IR 05000445/1993013
| ML20035F747 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 04/16/1993 |
| From: | Yandell L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20035F742 | List: |
| References | |
| 50-445-93-13, 50-446-93-13, NUDOCS 9304220230 | |
| Download: ML20035F747 (16) | |
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APPENDIX i
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
n Inspection Report:
50-445/93-13 50-446/93-13
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Operating Licenses: NPF-87
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NPF-89 Licensee: TV Electric
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Skyway Tower 400 North Olive Street Lock Box 81 Dallas, Texas 75201
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t Facility Name:
Comanche Peak Steam Electric Station, Units I and 2 Inspection At:
Glen Rose, Texas Inspection Conducted:
February 16 through March 20, 1993
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Inspectors:
W. B. Jones, Senior Resident inspector G. E. Werner, Resident inspector
- Accompanying Personnel:
V. Gaddy, NRC Intern
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k E.bD Approved:
L. A. Yandell, Chief, Project Section B Date
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Division of Reactor Projects
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inspection Summary i
Areas Inspected (Unit 1):
Routine, unannounced inspection of onsite followup of plant events, operational safety verification, maintenance and surveillance observation, followup on corrective actions for violations, and followup of licensee event reports (LERs).
Areas inspected (Unit 2):
Routine unannounced inspection of operational
safety verification and surveillance observations.
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Results (Unit 1):
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Control room operators exhibited good response during the recovery
from engineered safety feature (ESF) equipment actuations (Section 2.1).
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Chemistry' technicians ~used good radiological work practices while a
obtaining a primary sample (Section 3.1).
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E 9304220230 930419 PDR ADOCK 05000445 G
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An old revision of a procedure, used as an operator aid, was found
located at two lubrication lockers. An inspection followup item (IFI)
was identified to determine the licensee's controls established on use of operator aids (Section 3.3).
Overall, maintenance technicians were observed using good work practices -
and self-verification techniques. Two instances of poor work package
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review and inadequate prejob briefings were identified (Section 4.1).
The independent safety engineering group (ISEG) demonstrated effective'
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oversight of a surveillance activity (Section 4.1).
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The surveillance program was properly implemented.
Pretest briefings
were very well conducted.
Personnel performance was good (Section 5).
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Several procedural deficiencies were identified during the performance
of Channel 1 and 2 reactor coolant pump (RCP) underfrequency relay
surveillance (Section 5.4).
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The field support supervisor was utilized as an extra auxiliary operator.
- and was not available.to supervise auxiliary operator. activities (Section 5.5).
.In closing out LER 91-012, an IFI was identified on a related catter
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that pertained to the potential injection of gas from the volume control tank into'the centrifugal charging pump suction line (Section 7.4).
Results (Unit 2):
l The turbine-driven auxiliary feedwater pump (TDAFWP) steam admission
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check vah e testing was appropriately conducted (Section 5.5).
Summary of Inspection Findings:
IFI 445/9313-01; 446/9313-01 was opened (Section 3.3).
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IFI 445/9313-02; 446/9313-02 was opened (Section 7.4).
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Violation 445/9243-01 was closed (Section 6).
LERs 445/90-031, 445/90-039, 445/91-009, 445/91-012, 445/91-018,
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445/ 2-009, 445/92-012, 445/92-013, 445/92-016, 445/92-022, 445/92-024,
and 445/92-027 were' closed (Section 7).
Attachment:
Attachment - Persons Contacted'and Exit Meeting i
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u DETAILS 1 PLANT STATUS (71707)
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At the beginning of the inspection period, Unit I was near 100 percent power.
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Reactor power was maintained at 100 percent power for most of the inspection period. On February 26 and 27, 1993, Unit 1 ex3erienced two separate ESF i
actuations because of an internal Train A seque1cer fault. Unit I remained at
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power during the troubleshooting and repair of the sequencer. On March 14 l
reactor power was reduced to approximately 90 percent to' stabilize Main
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feedwater Pump (MFWP) 1-01 speed swings.
