IR 05000313/1990009
| ML20043C139 | |
| Person / Time | |
|---|---|
| Site: | Arkansas Nuclear  |
| Issue date: | 05/23/1990 |
| From: | Westerman T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20043C136 | List: |
| References | |
| 50-313-90-09, 50-313-90-9, 50-368-90-09, 50-368-90-9, NUDOCS 9006040113 | |
| Download: ML20043C139 (13) | |
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C APPENDIX
O.S. NUCLEAR REGULATORY COMMISSION
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. REGION IV
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Inspection; Report:
50-313/90-09 Licenses:.DPR-51
50-368/90-09-NPF-6
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Dockets: '50-313-
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50-368
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Licensee: Arkansas Power & Light Company (AP&L)
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P.O.-Box 551
Little Rock, Arkansas 72203 Facility Name:. Arkansas Nuclear One (ANO), Units 1 and 2
' Inspection At: ANO Site, Russellville, Arkansas h
' Inspection Conducted:
March 16 through April 30, 1990
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I Inspectors:
C. C. Warren, Senior Resident Inspector Project Section A, Division of Reactor Projects l
j R. C. Haag, Resident Inspector.
Project Section A, Division of Reactor Projects a
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'r T. F. Westerman, Chief, Project Section A-Bate /
Division.of Reactor Projects j
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l Inspection Summary-Inspection Conducted March 16 through April 30,1990 (Report 50-313/90-09:
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.50-368/90-09)
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.i Areas Inspected: Areas examined during the inspection included followup of-
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previously identified items, followup of events, operational safety
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verification, surveillance, and maintenance.
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'Results:
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General Observations - Poor health physics practices by a member of the Unit I l
operations staff were noted (Section 6.0).
- Management involvement in reviewing the adequacy of root cause determinations and corrective actions appears to be more effective.
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Weaknesses'
- Failure to incorporate all reactor engineering surveillances-into the comprehensive surveillance program is an apparent l
weakness in the program..
i Strengths-
- Good planning effort prior to the Unit I shutdown for the
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snubber' inspection resulted in a timely and successful planned
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outage.
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- Good planning efforts resulted in the successful ' replacement of defective piston pins-in Unit 2 Emergency Diesel Generator'2K4A (Section 4.1).
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1.
PERSONS CONTACTED N. Carns, Vice President, Nuclear Operations
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J. Yelverton, Director, Nuclear Operations
T. Baker, Technical Assistant to Plant Manager, Central P
D. Boyd, Nuclear Safety and Licensir.g Specialist M. Chitum, Unit 2 Assistant Operations Manager p?
K. Coci,es, Unit 2 Maintenance Manager R. Eddington, Unit 2 Operations Manager
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- E. Ewing, General Manager, Technical Support and Assessment
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- R. Fenech, Unit 2 Plant Manager i
- J. Fisicaro, Licensing Manager C. Fite,. Supervisor, in-House Events Assessment l
- L. Humphrey, General Manager, Nuclear Quality
- J. Jacks, Nuclear Safety and Licensing Specialist
- R. King, Plant Licensing Supervisor J. Kowalewski, Mechanical Engineer
- R. Lane, Manager, Engineering Standards and Programs
D. Mims, System Engineering Superintendent J. Mueller, Unit 1 Maintenance Manager T. Scott, Maintenance Engineer A. Sessoms, Plant Manager Central
- J. Vandergrift, Unit 1 Plant Manager C. Zimmerman, Unit 1 Operations Manager
- Present at exit interview.
The NRC inspectors also contacted other plant personnel, including operators, engineers, technicians, and administrative personnel.
2, PLANT STATUS l-Unit 1 operated at 80 percent power from March 16, 1990 through April 27, 1990,
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with the exception of a power reduction to 24 percent on April 7, 1990, for
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governor and throttle valve testing. On April 28, 1990, the unit was shut down-to perform a Technical Specification (TS) surveillance inspection of the reactor coolant pump snubbers.
