IR 05000445/1993018
| ML20044G393 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 05/27/1993 |
| From: | Yandell L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20044G390 | List: |
| References | |
| 50-445-93-18, 50-446-93-18, NUDOCS 9306030016 | |
| Download: ML20044G393 (20) | |
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APPENDIX
U.S. NUCLEAR REGULATORY COMMISSION
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REGION IV
Inspection Report: 50-445/93-18
50-446/93-18 Operating Licenses: NPF-87
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NPF-89 Licensee: TU Electric Skyway Tower
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400 North Olive Street Lock Box 81 Dallas, Texas 75201
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Facility Name: Comanche Peak Steam Electric Station, Units I ar d 2
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Inspection At:
Glen Rose, Texas
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- Conducted: March 21 through April 27, 1993
Inspect
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Inspectors:
W. B. Jones, Senior Resident Inspector G. E. Werner, Resident Inspector R. V. Azua, Resident Inspector
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b I/EMD Approved:
L.' A. Yandell, Chief, Project Section B Date
Division of Reactor Projects
'l Irspection Summary-Areas Inspected (Unit 1): Routine, unannounced inspection of plant status,
operational safety verification, engineered safety feature system walkdown, maintenance observation, surveillance observation, open item followup, and
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onsite licensee event report (LER) followup.
Areas Inspected (Unit 2): Routine, unannounced inspection of plant status, maintenance observations, open item followup,'and onsite LER followup.
Results (Units 1 and 2):
Very good coordination wae * erved between the licensed and
nonlicensed operators during the Unit 1 power reduction and
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removal of secondary plant equipment for planned maintenance
(Section 2.1).
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Permanent plant equipment was found to be appropriately maintained
(Section 2.2).
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9306030016 930528 l
PDR ADOCK 05000445
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-2-The radiation prc'ection and security programs were appropriately
implemented (Sections 2.4 and 2.5).
However an instance was identified where personnel did not utilize good radiological practicet to minimize the time spent in higher dose rate areas (Section 5.3)
The Unit I auxiliary feedwater (AFW) system was found properly aligned.
- Two minor material deficiencies were identified to the licensee and work requests were subsequently initiated. An inspection followup item (IFI)
was initiated to review work activities performed in the Unit 2 turbine-
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driven AFW room and the potential use of pipe thread sealant beyond the
expiration date (Section 3.1).
The implementation of two troubleshooting work orders on Diesel
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Generator (DG) 2-01 did not meet the intent of the maintenance
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departments' administrative procedures. The troubleshooting activities were not effective in identifying the root cause for a repetitive condition. Additionally, the corrective maintenance activity was not properly identified as repetitive. An IFI was identified to review the implementation of the licensee's repetitive maintenance program
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(Section 4.1).
The implementation of troubleshooting activities on a.
safety-related inverter and battery charger were well performed (Sections 4.2 and 4.3).
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A potential generic concern was identified involving the misapplication
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of relays in vendor supplied safety-related inverters (Section 4.2).
Procedural compliance and communications were excellent during the
conduct of surveillance testing. Overall, personnel performance during
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testing activities was very good (Section 5).
An IFI remained open to review the actions taken to prevent potential
gas binding of the charging pumps. A potential generic concern was
identified that hydrogen or nitrogen could be injected into the common
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high head safety injection pump suction header because of a failure of a
't level switch on the positive displacement pump suction stabilizer (Section 6.2).
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Two LERs remained open to review the adequacy of corrective actions
implemented following previous missed surveillances (Section 7.4).
Summary of Inspection Findings:
IFI 446/9318-01 was opened (Secticns 3.1 and 4.3).
- IFl 445/9318-02; 446/9318-02 was opened (Section 4.1).
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IFl 445/9318-03; 446/9318-03 was opened (Section 4.1).
- IFI 445/9313-02; 446/9313-02 remained open (Section 6.2).
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URI 445/9161-01 was closed (Section 6.1).
a LER 445/90-037-01 was closed (Section 7.1).
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LER 445/91-032-00 was closed (Section 7.2).
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LER 445/92-005-00 was closed (Section 7.3).
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LER 445/92-026-00 remained open (Section 7.4.1.1).
- LER 445/93-004-00 remained open (Section 7.4.1.2).
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LER 446/93-002-00 was closed (Section 7.4.1.3).
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Attachment:
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i Persons Contacted and Exit Meeting
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DETAILS f
1 PLANT STATUS (71707)
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At the beginning of this inspection period, Unit I was operating at 100 percent power.
Reacto* power was maintained at 100 percent power for a
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majority of the inspection period. On April 15.a reactor power reduction to 47 percent was initiated to perform moisture separator reheater and main
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feedwater Pump 1-01 lube oil regulator repairs.
The unit was returned to.
100 percent power on April 23 and continued to operate at essentially full power until the end of this inspection period.
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At the beginning of this inspection period, Unit 2 was in Mode 3 at normal j
operating temperature and pressure. Mode 2 entry and initial criticality were
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achieved on March 24 and low power physics testing was completed prior to the
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issuance of the full power license, NPF-89, on April 6.
The plant entered Mode 1 operations the same day.
Various initial startup tests were performed i-throughout this reporting period.