On March 19 reactor power was i
reduced to 60 percent to remove MFWP l-01 from service.
Corrective
maintenance was performed on the MFWP turbine control and returned to service.
-l Unit I was at 100 percent power at the end of this inspection period.
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Unit 2 was in Mode 5 at the beginning of the inspection period. The unit
entered Mode 4 on March 6 and Mode 3 on March 11.
Mode 3 initial startup i
testing-continued to the end of the inspection period.
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2 ONSITE RESPONSE OF. EVENTS (93702)
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2.1 Train A Sequencer Failure On February 26 and 27, 1993, Unit I experienced two separate ESF actuations
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because of a Train A sequencer fault.
The inspectors were in the control room
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at the time of the failure and followed the licensee's actions.
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inspectors observed good operator response during the recovery from automatic
equipment actuations.
Refer to NRC Inspection Report 50-445/9312;.
50-446/9312, paragraph 3.1.4, for a discussion of the events.
The inspectors will review the LER associated with this sequencer failure and follow up on
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IFI 445/9312-01 initiated in NRC Inspection Report 50-445/93-12; 50-446/93-12 i
for assessing work activities in progress during a subsequent inspection.
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i 2.2 MFWP l-01 Speed Oscillations
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On March 14, 1993, Unit I reactor power was reduced to approximately
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90 percent. MFWP l-01 had begun experiencing small speed oscillations of short durations 2 days earlier. These oscillations began to grow in magnitude
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and duration until they approached 400 rpm swings and lasted up to 10 minutes.
These larger speed changes begin to cause minor steam generator level and
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feedwater pump suction pressure oscillations.
Initial maintenance
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troubleshooting activities were not able to pinpoint' the cause of the
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problems; however, during the course of. troubleshooting, it i is found that the speed oscillation stopped when turbine speed dacreased below 4600 rpm. The
licensee reduced reactor power.in order to reduce feedwater tequirements,
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'thereby allowing MFWP 1-01 speed to be reduced to less than 4600 rpi, lhe
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inspectors. reviewed the licensee's re'sponse to the MFWP speed oscillations and
found it to be appropriate.
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The licensee brought in a vendor representative who assisted in the troubleshooting and collected various turbine and pump data.
This data was sent to the vendor's headquarters for_ analysis.
j The vendor identified the possible source of the oscillations as either a bad turbine speed control printed circuit board or the servo control associated
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with the pump's steam admission control valve.
On March 19 reactor power was
reduced to 60 percent power and MFWP l-01 was secured for corrective i
maintenance.
Both suspect components were replaced under Work Order 1-93-041580-00. The inspectors noted that work activity was well-coordinated including excellent management involvement. The pump was
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restarted later that day and Unit I returned to 100 percent power. The MFWP
operated without further incident through the end of the inspection period, t
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The control room operators' responded well to the Train A sequencer faults.
Conservative measures were implemented to mitigate the MFWP oscillations.
t Excellent management oversight was noted throughout the MFWP troubleshooting activity.
3 OPERATIONAL SAFETY VERIFICATION (71707)
3.1 Chemistry Observations
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i On February 24, 1993, the inspectors accompanied chemistry technicians taking j
samples from reactor coolant system Loop 4.
The samples were taken from sampling valves located inside the grab sample hood in the Unit l' primary sample room. The samples were taken in accordance with Procedure CHM-513A,
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Revision 4, " Operation of the Process Sampling System." Prior to taking the
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samples, the chemistry technicians ensured all precautions and prerequisites had been met.
Chemistry technicians took a nonpressurized and pressurized
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sample from reactor coolant system Loop 4.
The technicians followed the-instructions in the procedure.
The technicians also exhibited good
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radiological work practices throughout the evolution.
One technician read the.
actions to be taken as delineated by the procedure, while the second technician manipulated valves after repeating back the-procedure instructions.
Af ter the grab samples were gathered, they were taken to the chemistry hot laboratory and degassed for analysis in accordtace.with Instruction CLI-208,
-" Operation of the Gas Stripping Panel." The samples were analyzed and all
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parameters tested were within specifications.