The unit returned to 40 percent power operations on April 29, 1990, and then to 80 percent power operations on
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April 30, 1990.
Unit 2 operated at or near 100 percent power throughout the inspection period.
3.
FOLLOWUP ON PREVIOUSLY IDENTIFIED ITEMS (UNITS 1 AND 2) (92701 AND 92702)
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3.1 (Closed) Open Item (313/8804-03; 368/8804-04):
Implementation of
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design change control
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-4-This open iten concerned improvements in the control of the design change program ano the corresponding procedural change.
Previously, the inspector had reviewed the procedural changes, however, sufficient time did not allow for an evaluation of the implementation of these changes.
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During the recent Unit 1 midcycle outage and the Unit 2 refueling outage, the inspectors reviewed several design change packages (DCPs).
Adequate controls
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for the DCP development and implementation were evident. This item is closed.
3.2 (Closed) Open Item (368/8905-01):
Repair of emergency feedwater (EFW)
Valve 2CV-0714 During certain EFW system alignments, Flush Valve 2CV-0714 failed to fully close. This occurred only while attempting to close the valve with the EFW pump operating and with a differential pressure condition.
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operator were disassembled and no abnormal conditions were observed.
Engineering noted that during these attempts to close the valve, the pump discharge pressure was approximately 3400 psig, however, the maximum pump discharge during an EFW actuation would be 1228 psig. During subsequent tests, while maintaining 1300 psig discharge pressure, 2CV-0714 was satisfactorily stroke tested in both the c m and closed direction.
In addition, while operating the valve after twiembly and during the lowered discharge pressure, there were no indications of waterhammer noise.
Initially, the licensee reported a potential waterhammer occurrence due to noise observed while attempting to close the valve. While no definite cause of the noise has been identified, the licensee postulates that erratic movement of the valve, with flow through the valve, caused the noise. A subsequent walkdown inspection revealed no visual damage to the piping or supports. This item is closed.
3.3 (Closed) Violation (313/8828-01):
Failure to implement timely corrective action for reactor coolant system (RCS) unidentified leakage event During a previous review of this violation, all aspects of this issue had been
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resolved. However, during that review, the inspector noted the absence of the
TS leakage criteria which limits total RCS leakage to '10 gpm frcm Procedure 1103.13, "RCS Leak Detection." The inspector reviewed the recent revision to Procedure 1103.03 which now includes the 10 gpm total RCS leakage acceptance criteria. This item is closed.
3.4 (Closed) Violation (313/8825-01):
Failure to maintain correct valve position l
This violation involved the incorrect positioning of a manual valve during the tag out of a system for maintenance and the failure to comply with a procedure that resulted in an inadvertent valve actuation.
Both of these examples occurred during a refueling outage. The inspector was concerned that certain equipment control requirements that are used during normal power operation but are deleted during outages may have contributed to these examples of the valve misalignment.
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5-The licensee reviewed their controls for valve alignment during cold shutdown and refueling modes of operation. Attachment "F" was added to Unit 1 Procedure 1015.02, " Decay Heat Removal and LTOP System Control " to provide verification that the decay heat system is properly aligned.
This checklist is performed once per day.
A revision to Procedure 1915.038, " Unit 2 Operations Logs," was also made to include a shutdown roving log for use during Modes 5 and 6.
In addition, during the last Unit 2 refueling outage, the licensee implemented a list of vital equipment that was required to be operable. This was a dynaniic list and was changed based on plant conditions.
The licensee is currently proceduralizing the methodology used to control the vital equipment list.
This item is closed.
4.
FOLLOWUP OF EVENTS (UNIT 2) (93702)
4.1 Replacement of Piston Pins on Unit 2 Diesel Generator Job Order 811129 On March 14, 1990, the licensee received a 10 CFR Part 21 notification from Colt Industries which detailed the potential failure of upper piston pins in Fairbanks Morse, Model 38TD8-1/8 engines. The possible failure mechanism was
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bushing failure resulting from piston pin seizure within the bushing.