The main generator was initially synchronized to the electrical grid on April 9.
Power escalation and startup testing continued with the plant at approximately 48 percent power at the end of this inspection period.
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2 OPERATIONAL SAFETY VERIFICATION (71707)
2.1 Unit 1 Reactor Power Reduction The inspectors observed selected operator activities associated with the power reduction to 48 percent. This activity was performed to permit repair to a l
moisture separator reheater drip pot and the main feedwater Pump 1-01 lube oil i
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It was noted that good command and control was demonstrated.by the unit supervisor during the power reduction. Very good coordination was noted i
between the reactor operator, balance-of-plant operator, field support
supervisor and auxiliary operators during the power reduction and removal of
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secondary plant equipment from service.
2.2 Plant Material Condition l
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The inspectors performed detailed walkdowns of the turbine, electrical control, auxiliary, and Units 1 and 2 safeguards buildings.
Permanent plant equipment was found to have been appropriately maintained.
In almost all inctances, defective equipment had been properly Wtifhf 'ith work request i
tags. Observaticns pertaining to the Units 1 and 2'AFW systems are provided i
in Sectien 3.
Minor discrepancies were identified to operations management and appropriate corrective actions were initiated. No previously unidentified-deficitncies were noted which affected plant equipment operation.
Plant housekoeping control was good; however, tools were found in an area where work
identified as being in progress would not have required the use of'the
observed tools (Section 3).
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-5-j 2.3 Emergency Core Cooling System Lineups
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The inspectors verified that valves within the Unit 1 emergency core cooling system major flow paths were properly aligned. The inspectors walked down
accessible portions of those systems and verified that the valve lineups were in accordance with the operating procedures.
Required auxiliary' systems were i
found to be operable. The main control board indications were found to be
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consistent with the field conditions.
i 2.4 Radiation Protection
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The inspectors observed personnel entering the radiologically controlled area (RCA) at the Unit 2 access point.
It was noted that the briefings on
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radiological conditions conducted by radiation protection technicians were appropriate. Additional radiation protection technicians were posted in the Unit 2 safeguards building to assist in coverage of numerous work activities.
The inspectors reviewed a potential radiation contamination concern with a
radiation protection supervisor. The concern involved steam emittance from
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the potentially radioactive floor drains when the Unit 2 turbine-driven AFW
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pump was operated.
It was identified that appropriate sampling was conducted'
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to ensure that the steam was not transporting contaminated material into the l
room. On several occasions, the inspectors questioned the radiation
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protection technicians about ongoing work in the RCA and found them to be
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cognizant of the work activities. One instance of poor radiation worker
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practices was noted (Section 5.3).
2.5 Security Program implementation
The inspectors observed security access controls at the primary access point.
Personnel and packages entering the protected area were properly surveyed.
Personnel entry into vital areas and access control of vehicles into the protected area were observed from the alarm stations.
All observed activities were appropriately implemented. A walkdown of the perimeter fences indicated they were intact.
2.6 Conclusions The licensee demonstrated very good command and control during the Unit 1 power reduction evolution. The licensed and nonlicensed operator activities were well coordinated. This included effective use of the field support supervisor to coordinate the removal of secondary plant equipment from service.
Major flow paths within the emergency core cooling systems were properly aligned for Mode 1 operation.
Plant housekeeping control was good.
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Radiation protection personnel demonstrated the expected cognizance of plant conditions and were aware of ongoing maintenance and surveillance activities
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in the radiologically controlled area. The radiation protection technicians were informed of significant plant evolutions.
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-6-The security program was appropriately implemented. The protected area physical and electronic barriers were found to be intact and operational.
3 ENGINEERED SAFETY FEATURE SYSTEM WALKDOWN (71710)
3.1 AFW System The inspectors began a walkdown of the Unit 1 AFW system during the inspection period.
This activity included verification that the system was properly aligned, review of outstanding work requests and in-service and surveillance test results, and a comparison to the Unit 2 AFW system.
At the end of the inspection period, the inspectors had completed the valve position verification and initiated a comparison with Unit 2.
Each valve was found to be appropriately aligned and locked in accordance with Procedure SOP-304A, Revision 9, " Auxiliary Feedwater System," and the locked valve log requirements. During the review of valve positions, it was noted that a pressure gauge on the motor-driven AFW 1-01 flow control
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Valve 1-PV-2453A was reading approximately 12 psig, whereas the other flow control valves were reading approximately 50 psig.
It was also noted that the
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valve's pressure gauge had an indicating range from 0-30 psig. This condition
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was identified to the licensee and Work Request 134821 was initiated to change
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the pressure gauge to a 0-60 psig.
It was determined that this was a noncritical gauge and the condition did not indicate that the valve was inoperable.
On April 23, during a comparison of the Units 1 and 2 AFW systems, the inspectors noted tnat tools had been left below the turbine-driven AFW ' steam
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admission check Valve 2MS-0142.
It was not apparent that there was any work in progress in that room which would require the use of the specific tools.
The tools found included a pipe wrench, tubing cutter, two adjustable
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wrenches, and a tube of pipe thread sealant with an expiration date of
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February 1, 1993 (TSN No. 180759).