3.2 Building Walkdowns T1e Linspectors performed detailed walkdowns of the. turbine electrical control, au.viliary, and safeguards-buildings.
Permanent. plant equipment was found to be well maintained.
In almost all. instances, defective equipment had been-
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- properly identified with work request tags, Minor discrepancies were
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identified to operations management'and= appropriate corrective actions were-j
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plant. equipment operation.
Plant housekeeping control was good.
3.3 Equipment Lubrication Controls The inspectors reviewed the licensee's program and its implenuentation for controlling plant equipment lubricants. The inspectors also reviewed the licensee's technical evaluation to change the type of lubricating oil used in the Unit 2 TDAFWP.
l The inspectors noted that plant equipment lubricants were controlled by Procedure TDM-803A, " Equipment Data Lubrication Requirements." The auxi_liary operators have the authority to add oil to equipment as needed. To assure that the correct oil is added, the licensee provided_ controlled copies of the applicable Turbine-Driven Manual (TDM) procedure in ehch of the lube oil lockers. These lockers are located in the turbine, auxiliary, and safeguards buildings'.
The inspectors noted that the Unit I and common equipment TDM:
section was mounted on the cabinet door;~however,-Procedure TDM-803B for Unit 2 equipment had not been placed at the auxiliary building lube oil locker. This oil locker provides replenishment oil for both units' equipment.
The licensee issued Procedure TDM-803A, Revision 1,-on October 24, 1992.
The inspectors noted that the TDM had not been_ routed to the auxiliary building oil locker, as it still contained Revision 0.
The inspectors also-found ~ that the Unit I turbine building lube oil locker had not received an updated revision of the procedure. The. inspectors and tM licensee reviewed the two different procedure revisions. Only one changc 9 the type of lubricant was identified. A procedure change notice had been made effective the day the inspectors brought the concern to the licensee for the Unit.2 TDAFWP.
A review of the licensee's program for'the control of operator aids is an IFI (445/9313-01; 446/9313-01). The IFl will review the licensee's process
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for updating the numerous operator aids located throughout the plant and the revision status of the installed operator aids. Additionally, a comparison of Unit 1/ Unit 2 operator aids will be accomplished.
During preoperational testing, the licensee identified that the Unit 2 TDAFWP thrust bearing was operating at bnusually high temperatures. After extensive troubleshooting activities, including input from the TDAFWP and oil vendors, the licensee decided to increase the viscosity of the oil and temperature-limits of the bearing.
Technical Evaluation 93-618 described the justification for increasing the -
bearing operating and trip setpoint temperatures.
This evaluation was based on discussions with the pump vendor (Ingersoll-Rand), data from the bearing-
-manufacturer's maintenance guide, and lubrication characteristics of various lubrication oils.
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The data indicated that Texaco Regal R+0 68 oil was an appropriate choice for
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the operating termperature ranges of the pump.
Regal R+0.68 oil was placed in the pump and' subsequent testing showed that the pump thrust bearing temperature stabilized at a temperature below the alarm and trip setpoints.
The inspectors determined that Technical Evaluation 93-618 supported the
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decision to change bearing temperature limits and lubrication requirements for the Unit 2 TDAFWP.
3.4 Emergency Core Cooling System Lineups a
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The inspectors verified that valves within the emergency core cooling system
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major flow paths were 'roperly aligned.
The inspectors walked down accessible portions of those systems and verified that the valve lineups were in
accordance with the opera ing procedures.
Required. auxiliary systems were found to be operable.
T's main control board indications were found to be consistent with the fie ' conditions.
y 3.5 Radiation Protection (RP)
The inspectors observed personnel entering the radiological control area at j
the Unit 2 access point.
It was noted that-the briefings on radiological
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technicians were posted in the Unit 2 safeguards building to assist in-I coverage of numerous work activities. On several occasions, the inspectors questioned the RP technicians about ongoing work in the radiological control
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area and found them to be cognizant of the activities, j
t 3.6 Security Program Implementation
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t The inspectors observed security access controls at the primary access point.