Increased friction caused by a change in piston pin surface finishing techniques was determined to be the root cause of two failures of commercial grade Fairbanks Morse 900 rpm opposed piston engines. Colt Industries had determined that the failure mode was only possible in the upper piston assemblies and that lower piston assemblies were not susceptible to this condition.
Information supplied by Colt Industries indicated that 34 piston pins with suspect surface finish had been supplied to AP&L in 1987.
The pins were supplied as both individual pins and as a part of complete piston assemblies.
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The licensee's technical support and assessment group performed a review of available documentation to determine how many suspect pins were installed in upper piston assemblies in the Unit 2 diesels. Available documentation showed that two pins had been installed in EDG 2K-4A and no suspect pins were installed in EDG 2K-4B. This evaluation was performed in a timely fashion and
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was thorough in scope.
All remaining suspect pins were located within the licensee's warehouse and p1;.ced in a quality assurance hold status.
These actions were completed on March 30, 1990, and the facts documented in licensee Condition Report CR-2-90-161.
Based on further discussions with the vendor, l
the licensee decided to replace the suspect piston pins at the earliest possible date. The vendor advised the licensee that operability of EDG 2K4A was not a concern because the engine had over 90 hours0.00104 days <br />0.025 hours <br />1.488095e-4 weeks <br />3.4245e-5 months <br /> of run time since W-installation of the suspect pins and the vendor believed that a failure due to pin seizwe was most likely to occur within the first 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> of run time.
The ifcensee decided to perform the replacement of the 12 upper piston pins in
{DG 2K4A, with the job to begin as soon as replacement parts and vendor tecMicians were available. The need to change out all 12 pins was due to the
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lack of accurate data detailing which 2 of the 12 upper piston assemblies contained the affected pins.
Planning for the pin replacement indicated that i
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-6-the physical work would take 24-30 hours with the postwork testing activities to take 30-36 hours.
The inspector reviewed the work procedure to replace the upper piston pins, Procedure 2409.256, and observed portions of the ongoing piston pin replacement. The inspector noted that the physical work was very well planned and executed and that the procedure was well detailed and easily understood.
The pin replacement activities were finished within the scheduled period.
The inspector also observed portions of the postwork operability testing. The testing was developed with vendor recommendations and included 15-minute runs at reduced speeds, with inspections between each increase in speed, until 900 rpm was reached followed by incremental loading, with inspections between runs, up to a final run of 110 percent of full load. All testing was completed satisfactorily and the diesel was declared operable prior to the expiration of the 72-hour TS action statement.
During the initial disassembly, the licensee noted that the main bearing end caps for Bearings 6, 7, and 8 had been interchanged. The vendor recommended to the licensee that the three main bearings be considered for replacement during the next outage and the licensee is currently evaluating this recommendation.
In general, the inspector found that the licensee performed very well throughout this endeavor and that the planning and communication between all involved parties was very good.
5.
FOLLOWUP OF BULLETINS (UNITS 1 AND 2)
(92701)
NRC Bulletin No. 90-01 addressed the loss of fill-oil in the transmitter manufactured by Rosemount.
The inspector reviewed the licensee's initial actions in response to this bulletin. The licensee identified that 144 Model 1153 Series B and D and Model 1154 transmitters manufactured prior to July 11, 1989, were installed in either safety-related systems or system installed in accordance with 10 CFR 50.62.
In addition, 16 of these transmitters were in Unit I reactor protection or_ engineering safety actuation systems and were from the manufacturing lots that have been identified by Rosemount as having a high failure rate due to loss of fill-oil. The licensee is pursuing the replacement of these transmitters as requested by the bulletin, however, the actual completion date has not been established.
The initial estimate for transmitter replacement is prior to or during the next refueling outage which will start in October 1990. As of May 1990, the licensee had not completed the documentation of the basis for continued plant operation with the 16 suspect transmitters in service, as requested by Bulletin 90-01.