Three work-in-progress tags were found in the immediate area. One tag
(2MS-0145, 93-043843, dated April 13, 1993) was active and attached to a bag of insulation which had been removed to permit acoustical testing on Valve 2MS-0145. The two remaining work-in-progress tags (CP1-CHAPCP-05, 5-92-502647, dated December 1,1992; and 2PI-2390, OPT-206B, dated March 14, 1993) were closed.
l The inspectors have requested that the work orders associated with the Unit 2 turbine-driven AFW system, which may have utilized the pipe thread sealant, be provided. This is also to include any work activities which may have been
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worked under a work request tag. The review of these work orders, the work request, the potential use of the pipe thread sealant beyond the expiration date, and the potential for undocumented repair activities to have occurred
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will be IFI 446/9318-01.
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i The inspectors also noted that turbine-driven AFW flow control Valve 2-HV-2460 had a small instrument air leak at the flow control valve regulator. This condition was identified to the licensee and Work Request 145430 was initiated
to correct the condition. This work request is scheduled to be completed in
July 1993. A work request tag (WO 92-025591, CP2-AFAPM-01, dated October 13, 1992) to perform a hot alignment on the motor-driven AFW Motor 2-01, was found attached to the outboard end of the motor.
It was subsequently determined
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that the work activity had been completed on February 15, 1993. The licensee j
has provided a commitment as documented in NRC Inspection Report 50-445/93-12 50-446/93-12 to identify and remove similar tags by the end of May 1993. This
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I specific tag was identified to the licensee.
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3.2 Conclusion The Unit 1 AFW system was found to be appropriately aligned to meet its design
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safety function.
Locked valves within the system were appropriately controlled. Two conditions were identified to the licensee which resulted in the initiation of work requests; however, AFW system operability was not
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affected on Units 1 or 2.
An additional example of a work request tag being left in the field following completion of the work activity was identified.
4 MAINTENANCE OBSERVATION (62703)
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t 4.1 DG 2-01 Troubleshooting Mechanical maintenance technicians were observed performing troubleshooting maintenance on DG 2-01, Cylinder No. 7, using troubleshooting Work Order 1-93-043107-00. This work activity was performed during the scheduled
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work window outage. The initiating work request (132858) was dated March 19, 1993, and identified abnormal hydraulic valve lifter noise. A subsequent work
request (134391) dated March 26, 1993, which was included in this work order,
identified abnormal exhaust gas and cylinder differential temperatures for
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Cylinder No. 7.
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The technicians removed four lifters and tested them in accordance with
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Mechanical Maintenance Procedure MSM-CO-3339, Revision 1, " Emergency DieseI Generator Engine Subcover Assembly Inspection." The left exhaust hydraulic
valve lifter failed the time bleed-down test and was replaced with a new
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lifter. The technicians determined initially that the failed hydraulic valve
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lifter was the cause for the abnormal noise. During the adjustment of the new hydraulic lifter, the technicians discovered that the associated exhaust valve was sticking partially open. The exhaust valve was stroked several times and no further sticking was observed. The postmaintenance run indicated no abnormal cylinder temperature indications or valve noise. The system engineer felt that carbon deposits on the valve stem caused the sticking problem. The licensee concluded that no valve damage had occurred because of the exhaust valve being stuck partially open.
The inspectors reviewed the DG Vendor Manual CP-0034-001A and found that the maintenance procedure for testing, installing, and adjusting the lifters was
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vendor manual, the inspectors noted that numerous possibilities for the
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abnormal lifter noise were listed. After discussions with the mechanics who i
had performed the work and a review of the work order, the inspectors i
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concluded that no actual troubleshooting had been accomplished.
t The inspectors reviewed a similar work order (1-93-036934-00) which had been
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completed on March 3,1993.
This work orden also addressed possible lifter noise on Cylinder No. 7.
On January 14, 1993, the licensee identified possible hydraulic lifter noise on DG 2-01, Cylinder No. 7.
The inspectors
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concluded, base
Operations Notification and Evaluation (CNE) Form 93-936 to document the
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coding failure. The inspectors' review of the licensee's repetitive
.i maintenance program implementation will be IFI 445/9318-03; 446/9318-03, i
The inspectors discussed the DG. system status with the responsible system engineer. He was found to be fully cognizant of the problems with Cylinder 7.
His followup to the problem accomplished basically tne same action as those
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that should have resulted from the technical review process. Technical Evaluation 93-893 dated April 22, 1993, confirmed that the DG 2-01 was
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operable. The evaluation also stated that the cylinder differential
temperature should not exceed the specified maximum value; however, the high temperatures were to be expected until the cylinder head rework was completed.
An unrelated postmaintenance run conducted on April 22, 1993, indicated no
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abnormal valve noise or exhaust gas temperatures on any DG 2-01 cylinder. The
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e licensee was staging a replacement cylinder head and associated parts as a contingency in the event of any further problems with the Cylinder 7 exhaust valves.
i 4.2 Unit 1 Safeguards Inverter
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On April 7 the inspectors observed the performance of corrective maintenance activities on the 118 VAC Safeguards Balance-of-Plant Inverter IVI-EC2 (CPI-ECIVEC-02). Work Order 1-93-041200-00, Revision 1, authorized the t
replacement of 12 Westinghouse ARD 440 SR relays. These relays provided an
alarm function to the control room in the event power from the inverter was
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lost or degraded. The relays were replaced by electrical maintenance technicians utilizing good self-verification techniques. The relays were
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replaced with Westinghouse ARD 440 UR relays, rated at 130 volts direct current (DC), plus 10 percent, minus 15 percent. Appropriate supervisor
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oversight was provided during the work activity.