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Personnel and packages entering the protected. area were properly surveyed.
Observation of personnel entry into vital areas' and plantL perimeter were t
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All observed activities were well implemented and perimeter monitoring equipment was operable.
3.7 Conclusions
Chemistry technicians utilized good self-verification and radiological practices to obtain and ' analyze a primary sample.
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The' licensee had established appropriate controls for adding oil to equipment by the auxiliary operators. However,- the control' of the ' operator aids used to
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select the proper lubrication for equipment, located on two lubrication
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lockers, was not maintained.
It was found that the procedure revision changed.
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only'the organization of the procedure and did not constitute a safety
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concern.
IFl 445/9313-01; 446/9313-01 was opened to review the :ontrol-and
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dissemination of operator aids.
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The technical evaluation to change the type of oil in the TDAFWP was well supported.
The security and radiation protection programs were appropriately implemented.
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4 MAINTENANCE OBSERVATION (62703)
4.1 Handswitch Replacement q
Electrical maintenance technicians were observed performing corrective i
maintenance on twe local valve operator position handswitches.
Work Orders 1-92-22059-00 (1-HS-2406, Steam Generator 2 sample line outside reactor-
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containment isolation valve handswitch) and 1-92-001430-00 (1-HS-4176, pressurizer steam space sample outside reactor containment isolation valve
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handswitch) were written to replace the handswitch modules; however, the technicians thought the work packages were to replace the individual
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handswitches.
The technicians began the work on Valve Handswitch 1-HS-4176 and removed the handswitch module.
While preparing to replace the handswitch, the technicians noted that the work package had a step to replace the entire
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module verses the handswitch.
The' technicians immediately stopped the work
activity and contacted their supervisor.
Subsequent followup indicated both-packages had been written to replace the respective handswitch modules. The work packages were revised to change the scope of the task and were completed the next day.
Both work packages required entry into Technical Specification limiting -
conditions for operation.
The technicians were not aware of the correct job scope and were not fully cognizant of the work package requirements prior to starting the maintenance activity.
The prejob briefing conducted by the supervisor was not appropriate in that the scope of the work activity was not discussed.
The valve handswitch was removed from service for approximately 30 minutes.
The inspectors discussed these observations with an electrical maintenance manager who indicated that this particular job performance did not meet management's expectations.
The ISEG identified a similiar concern in ISEG Field Note ISEG-fN-93-97.
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Three. instrumentation and control (I&C) technicians were observed working on the thlit 2 solid state safeguards sequencar train B without having performed an adequate prejob briefing.
4.2 Various Maintenance Activities
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The inspectors observed the following maintenance' activities:
Mechar' al maintenance technicians performed corrective maintenance on
Valve. 8'95B, Coolant Charging Pump 1-0? discharge valve. Work Order 1-91 033701-00 involved reworking the remote linkage _ due to difficulty when operating the valve remotely. The work package contained the proper approval signatures and the work order was identified on Clearance ~1-92-04366.
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-8-I&C technicians replaced motor-driven. auxiliary feedwater Pump 1-02
discharge pressure Transmitter 1-PT-2454.
This Rosemount transmitter was an older model (oil-filled transmitter) that was being replaced by the licensee. Work Order 1-93-037435-00 verified that the old transmitter was in calibration, then removed and replaced the transmitter with the new style and performed a-channel calibration on the newly installed transmitter. All "as-found" data was satisfactory.
The lifted-leads were properly controlled and documented in accordance with procedure requirements.
Replacement and alignment of Train A X-01 uninterruptible power supply-
air-conditioning unit.
Electrical and mechanical maintenance department, personnel were coordinating work activities on the compressor unit.
Supervisors from both departments observed the work.
The work activity was conducted in accordance with Work Order 1-93-038927-00.
Portions of the calibration associated with the replacement of thz
control board and servo control on MFWP 1-01 (Work
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Order 1-93-041580-00).
Procedure ICI-4217A, Revision 1, " Calibration of Feedwater Pump Turbine FWPT 1A Speed Control," was used by the technicians to calibrate the components.