The condition report which identified the need for a documented basis was written on April 9, 1990.
It does not appear that the effort given for the development and documentation of the basis was timely.
The inspector will review the basis when they are completed.
During review of recent calibration records for the 144 transmitters, the licensee identified that 10 transmitters exhibited drift in the calibration points that exceeded limits recommended by Rosemount.
Upon further review of
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~7-the calibration data, discussions with Rosemount personnel, and the establishment of operability criteria, the licensee determined that drift was not a true indicator of loss of fill-oil and that these transmitters were operable.
6.
OPERATIONAL SAFETY VERIFICATION (UNITS 3 AND 2) (71707)
The inspectors routinely toured the facility during normal and backshift hours to assess general plant and equipment conditions, housekeeping, and adherence to fire protection, security, and radiological control measures. Ongoing work activities were monitored to verify that they were being conducted in accordance with approved administrative technical procedures and that proper communications with the control room (CR) staff had been established.
The inspector observed valve, instrument, and electrical equipment lineups in the field to ensure that they were consistent with system operability requirements and operating procedures.
During tours of the control room, the inspectors verified proper staffing, access control, and operator attentiveness. Adherence to procedures and limiting conditions for operations were evaluated. The inspectors examined equipment lineup and operability, instrument traces, and status of control room annunicators.
Various control room logs and other available licensee documentation were reviewed.
After the last Unit 2 refueling outage (2R7), which ended in November 1989, the average leakage to the quench tank increased from 0.15 gpm to 0.40 gpm.
Since March 1990, leakage has averaged between 0.40 and 0.50 gpm with no increasing trend.
The licensee determined that the major portion of quench tank inleakage resulted from the pressurizer code safety relief valves.
Refurbished relief valves were installed in Outage 2R7.
Leakage from the relief valve (s) has been experienced during previous fuel cycles. The licensee has initiated several long-term action items to address and resolve the issue of pressurizer relief valve leakage.
The inspector questioned the licensee to determine if a maximum pressurizer relief valve leakage value which considered available pressurizer heater capacity had been established.
TS 3/4.4.4 requires that both pressurizer proportional heater groups be operable with the summed power consumption of the two heater groups greater than or equal to 150 KW. The TS BASES for 3/4.4.4 states that the 150 KW of heaters provides assurance that the heaters can be energized during loss-of-offsite power conditions to maintain natural circulation in hot standby. The inspector was concerned that pressurizer
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relief valve leakage could exist, which was less than the 10 gpm identified l
1eakage limit, but could exceed the heat addition capability of the
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proportional heaters. After reviewing this concern and other factors involving pressurizer relief valve leakage, i.e., quench tank temperature considerations
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and relief valve wear rate, the licensee set a limit of 1.0 gpm for pressurizer
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relief valve leakage. At the end of the inspection period, engineering had not
completed the documentation package to support the 1.0 gpm leakage limit. Upon completion, the inspector will review the documentation package and the implementation of the relief valve leakage limit.
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The inspector observed the addition of oil for the Unit 1
"B" containment spray pump motor and the "A" low pressure injection pump by operations personnel.
Earlier significant weaknesses had been identified in the licensee's program for lubricant controls and was being tracked by Inspector Followup Item
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(IFI) 313; 368/9005-02.
In response to the weaknesses, the licensee had r
completed some short-term action and was reviewing several additional improvement items.
The operator obtained the current lubricant information by phoning the CR and having a CR operator review the component / lubricant database.
The inspector
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noted that, since this information was not recorded by the operator, the potential exists to inadvertently switch the lubricants.when lubricating several different components.
The storage cabinet for the lubricants appeared to be properly controlled with correct labels on the containers.
During the oil addition, the operator set the container down in a contaminated area then removed the container and placed it in the storage cabinet.