It was noted by the licensee
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and the inspectors that the work instructions did not specify a specific
postmaintenance test. The work order was subsequently revised to verify operability of the inverter and the alarms.
On March 23, 1993, Revision 0 to this work order provided for the troubleshooting of the inverter to determine why a 3 ampere fuse on a DC-to-DC-
converter card had blown. No apparent reason for the blown fuse could be found. The fuse was then replaced and the inverter energized. During this i
period, the operators noted that the expected alarms for the inverter being deenergized had not been received. ONE Form 93-767 was initiated and
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additional troubleshooting activities conducted to determine the reason for
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the expected alarms not being received.
It was then found that the K 10 relay
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(Westinghouse ARD 440 SR) which feeds the K 12 summary relay would not drop
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out when deenergized. The troubleshooting activity verified that the l
annunciator cards and isolation modules were all operable.
It was then
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determined that the 11 remaining Westinghouse ARD 440 SR relays were also
Because these relays provided an alarm function only, the
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licensee determined that the inverter could be returned to service until the required parts were procured from the warehouse and the work scheduled.
i Compensatory measures were established to have the auxiliary operators
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periodicelly monitor the inver+ar incally on an increased frequency.
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I following the completion of the work activity on April 7, the licensee identified that all the Westinghouse ARD 440 SR relays had failed in the same manner. Technical Evaluation Failure Analysis TE-FA-93-814 was initiated the following day and concluded that the coils (No.1253C48G01) which were rated at 120 volts DC plus or minus 10 percent had been subjected to a continuous overvoltage condition up to 140 volts DC. This resulted in the coil swelling i
around the relay armature and holding the alarm contacts closed after the coil j
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was deenergized. These relays were installed in the inverter, Elgar i
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Model 103-1-102, by the vendor. The licensee initiated a report on the
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nuclear network identifying the potential common mode failure of these relays.
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Work requests were initiated to replace the remaining relays in the remaining i
inverters with the Westinghouse ARD 440 UR relays. A total of 144 relays in l
both Units 1 and 2 required replacement.
l The inspectors reviewed the licensee's evaluation of Information Notice 88-88, i
" Degradation of Westinghouse ARD Relays"; Information Notice 88-88, Supplement 1, " Degradation of Westinghouse ARD Relays"; Information
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Notice 91-45, "Possible Malfunction of Westinghouse ARD, BFD, and NBFD Relays, i
and A200 DC and DPC 250 Magnetic Contactors"; and ONE Form 91-779, j
Westinghouse Potential Part 21 Deficiency.
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The information notice and its supplement identified concerns with
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Westinghouse ARD relays where increased drag was noted between the solenoid
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coil spool and the armature. The increased drag resulted from granules within the coil potting compound lodging between the coil spool and the armature.
The potting compound utilized a sand based material which was found to deteriorate.
Prior to issuance of Information Notice 88-88, the licensee had
initiated Design Modification Request Construction Phase 88-1-243 to inspect and replace, where needed, Westinghouse ARD relay coils which were not designed for prolonged use at 140 volts DC.
These actions were in progress l
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at the time Information Notice 88-88 was issued. The coil spools which
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contained the granular potting compound were also identified and replaced,
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starting with the relays used in safety-related applications.
Information Notice 91-45 and ONE Form 91-779 identified concerns that the
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i epoxy used in the above mentioned relays and contactors, to encapsulate the coils, had not been properly mixed, resulting in the 7poxy softening and restricting the armature movement. The inspectors found that tb licensee had taken appropriate measures to assure that the installed relays did not exhibit this problem.
It was subsequently determined that the licensee had taken appropriate measures to locate the Westinghouse ARD relays which could have been affected
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by the above problems identified in the design modification request construction phase and information notices. TP-failure mode experienced with the Westinghouse ARD relays installed in the Elgar inverters was consistent i
with the concerns identified in the scope of the design modification request;
however, the inspectors concluded that the licensee would not have known that ti,e relays were installed in the inverters without prior notification from the vendor.
It appears that, following the issuance of the 10 CFR Part 21 report
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by Westinghouse, as described in Information Notice 91-45 on the ARD relay
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concerns, no notification from the vendor was received that the relays were
installed in the inverters.
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4.3 Unit 2 Battery Charger The inspectors observed a troubleshooting work activity on the safety-related
125 volt DC Battery Charger BC2ED4-2. The troubleshooting activity was
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authorized by Work Order 1-93-043015-00 to determine the cause for fuses
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protecting the undervoltage relay card to blow as soon as power was applied to
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the circuit.
l The troubleshooting activity was performed in accordance with the work order
instructions.