It was noted by the inspectors that the I&C managers oversaw the entire activity.
The technicians utilized good work practices and self-verification techniques.
Management's expectations were met for each of these work activities.
4.3 Conclusions The work activities were appropriately planned.
In general, good work practices were observed, including the use of self-verification techniques.
An instance was observed where electrical maintenance personnel were not fully -
cognizant of the work requirements. Although the work activity did not result in a safety concern, safety-related equipment was out of service longer than required for completion of the work activity.
5 $URVEILLANCE OBSERVATIONS (61726)
5.1 Analog Channel Operational Test The inspectors observed two I&C technicians performing an analog channel-operational test on Unit -l refueling water! storage tank' level Channel 0933.
The surveillance was being conducted under Work Order 5-93-500988-AB and-Procedure INC-7881A, Revision 3, " Analog Channel Operational Test and Channel Calibration Refueling Water Storage Tank Level Protection Set IV, Channel.0933," Section 11.0.
The. "as-found" data was within' specification; therefore, no adjustments to the instrumentation were necessary. =A review of the previous surveillance (Work Order 5-93-500908-AA, dated February 8, 1993)
indicated that the instrument had required no previous recalibration. The f
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comparison of the "as-found" data between the two surveillances indicated ~no j
instrument drift. The technicians exhibited good use of procedures throughout j
the surveillance.
5.2 Service Water Operability Test j
The inspectors observed the performance of surveillance testing on Train B
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service water system pump and valves (Work Order 5-93-502498-AB and
Procedure OPT-207A, Revision 4, " Service Water System Operability-l
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Verification," Section 8.3.2).
h.e on-shift crew held a thorough prejob brief
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ensuring all participants understood the sequence of the procedure and their individual responsibilities.
Service Water Pump 1-02 had been placed on an increased surveillance frequency-i due to previous vibration data being in the alert range.
The pump had been
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worked during the outage and new baseline vibration data had not been
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incorporated into the procedure prior to the previous-surveillance conducted on February 2,-1993.
The inspectors noted that the vibration data collected-
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during the surveillance did not correspond to the previous surveillance and
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postwork baseline vibration data.
The in-service testing. coordinator was-l contacted'concerning the discrepant readings and he. discovered that the wrong-j bearing'information had been recorded on the test data sheet
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(Form OPT-207A-5). The surveillance data sheet was corrected.
j The cinspectors independently verified calculated data and acceptance criteria.-
l All equipment was determined to operate satisfactorily.
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During the_ surveillance, the inspectors noted that Section 8.3.2 required the l
operators to verify the pump discharge valve 10 percent open; however, the
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step was not clear as to the intent of local valve position verification. The
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unit supervisor's actions to clarify the step prior to continuing with the i
test was viewed by the inspectors to be conservative. :The operators _used i
excellent self-verification and, generally, good communications during the
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surveillance.
i 5.3 Solid State Protection System Logic Test j
The inspectors observed the licensee conduct the surveillance test i
Procedure OPT-445A, Revision 2, " Solid State Protection System, Train 'A'
Actuation Logic Test." The test was authorized and approved in Work j
Order 5-93-500269-AA. The licensee has instituted a policy of allowing only.
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designated. reactor' operators;(R0s) to perform this surveillance.since_ several
reactor. trips have occurred during previous tests.
The designated R0- _ _
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performed' an. excellent presurveillance brief with the participating members of.
.i the on-shift' crew. Copies of the' applicable procedures;were marked 'and.given-t to.the auxiliary operators performing local breaker manipulations. The
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designated R0 discussed the performance of the test with.the on-shift R0 to determine'what information the on-shift R0 wanted in relation to alarms and equipment. manipulations.
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.The designated RO was assisted by the balance-of-plant R0 during the-j performance of the surveillance.
Good communications.between the two R0s and
auxiliary operators were noted.