The operator was aware of this practice and stated that since a frisker was not available he felt that it was a:ceptable to only wipe the bottom of the container prior to placing it in the cabinet. The inspector noted that while the container was not transferred to a " free release" area it had been taken to a clean area without proper frisking. This practice does not appear to promuce the control of contamination and is being referred to the Division of Radiation Safety and Safeguards, Region IV, for further followup.
r No violations or deviations were identified.
7.
MONTHLY SURVEILLANCE OBSERVATION (UNITS 1 AND 2) (61726)
The NRC inspector observed the TS required surveillance testing on the various components listed below and verified that testing was performed in accordance with adequate procedures, test instrumentation was calibrated, limiting conditions for operation were met, removal and restoration of the affected components were accomplished, test results conformed with TS and procedure requirements, test results were reviewed by personnel other than the individual directing the test, and any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personnel.
7.1 Missed Surveillance on Unit 2 Control Element Assembly (CEA) Position
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On April 1,1990, the licensee determined that CR personnel had failed to log CEA positions once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> as required by TS.
The log sheet for CEA positions had not been provided to the CR, therefore, the normal cue to perform this function was absent and CEA positions were not taken.
Failure to take
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The licensee is currently implementing numerous changes to the program and
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methods used to schedule and track the surveillances required by TS.
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inspectors will continue to monitor the licensee's performance in this area regarding the effectiveness of these changes.
The WRC inspector witnessed portions of the following test activities:
Monthly test of Unit 2 core protection calculator Channel "B" (Procedure 2312.35, Job Order 810951)
Unit 2 weekly incore detector channel check (Procedure 2302.01, Job Order 810949).
This surveillance was performed in accordance with
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TS 4.3.3.2.A to demonstrate the incore detection system as operable for
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use in monitoring azimuthal powertilt, radical peaking f actors, local
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power density, or departure from nucleate boiling margin.
- Operability run of EDG 2K4B (Procedure 2104.36, Attachment 9). While EDG 2K4A was out of service for maintenance, TS 3.8.1.1 required that the remaining EDG be demonstrated operable every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.
During each of the runs, a vibration signature was taken for identification of bearing degradation.
Earlier vibration analysis and inspection of the outer
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generator bearing had identified higher than normal bearing wear.
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Evaluation of the earlier data confirmed that the bearing was fully acceptable for EDG operation, however, the licensee implemented the requirement for taking vibration signature during each EDG run.
Currently, the licensee has not observed any additional bearing degradation.
- Unit 1 monthly incore detector functional check and backup recorder calibration (Procedure 1304.34, Job Order 811514). The functional check involves obtaining a computer printout of all detector currents, then identifying any defective detector by comparison to adjacent detectors in the same asse%1y, r-for symmetric assemblies, by making comparisons to detectors same level.
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d identifying those detectors as defective. The instrument and control technician then notified a reactor engineer of the defective detectors.
The inspector was concerned that the functional check was not performed in a l
thorough manner and questioned whether the detector current data was also
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reviewed by reactor engineering. No additional review of the data is
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performed, however, the inspector was informed that reactor engineering performs an incore detector operability check per Procedure 1302.01. The
inspector reviewed this procedure which provides detailed acceptance criteria for verifying compliance with TS.
During the review, the inspector noted that Procedure 1302.01 along with six additional procedures which verify compliance with TS surveillance are not included in the computerized scheduling program.
These particular surveillances, which are performed by reactor engineering, are also manually scheduled by reactor engineering personnel.
This appears to be another weakness in the surveillance program.
No violations or deviations were identified.
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MONTHLY MAINTENANCE OBSERVATION (UNITS 1 AND 2) (62703)
l Station maintenance activities for the safety-related systems and components listed below were observed to ascertain that they were conducted in accordance l
with approved procedures, regulatory guides, and industry codes or standards
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and in conformance with the TS.
The following items were considered during this review:
the limiting
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conditions for operation were met while components or systems were removed from
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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, parts and materials used
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were properly certified, radiological controls were implemented, and fire prevention controls were implemented.