It was identified that the cause for the fuses blowing was that
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DC Relay K1 and the alternating current Relay K2 had been interchanged and
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were not installed in accordance with the circuit design. The relays being l
installed incorrectly resulted in the loss of the undervoltage DC alarm, but l
did not affect operability of the battery charger.
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ONE form 93-856 was initiated on April 7, 1013. to document the as-found condition. A review of previous work activit'
i siled to identify when the
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alarm rel:ys may have been inadvertently exch e v,K Additionally, a review of l
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the remaining battery chargers for both units Ahnined that all other relays were properly installed.
It was believed that & condition resulted from
startup or construction activities. The inspectors discussed the as-found
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condition with licensee managt; int. A review of the the licensee's corrective
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actions associated with this battery charger will be conducted along with the l
review identified as IFI 446/9318-01.
4.4 Conclusions The troubleshooting activities associated with the DG were not effectively implemented. This resulted in the failure to identify the root cadse for the i
excessive valve noise. The classification of the work activities was not
consistent with the repetitive maintenance program. The actions of the system i
engineer were very' good and resulted in the intent of the repetitive
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maintenance program being met.
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The troubleshooting activities associated with the inverter and battery I
charger were well implemented. A potential generic concern was identified i
involving the misapplication of relays in vendor supplied safety-related inverters. An instance was identified where components were installed
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incorrectly. A review of the work requests and work orders which could have resulted in this occurrence is an IFI.
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5 SUR"r"! ANCE OBSERVATIONS (61726)
5.1 Engineered Safety Feature Filter Unit
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The inspectors observed the testing (Work Order 5-92-1621-AA) on primary plant ventilation exhaust Filter Unit X-01 (CPX-VAFUPK-01).
Procedure PPT-SX-7507A,
Revision 0, "ESF Filter Unit Test-CPX-VAFUPK-01," was used to demonstrate the i
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proper operation of the high efficiency particulate air filters and duct heater.
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The procedural acceptance criteria was reviewed and found to be consistent
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with those specified in the Technical Specifications, Final Safety Analysis l
Report (FSAR), and applicable section of Regulatory Guide 1.52, " Design,
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Testing, and Maintenance Criteria for Engineered-Safety-Feature Atmosphere Cleanup System Air Filtration and Absorption Units of Light-Water-Cooled Nuclear Power Plants." All test data met the required acceptance criteria.
The inspectors did note that, during calculation of airflow on
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Attachment 10.6, the aerometer correction factor was approximated. The data
sheet with the aerometer had sufficient data to allow calculation of a more i
precise correction factor; however, the added inaccuracies with the approximated correction factor were determined to be insignificant.
The inspectors reviewed the previous test conducted under Work Order 910000781 on September 20, 1991.
Comparison of the data with the recent test found the i
data to be consistent. No review for trends of other past surveillance test was performed since Work Order 910000781 was accomplished after a complete carbon bed change-out.
A radiation protection technician performed contamination surveys on the filter unit and discussed the radiological protection practices and precautions that personnel should observe during the setup of test equipment inside the filter unit. Good radiological work practices were used during the
observations of the test rig setup.
5.2 Solid State Protection System Train B Actuation Logic Test On April 8 the inspectors observed portions of the surveillance test that was performed on Train B of the solid state protection system. This effort was performed to satisfy, in part, the requirements of Technical Specifications 4.3.1 and 4.3.2.
This effort was performed using Procedures OPT-446A, " Solid State Protection System Train B Actuation Logic Test"; OPT-702A, " Rod Control System"; and 50P-711A, " Solid State Protection System."
The inspectors reviewed the surveillance procedures for technical adequacy, i
for adherence to the Technical Specification requirements, and to verify that thr.y had been reviewed and approved, as noted by the appropriate signatures.
i The inspectors interviewed the personnel performing these procedures and found that they were knowledgeable of their responsibilities and were aware of the potential for a reactor trip.
Prior to the initiation of the test, the personnal invol"M held a briafing to
discuss the aspects of the test.
Specifically addressed was the potential for a reactor trip and what needed to be accomplished to avoid such an event.
The
Lhift supervisor was in attendance.
The inspectors noted that the briefing
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was clear and concise, leaving little room for misunderstanding of what was expected of each of the personnel involved.
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Procedural compliance during the surveillance test was excellent, with very good communications between the control room personnel and the personnel stationed out in the field.
j 5.3 Containment Spray System Operability Test
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On April 8 the inspectors witnessed the performance of Surveillance Test l
Procedure OPT-205A, Revision 4, " Containment Spray System Operability Test,"
Revision 4.
This surveillance was performed on Containment Spray Pumps 01 and 02. This effort was performed to satisfy, in part, the requirements of-
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Technical Specifications 4.6.2.1 and 4.0.5, which addressed the operability of containment spray pumps and check valves.
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The inspectors witnessed portions of the test in the control room and locally.
Control room communication between the operator and the auxiliary building i
operator was found to be very good, as was procedural compliance.
The inspectors noted that the licensee prestaged the equipment needed to perform
the surveillance test.
It was observed, however, that the area surrounding
the containment spray pumps was a contaminated area that was roped off
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appropriately but did not contain an entryway with a step-off pad for access
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or egress.