The R0s consistently used good self-
.j verification techniques.
l 5.4 Trio Actuating' Device Operational Test (TAD 0T) Surveillance
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Three meter and relay personnel were observed performing.TADOTs on Unit 1 RCP
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Channels I and 2 underfrequency relays (Work Orders 5-92-502360-AD j
and 5-92-500709-AD).
Procedures MSE-SI-0665W and -0665X, Revision 2, " Unit 1,
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Channel 1(2), RCP Underfrequency Relays Trip Actuating Device Operational Test j
Surveillance," were used throughout the test.
The inspectors noted that j
Step 8.2.7 referenced a switch that was not adequately labeled. The cabinet
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contained two " Normal / Test" switches that were alpha-numerically identified, l
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whereas the procedure listed a noun name for the switch. The inspectors i
discussed the labeling concern with the lead technician.
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Channel 1 RCP underfrequency relays passed the TADOT surveillance test and
required no recalibration. However, Channel 2 RCP underfrequency-relay
required recalibration.since it was not within the tolerance of. Design i
Document El-2400.
However, Channel 2 RCP underfrequency relay was within the
Technical' Specification tolerance.
The technicians' exited Section 8.2,
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"Underfrequency Relay (UF) Trip Actuating Device Operational Test," and
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calibrated Underfrequency Relay 81/lA2 in accordance with Section 8.3,
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"Underfrequency Relav 81/lA2_ Recalibration." After the technicians completed
calibrating the relay, the inspectors cbserved the lead technician performing j
steps not contained within the procedure.
The technician explained that these j
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additional steps were needed to ensure that' the relay would not actuate. The j
inspectors pointed out that these steps should be contained within_the'TADOT-i procedure to prevent technicians from missing a step. The inspectors-
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discussed this observation with the assistant electrical maintenance i
supervisor and he indicated that he would review the procedural weaknesses with the lead technician.
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5.5 Unit 2 TDAFWP Steam Supply Line Check Valve Testing On March 13, 1993, the inspectors observed the performance of f
Procedure OPT-206B, Revision 1,."AFW System," Section 8.1.6, "TD AFW PMP 2-01
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ASME Section XI Test." This test verifies, in part, that the check valves j
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-(2AF-0142 and 2AF-0143) located in-the.TDAFWP-steam supply lines are' ope abic.
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The unit supervisor-conducted-an extensive-pretest-briefing. This included
. establishing specific assignments and precautions to be observed during the-j test.
Good communications were maintained between the control room and-
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personnel performingithe_ test.
The inspectors noted that the field support j
supervisor's activities were directed at performing the. auxiliary operator
duties.instead of' overseeing the auxiliary operator activities.
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the field support supervisor and-auxiliary operator. conducted the activities-
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The surveillance was tompleted with j
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satisfactory results obtained.
The inspector subsequently discussed the
~ utilization of the field suppcrt supervisor as an extra auxiliary operator
with operations' management.
5.6 Conclusions
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The surveillance program was appropriately implernented.
Pretest briefings
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Personnel performance during the testing activities was generally very good.
The' inspectors noted that the RCP TADOT surveillance could result in performance problems.
6 FOLLOWUP ON CORRECTIVE ACTIONS FOR VIOLATIONS (92702)
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(Closed) Violation 445/9243-01: Containment Wide Range Level Instrument
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Channel Sensors Not Calibrated In October 1992 it was determined that the Units 1 and 2 channel calibrations
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for the containment postaccident water level instrumentation did not include a -
check of the level sensors.
The licensee subsequently determined that, when surveillance Procedures INC-7739A, Revision 2, "CH CAL CNTMT Level Train A CH 4779," and INC-7740A, Revision 2, "CH~ CAL CNTMT Level Train B CH 4781,"
were revised, the sensor calibration requirements were inadvertently deleted.
The licensee has revised the Unit 1 procedures to include the calibration of
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these sensors.
The applicable Unit 2' procedures have also been revised.
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of the causes for this event was determined to be inadequate communications
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during the procedure revision process.
In particular, procedures requiring major revisions did not utilize change bars to identify the sections which had
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been changed.