Work requests were reviewed to determine the status of outstanding jobs and to ensure that priority is assigned to safety-related equipment maintenance which may affect' system performance.
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8.1 Leak on Feedwater Check Valve FW5A On April 22, 1990, operators in the CR noted an increase of approximately 2.5 gpm in containment sump fill rate with no corresponding increase in RCS makeup rate. Analysis of sump sample indicated that the leakage was feedwater.
Members of the licensee staff performed a containment entry and determined that the leak was from the hinge pin cover on a 24-inch Attwood Morrell feedwater check valve. A subsequent entry was made by maintenance personnel to determine the feasibility of performing a leak repair while the unit remained online.
Personnel from the licensee's contract leak repair company assured plant management that the repair could be easily and quickly completed by injecting a
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Although the inspectors have recently noted a heightened awareness on the part of licensee management to the importance of detailed planning for high risk jobs, the preparation and control of this effort was not clearly was evident.
When unexpected difficulties arose during the effort to repair the leak, it appeared that no contingency plans had been developed.
Contractor personnel attempting to perform the work made at least one entry into the containment without the proper tools, and support to maintenance on back shift throughout the duration of the repair was not always conveniently available.
Lack of planning was a primary contributor to the job requiring 7 days and 53 reactor building entries to successfully complete the work.
A different leak repair contractor was brought onsite early in the week and, using a different technique, was able to repair the leak on April 29, 1990.
The technique that was finally successful has been commonly used in the industry and, had additional planning and review been used, may have allowed for repair earlie.
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-11-The licensee has self-initiated a review of the problems that occurred during the planning for this outage.
The results of that review are not yet complete.
8.2 Maintenance Activities The following maintenance activities were alto observed:
Postmaintenance performance test of Unit 2 Inverter 2Y-25, which supplies powe) to the plant computer.
DCP 90-8013 replaced two 15KV constant voltage transformers (CVT) with a single 30KV CVT.
Instructions for the performance test were included in DCP 80-8013. A vendor technical representative provided support for the CVT replacement, initial inverter checkout, and the performance test. During the test, the inverter was sequentially loaded in 50-ampere increments up to 250 amperes, while the output voltage and frequency were monitored.
- Replacement of cooling coil on ESF Pump and Equipment Room Cooler 2 VUC-1B i
(JO 809230). The inspector also reviewed the construction work permit which provided the detailed work instruction for the coil replacement.
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Repair of Unit 2 shutdown cooling Flow Centrol Valve 2CV-5091 (Job Order
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811506). The valve is a butterfly design with 90 degrees of normal
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rotation. Operations had initially identified that movement by the valve operator did not result in rotation of the valve. After removal and disassembly of the valve, the licensee identified that the stem had sheared at a dowel pin location.
The disk is attached to the stem by two dowel pins.
Inspection of the stem indicates that the break resulted from a torsional. failure caused by overtorquing of the valve.
A new stem was i
installed in the valve. Due to the unique design of the valve and it's operator, the licensee has not determined the root cause of the valve failure. The first attempt to determine the root cause was incomplete and lacked an adequate review of past valve maintenance.
The licensee is continuing the investigatien of the valve failure. The inspector will follow up on the licensee's root cause determination and any additional corrective action.
(IFI 313; 368/9007-01)
Cleaning and flushing the service water (SW) inlet and outlet line to
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Radiation Monitor 2RE-1511 (JO 811495). A s8mple portion of the SW return l
flow from Containment Cooling Unit 2 VCC-2A/B is directed through 2RE-1519 for detection of leakage into the SW flow.
Initially large quantities of sediment and corrosion products were flushed from the monitor. After the lines were back flushed with demineralized water, adequate SW flow through the lines was verified.
The licensee is initiating a program to flush, clean, and verify adequate
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SW flow through all radiation monitors and component coolers which have i
small or periodic SW flow.