Entry to this area was necessary for the licensee personnel responsible for taking vibration readings of the pump. This was identified
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and promptly corrected by a radiological protection technician who was in the
area. The inspectors noted that the licensee personnel performing the
surveillance in the vicinity of the pumps were not utilizing good radiation protection practices.
It was apparent that the personnel were not fully
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cognizant of which part of the room had higher radiation dose rates.
The t
personnel did not minimize their stay time in these ' areas or increase their distance from these areas to reduce exposure until the radiation protection
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technician brought it to their attention.
It was noted by the inspector that-a radiological room survey was posted next to the entrance to the containment
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spray pump room. The radiation protection technician remained in~the area to oversee the work in the contaminated area.
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The inspectors observed portions of the channel calibration for steam pressure Loop 4 pressure transmitter under Work Order 5-92-502069-AA.
Procedure INC-7310A, Revision 5, " Analog Channel Operational Test and Channel
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Calibration Steam Pressure, Loop 4, Protection Set II, Channel 0545,"
l Section 8.8, was referenced to perform the channel calibration. The "as i
found" values were within specification; however, the values were close to the end of their tolerance bands and the technicians decided to recalibrate the
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pressure transmitter.
Good work practices and self-verification techniques
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were used during the surveillance.
5.5 Conclusions
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Procedural compliance and communications were very good.
Pretest briefings were thorough and addressed the areas of concern. One instances of poor
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radiation work practices was noted in keeping radiation exposure to as-low-as
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6 FOLLOWUP (92701)
6.1 (Closed) URI 445/9161-01:
Reactor Coolant System (RCS) level for Entering into Reduced Inventory Controls j
I This item was opened to determine whether the licensee's actions to revise their guidelines entering into RCS reduced inventory controls (from 3 feet to
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5 feet below the reactor vessel flange) was appropriate. Also of concern was l
the appropriate process for notifying the NRC of a change to the docketed
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licensing basis that is not included in the FSAR. Based on further review and
discussions with the licensee, it was determined that:
A 10 CFR Section 50.59 evaluation was not required because the
definition of reduced inventory condition was not included in the FSAR.
i Reactor vessel level controls were appropriate and vessel level is not I
normally lowered to less than 3 feet below the reactor vessel flange
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while fuel is in the reactor vessel, except when removing or i
reinstalling the upper internals and reactor vessel head.
Given the-l limited time these conditions are present, not establishing reduced inventory conditions for these limited evolutions poses an acceptably i
low safety risk.
Current TV Electric practice does not meet the guidance specified I
within Generic Letter 88-17 issued October 17, 1988; however,
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TU Electric complies with its commitment to Generic Letter 88-17 as
modified (from 3 feet to 5 feet) and documented in Safety Evaluation SE-91-86 dated September 11, 1991.
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The inspectors concluded that the licensee had appropriately considered the
regulatory basis and safety significance to define reduced inventory conditions differently than that specified in the generic letter.
6.2 (0 pen) IFI 445/9313-02: 446/9313-02:
" Potential Gas Binding of the Centrifugal Charging Pumps from the Volume Control Tank"
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LER 445/91-012, " Potential Gas Binding of Centrifugal Charging Pumps Due to Voids in the Boric Acid Gravity Feed System," was closed in NRC Inspection Report 50-445/93-13; 50-446/93-13, Section 7.4.
During the review of this LER, the inspectors noted that a similar concern had been identified in Technical Evaluation 93-0509. This Technical Evaluation addressed the i
potential for gas within the volume control tank (VCT) to be injected into the charging pump suction header on a safety injection actuation signal, provided the refueling water storage tank was at a lower pressure than the VCT.
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The inspectors reviewed the technical evaluation, associated ONE Form 93-550,
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and Flow Diagram M1-0255, Revision 16, " Chemical and Volume Control System Volume Control Tank Loop." This concern was also discussed with the cognizant i
system engineer.
It was subsequently determined that the gas from the VCT l
would not be injected into the centrifugal charging pumps (CCPs) during the
sequencing of suction valves on a safety injection signal.
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On February 25, 1993, at approximately 12:20 p.m. with Unit 2 in Mode 5, and
Reactor Coolant Pumps 3 and 4 in operation, erratic positive displacement pump (PDP) indications were observed. This occurred with the PDP in operation
and makeup to the RCS being provided through the charging system with the
system lined up to the refueling water storage tank (RWST).
RCS letdown was l
through the residual heat removal system.
CCP 2-01 was subsequently started
to restore reactor coolant pump seal injection, which had been lost during the erratic PDP operation.
The licensee initiated troubleshooting activities to determine the reason for
gas binding of the PDP. The pump casing was vented (Valve 2CS-209) for approximately 15 minutes before a solid stream of water was received. The PDP
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suction stabilizer vent line (Valve 2CS-8212) and the RWST supply vent line (Valve 2CS-0215) were opened with no air in the line observed. The CCP 2-01 l
suction supply was then shifted to the RWST and no perturbations were noted.
At 3:45 a.m. the following morning, the gas supply line to the PDP suction
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stabilizer was opened and, almost immediately, CCP 2-01 flow oscillations were noted. The gas supply line was isolated and the charging system suction transferred back to the VCT. No additional oscillations were observed. These t
oscillations were determined to be due to gas intru ion into the suction line.
