented by General Electric employees.
-Clearances were verified to be within tolerances and the motor windings were revarnished. The disassembly, inspection, refurbishment, reassembly, and testing were conducted in accordance with procedures.
During the outage, PM activities continued. No major component failures were identified during the annual inspections of both EDGs. No
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6.
Installation and Testing of Modifications (37828)
The purpose of this inspection is to verify that design change installation and testing are in conformance with regulatory requirements.
The modification packages included 10 CFR 50.59 evaluations, purpose and scope of the modification', fire hazard reviews, and ALARA reviews. After completion of the installation, the design engineer signs a sheet confirming that the modification has been completed in accordance with the design package. The method used to make changes to modification packageinstallationstepswasanon-the-spotchange(OSC). Additionally, OSCs were used to alter postmodification test steps when the test could not be conducted as planned.
BothNPPDpersonnelandPowerPlantMaintenance(PPM) personnel,an outside contractor. were used to implement the various modifications. The employees were hired based on the licensee's needs to complete the required activities and their personal skills.
In addition to general employee training, specific training was provided to selected PPM employees in the following areas:
instrument tubing and fittings, fire seals and grouting,
Raychem and Okonite splices, environmental qualification, mechanical measuring and test equipment, torquing, control rod drives, and other types of work activity courses.
The NRC inspectors toured the facility and observed portions of modification installation and testing. The verifications included confirmation that the work was accomplished in accordance with instructions and drawings contained in the modification package.
Installed hardware was reviewed to verify it conformed to as-built drawings. Selectively verified were equipment model numbers, dimensions, materials, and configurations.
While observing postinstallation testing, celective examinations of the t
following were conducted as appropriate: wiring continuity, termination integrity, and separation checks; cleaning and flushing; calibration of instrumentation; hydrostatic pressure testing of fluid systems; component functional testing; filling and venting; adjustment of limit switches, interlocks and stops; and required preventative maintenance.
Some of the design changes observed being implemented and/or tested included:
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Replacement of the transfonners connected with RPS Trains "A" and "B"
EDG tubing replacement and instrumentation upgrade
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Annunciator upgrade Feedwater pump turbine controls changeout Replacement / upgrade of the 250 Vdc batteries
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One of the more' involved and complicated of the DCs was the combination of the tubing replacement and upgrade of the instruments for the EDGs.
The copper tubing was replaced by stainless steel tubing and the instruments and associated tubing was relocated from the EDG to instrument racks and heavy duty tubing trays to reduce vibration. The PPM personnel installing the tubing and fittings had received the required training.
Each tubing run had a preliminary as-built sketch prepared by the PPM personnel and final as-built sketches were to be prepared after the postmodification testing was completed.
Overall, the postmodification testing of the EDGs was satisfactory. Out of an estimated 900 swagelock fittings installed on EDG No. 2, 4 had to be replaced and 60 required further tightening. During the acceptance testing, several OSCs had to be written to allow for the testing to be implemented. Each OSC corrected multiplc discrepancies. Additionally, the I&C technicians conducting the testing haa prior experience with the diesel electrical circuitry and pneumatic circuits. Their familiarity with the field cc, figurations and working of the circuitry made a significant contribution to the resolution of problems which occurred during testing.
Problems in the electrical acceptance test were exemplified by differences in labeling of the components and the title printed in the test procedure.
At one point relays were paralleled with another circuit. This prevented the relays from " dropping out" as required in the test procedure. Other steps had relays picking up when they should have dropped out.
The I&C technicians recognized the discrete sections in the test; however, it was apparent a thorough reading had not been conducted by the lead
technician in that he walked it through in the field. This was not a problem except that it slowed testing and pointed to the fact that he appeared to have not had sufficient review time prior to start of the testing. Another indication that the test procedure had not been reviewed thoroughly prior to start was the fact that, at a certain step, it was not recognized that three stop watches were needed, although it was clearly specified in the test procedure.
From discussions with licensee employees, the NRC inspector determined that the test package and design change package had been written 3 years prior to the outage by a contractor engineering group. The engineers had utilized as-built drawings to design the EDG modifications and
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postinstallation testing without conducting any field walkdowns. The as-built drawings were an additional factor which complicated the testing.
The drawings were not accurate, since the licensee presently is undergoing an as-built drawing verification project which includes the EDGs.
Discussions with the_ licensee indicated that the design engineers are encouraged to conduct field walkdowns as plant operating conditions permit. Further discussions pointed out that shutdown conditions during outages provided the best opportunity for field walkdowns of design packages. The licensee stated that this was their goal.
Overall, the installation and testing of modifications was satisfactory.
There does exist a need for long range scheduling of design modifications.
This would allow for more extensive field walkdowns due to the greater
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accessibility of plant equipment structures and components.
No violations or deviations were identified.
7.
Refueling Activities (60710)
During the outage, verification was made of the operability of refueling equipment and other required systems. Housekeeping and loose object control were being maintained on the refueling floor. Staffing was maintained in accordance with procedures.
The NRC inspector observed portions of the core being reloaded into the reactor vessel. Communications were maintained among the refueling floor supervisor, the refueling bridge, and the control room. The reloading was condurted in accordance with procedures.
Refueling equipment was checked out each shift before refueling operations began.
Prior to the beginning of the core reloading, conference calls were held among the licensee, Nuclear Reactor Regulation (NRR), and the resident inspector to describe the licensee's planned method of reloading the core.
The licensee planned to begin the spiral reload from one of the source range monitors (SRM) and work to the center of the core, instead of from the center and spiral outward. The licensee stated this was more conservative and met the intent of the Technical Specifications, since the fuel remained " coupled" to a monitoring device.
No violations or deviations were identified.
8.
Exit Interviews (30703)
A pre-exit interview was conducted on May 22, 1989, and an exit interview was' conducted on June 9, 1989, with licensee representatives identified in paragraph 1.
During these interviews, the NRC inspectors reviewed the scope and findings of the inspection. Other meetings between the NRC inspectors and licensee management were held periodically during the
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inspection period to discuss identified concerns. The licensee did not l
identify as proprietary any information provided to, or reviewed by, the NRC inspectors.
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REPRODUCED COPY OF THIS
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COMPLETED TRACKING FORM
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WHD WILL CHECK THE 766 m Date(s):
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STATUS DELDW:
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[ 766 FORWARDED W/RPT.
INTERIN 766 FORWARDED tewed by Section Chief:
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766 HELD PENDING
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