Current plans include performing these tasks on a 6-month schedule and the instructions in either preventive maintenance procedures or component surveillance procedures. While performing a similar task on the SW outlet radiation monitor for the fuel pool heat exchange (2RE-1525), a live clam, approximately 1/2-inch in
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-12-diameter, was flushed from the monitor. Also, the inlet SW line to the monitor initially had zero flow.
Subsequ2ntly, the licensec was able to establish adequate flow to declare the monitor operable. Additional corrective action involving the replacement of the 1/4-inch carbon steel tap off of the SW orifice is being reviewed.
The licensee is investigating the origin of the live clam in the monitor and the effectiveness of the SW chlorinating system.
The inspector will review the licensee's corrective actions.
(IFI 313; 368/9007-02)
Replacement of the tappet for overspeed trip assembly on the Unit 2 EFW pumpturbine(Procedure 2402.124, JO 811312).
During a surveillance test of the EFW pump, the licensee identified that t' e tappet would not retract into the turbine bearing housing.
The overspee trip mechanism is designed such that spring force will return the tappet to its normal position when resetting the overspeed trip assembly.
Manual force was required to retract the tappet during the surveillance.
Disassembly and inspection revealed that swelling of the molded polyurethane tappet head caused binding of the tappet in the tappet plunger guide.
'a Temporary Modification (TM) 90-1-009 which deleted the alarm input from leakage past pressurizer high point vent Valve SV-1079. The pressurizer high point vent system includes two inservice solenoid operated valves (SV-1079, the upstreem valve, and SV-1077, the downstream) which vent to the quench tank. A pressure detector located between the valves will detect leakage past the upstream valve and will actuate an annunciator if pressure builds up to the setpoint.
The upstream valve started to experience leakage which actuated the annunciator alarm. Attempts to cycle the valve to stop the leakage were unsuccessful.
The licensee then started to periodically cycle the downstream to relieve the pressure buildup and clear the annunciator.
Several high point RCS vent system input into this same annunciator and with no reflush capability; the operators did not want the constant alarm caused by SV-1079.
However, the inspector questioned the rational of periodically cycling the downstream valve when the upstream valve is known to leak and there is the potential that the downstream valve would not reseat. After reviewing this issue, the licensee elected to install the TM that would delete the annunciator input.
In December 1989, a similar condition was identified on both Units 1 and 2 EFW turbines in which swelling of the tappet head prevented the tappet from returning to its normal condition. The following actions were initiated to compensate and resolve this problem:
The turbine driven EFW pump surveillance procedures were revised to include a manual trip of the turbine and a freedom of movement inspection of the tappet.
- The operating procedures for resetting the overspeed trip mechanism were revised to state that manual force may be required to return the tappet to its normal position, i
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A new tappet was installed in Units 1 and 2 turbine overspeed trip mechanisms.
- Tempcrature of the Unit 1 turbine outer bearing housing during standby conditions were recorded at 183'F and 138'F for Unit 2 turbine.
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Conversation with the vendor (Dresser-Rand) revealed that the polyurethane
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material was designed for ambient temperature of 115'F and was tested to a maximum temperature of 125'F. The vendor also agreed with the licensee
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that the higher ambient temperature was the most probable cause of the
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tappet swelling, j
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swelling of the tappet head would not affect the overspeed trip setpoint.
However, the vendor did recommend that the tappet be replaced when swelling of the polyurethane material is discovered. On April 13, 1990, during a surveillance at Unit 1 EFW pump, the tappet would not retract into the turbine bearing housing. A new tappet was subsequently installed.
Recent correspondence from Dresser-Rand indicates that a new tappet assembly design that will prevent binding may be available in July 1990.
'No violations or deviations were identified.
9.
EXIT INTERVIEW The inspectors met with the Director, Nuclear Operations, and other members of the AP&L staff at the end of the inspection.
At this meeting, the inspectors summarized the scope of the inspection and the findings.
The licensee did not identify as proprietary any of the material provided to, or reviewed by, the -
inspectors during this inspection.
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