The PDP utilized a suction stabilizer which consisted of a water volume with a gas medium present to dampen suction oscillations. No bladder existed between the gas and water in the stabilizer. A single level switch on the suction stabilizer controlled a gas inlet valve (2-8204) which provided a gas.upply from either a hydrogen or nitrogen source. The normal system lineup was with
the common gas supply inlet valve closed. Two additional valves in series
downstream of the gas inlet valve were normally open.
In addition, there were j
two valves in series downstream of the suction stabilizer vent line which were
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normally open to permit flow to the waste gas compressor. These normally open l
d valves would receive a close signal on a safety injection actuation signal.
i The level switch (2-LS-0189) was designed to open the gas supply valve when t
the level in the suction stabilizer reaches a hi level. The level switch t
should then close the gas supply valve after level in the suction stabilizer
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had decreased.
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The licensee determined that the level switch in the suction stabilizer had hung up in the hi level position, causing the gas supply valve to remain open.
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When the charging system suction was transferred to the lower pressure RWST
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from the VCT, the gas supply blew the suction stabilizer dry and the gas
entered the common suction supply line. The immediate corrective action taken
was to rotate the. level switch approximately 180 degrees about its axis to i
preclude it from hanging up. The system was subsequently returned to service.
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i A contributing factor to this event appears to be the decrease in suction t
pressure to the charging pumps as a result of transferring from the VCT to the
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RWST.
Currently, the PDP is not being used during normal operation and the l'
gas supply to the suction stabilizer is administratively maintained closed.
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This event appears to be limited to Mode 5 operation with the charging system
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suction lined up to the RWST. Additional review of plant conditions which
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could result in the introduction of gas from the suction stabilizer to the
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common charging system suction line will be included in subsequent review of
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this IFI.
7 ONSITE REVIEW 0F LERs (92700)
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The inspectors reviewed the below listed LERs to determine whether corrective l
actions were adequate and whether the responses to the events were adequate l
and met regulatory requirements, license conditions, and commitments.
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7.1 (Closed) LER 445/90-037-01:
" Blackout Sequencer Actuation Due to Personal Error"
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On November 5,1990, with Unit 1 in cold shutdown, Made 5, for a planned outage, an inadvertent Train B blackout sequencer actuation occurred.
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t Electrical maintenance personnel were assisting an operator with the performance of Procedure OPT-211A, Revision 1, " Cold Shutdown Class lf
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Electrical UV Relay Test." During restoration from the test, a lifted lead
contacted an adjacent terminal point, causing the blackout sequencer to
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activate.
r The licensee identified that the lead should be lifted at a point more accessible and Procedure OPT-211A was revised to change the location where the-j lead was lifted. A review of procedures which required lifting / landing leads
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near exposed contacts was performed.
In the cases where the terminal block
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was more accessible than the component, the procedure was revised to lift / land the lead at the terminal block. A list of procedures which required the
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lifting / landing of leads was provided to engineering for resolution.
In some instances, design modifications were issued to move the test point. The
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inspectors found these corrective actions to be appropriate.
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i 7.2 (Closed) LER 445/91-32-00:
" Procedure Error Leading To Nonconservative
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Miscalibration Of Power Range Nuclear Instrument Channels" The licensee was conducting power escalation activities fc110 wing the first
refueling outage. During the escalation, the shift supervisor noted that l
9 percent indicated nuclear power did not appear to be consistent with indicated plant conditions.
It was subsequently determined that the four power range channels had not been properly calibrated, resulting in a nonconservative indicated power approximately 8 percent lower than the actual
calculated power of 17 percent. No operation above Technical Specification
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limits occurred.
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The licensee. initiated ONE Form 91-1672 to determine the root cause for the event.
It was determined that the surveillance work order steps were
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incorrectly identified, which resulted in incomplete performance of the j
surveillance activity.
The work planner had failed to recognize that the r
work identified on the calibration sheet was not consistent with work order 3'
requirements.
Lastly, the error in the work instructions was not corrected following the previous performance.
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The inspectors verified that the licensee had implemented appropriate
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corrective actions to address the root cause and the contributing causes.
This included revising the surveillance data base to clarify the procedure requirements.
7.3 (Closed) LER 445/92-005-00:
" Personnel Error Leading to Engineered Safety Feature Actuation During Performance of Surveillar.ce Testing" l
During the performance of a slave relay test on the engineered safety featu.res-actuation system instrumentation and the AFW system, the split flow bypass valves were inadvertently closed because of personnel error.
The inspectors reviewed the licensee's implementation of the corrective
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actions identified in the LER.
In addition, the NRC staff has conducted
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several inspections to review the licensee's corrective actions to reduce personnel errors during the performance of surveillance tests and the implementation of the surveillance program. Two inspections which directly
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involved review of this area are documented in NRC Inspection Reports 50-445/92-22; 50-446/92-22, and 50-445/93-12; 50-446/93-12. The inspectors concluded that the licensee has implemented significant measures j
and achieved quantifiable results in reducing personnel error and enhancing personnel performance.
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7.4 LERs Resulting From Missed Surveillance Test Requirements j
7.4.1 Surveillance Task Team Corrective Action Implementation
NRC Inspection Report 50-445/92-22; 50-446/92-22 reviewed the licensee's surveillance test and control program. This program appeared to be well i
defined and the controls for its implementation were thorough and comprehensive. The inspection also included a review of missed surveillance and the corrective actions which had been implemented as a result of the
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licensee's Surveillance Task Team Report.
At the time of the inspection, the inspecter concluded that effortiva implementation of the tasks team's
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identified corrective actions would strengthen the surveillance test program.
The following two LERs will remain open to determine whether the corrective actions recommended by the Surveillance Task Team should have prevented the events.
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7.4.1.1 (0 pen) LER 445/92-026-00:
" Missed Diesel Generator Fuel Oil Surveillance Due to Personnel Error" On December 13, 1992, the licensee identified that the monthly surveillance requirement to check for and remove water from the Train B diesel generator fuel oil storage tank had not been performed prior to the November 28, 1992, expiration date. At the time the surveillance requirement was due, the unit was in Mode 6 and the Train A diesel generator was out of service for preventive maintenance.
The licensee determined that the surveillance was missed because of personnel error. The fuel oil sample was subsequently determined to meet the surveillance test acceptance criteria.
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The inspectors noted that the licensee had developed " Lessons Learned," which emphasized the use of good communications skills and that the work load of the surveillance coordinators and the schedulers should be considered during an
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outage. This included management's expectation that outage staffing be i
adequate to support surveillance monitoring during all plant conditions.
These corrective actions were found to address the conditions which resulted in the missed surveillance.
7.4.1.2 (0 pen) LER 445/93-004-00: " Failure to Satisfy Surveillance Requirement for Liquid Waste Processing Valve 1-7150" The licensee identified that the ASME Section XI inservice testing required by
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Technical Specification 4.0.5.b had not been implemented in accordance with the Code requirements.
It was identified that Liquid Waste Processing Valve 1-7150 had exceeded the alert range stroke time criteria on two occasions, but had not been placed on an increased test frequency. These events occurred on November 6, 1991, and June 27, 1992.
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The licensee determined that the cause for the events were the alert limit not
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being identified in the body of the procedure and a lack of tracking to ensure increased testing was implemented. The inspectors verified that the licensee
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has implemented its identified corrective actions to prevent recurrence. The j
test procedure data sheets arr being revised to include the alert limits, and
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the operators were being trained on inservice test requirements. These corrective actions were found to be adequate to address the conditions which resulted in the missed surveillance.
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7.4.1.3 (Closed) LER 446/93-002-00:
" Personnel Error Leading to Failure to Satisfy Technical Specification Surveillance Requirement for
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Feedwater Isolation Valve Temperature Monititoring"
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On March 16, 1993, the licensee identified that the Technical Specification
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requirement to verify that the feedwater isolation valves are greater than or equal to 90oF at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> except in Mode I was not met. The unit was in Mode 3 during the period the temperature readings were not taken.
l The licensee was able to provide reasonable assurance that the feedwater isolation valves remained above the Technical Specification temperature limit during that time.
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Management's expectation was reiterated to all licensed personnel to utilize all available references when assessing Technical Specification requirements.
The inspectors concluded that these corrective actions were appropriate.
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ATTACHMENT 1
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1 PERSONS CONTACTED l
1.1 TU ELECTRIC i
D. B. Allen, Initial Startup Manager
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O. Bhatty, Site Licensing R. D. Bird, Jr., Manager, Work Control Center M. R. Blevins, Director of Nuclear Overview
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D. M. Bozeman, Chemistry and Environmental Manager T. Broughton, Operations j
0. E. Buschbaum, Systems Engineering
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R. R. Carter, Assistant to Manager, Maintenance
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D. L. Davis, Manager, Plant Analysis M. Dean, Operations i
J. W. Donahue, Manager, Operations
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S. L. Ellis, Work Control Manager
R. Flores, Shift Operations Manager
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J. Greene, Licensing
W. Hartshorn, Nuclear Operations Department T. A. Hope, Site Licensing Manager
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B. T. Lancaster, Manager, Plant Support i
B. tantz, Nuclear Operations Department W. R. Morrison, Systems Engineering
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J. W. Muffett, Manager of Technical Support & Design Engineering
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D. J. Reimer, Manager, System Engineering J. Riess, Project Engineer
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S. Sawa, Unit 2 Outage Maintenance E. J. Schmitt, Operations / Engineering Training Manager i
G. Stein, Maintenance (DM)
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C. L. Terry, Vice President, Nuclear Engineering and Support G. Westhoff, Assistant to Marager, Quality Assurance
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1.2 NRC Personnel
D. N. Graves, Senior Resident Inspector l
The personnel listed above attended the exit meeting.
In addition to the
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personnel listed above, the inspectors contacted other personnel during this
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inspection period.
i 2 EXIT MEETING
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An exit meeting was conducted on April 27, 1993 Durina +his meetino, the inspectors reviewed the scope and findings of the report. The licensee did l
not identify as prop'rietary any information provided to, or reviewed by, the
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