Procedure STA-202, Revision 23, " Administrative Control of CPSES Nuclear Engineering and Operations Procedures " has been revised to require a detailed description of procedure changes. These corrective actions
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were determined to be appropriate.
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7 0NSITE REVIEW 0F LICENSEE EVENT REPORTS (92700)
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i The inspectnr reviewed the below listed LERs to determine whether corrective actions were adequate and whether the responses-to the events were adequate.
and met regulatory requirements, license conditions, and commitments.
7.1 (Closed) LER 90-031:
" Failure to Compl_y With Technical Specification.
Action Statement Due to Nonconservative Alarm Setpoints" On July 23, 1990, the licensee declared the containment atmosphere radioactivity monitoring _ system inoperable because the steady. state background
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activity levels were above the alarm'setpoint level. On August 10, 1990, it was eterm ned that the containment air cooler condensate flow rate alarm
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setpoints were set nonconservatively; It was later determined that the nonconservatism had been input in February 1990. With both monitoring' systems inoperable, the Technical Specifications required that the unit be shutdown by
August 22, 1990; however, this~was~not accomplished.
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.The licensee determined that this ev'ent resulted from two principle root i
causes.. The first involved the use of nonconservative assumptions by the
engineering staff when the alarm setpoints were developed..In addition, the design basis documents were found to have unconfirmed alarm setpoints.
A memorandum, CPSES-9103726, dated February 18, 1991, was issued to the I
engineering staff reiterating their responsibility to provide accurate-
information throughout the design procest In September 1990 the licensee
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any unconfirmed or nonconservative design assumptions.
The inspectors found
these corrective actions to be appropriate.
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J 7.2 t' Closed) LER 90-039:
" Inadequate Design Implementation Leading to
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Potential For Overpressurization of Containment Electrical Penetration
- j Assemblias" In October 1990 the _ licensee identified the potential for electrical.
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panetration seal assembly overpressurization because of a postulated failure in the nitrogen pressurization system. The pressure' regulator valves were-i closed to ensure that an overpressurization event could not occur.
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Tno licensee has revised Flow Diagram M1-0243, " Plant Gas Supply System," to
' include the plant gas subsystems.
Design basis Document DBD-EE-062,
Revision 3, " Containment Electrical Penetration-Assemblies," was revised to includ_e system interface requirements. -Procedure 50P-511, Revision 4,
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" Nitrogen Gas. System,'" was revised to require that the nitrogen gas manifold
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isolation valves be maintained closed and should preclude inadvertent R
overpressurbation of the penetrations.
l The inspectors have confirmed that a similar concern does not exist for Unit.2 because of design differences.
1; 7.3 (Closed) LER 91-009:
" Automatic -Isolation Of Steam' Generator Blowdown Due To Cognitive Personnel Error" j
In March 1991, with the _ unit in cold shutdown, the licensee was in the process
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of lowering the level in the: steam generators. 'When the level reached- '
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25 percent narrow range in Steam Generator 1-03 an-ESF actuation occurred.
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' t The evolution was being performed in accordance with Procedure IP0-005A, l
Revision 9, " Plant Cooldown From Hot Standby to_ Cold Shutdown." This
E procedure.did not require the solid state protection' system mode. switch to..be y
placed in the Mode 5/6 position until the-steps where the' event' occurred had
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been completed. The: licensee determined that the personnel performing'.the'
l activity were not fully-cognitive of the-type.of activity which cons'tituted an ESF actuation.
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The ' licensee provided lessons learned training on when an ESF actuation -is I
Revision 4, "Nonroutine Reporting," was' revised to identify equipment and..
-l allowed.to occur and when it is not reportable.
Procedure'STA-501L
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L-13-protective circuitry which would require a reportability determination.
The inspectors found these corrective actions to be appropriate.
7.4 (Closed) LER 91-012:
" Potential Gas Binding of Centrifugal Charging Pumps Due to Voids in the Boric Acid Gravity Feed System" During ultrasonic testing of the centrifugal charging pumps; the licensee identified the presence of voids in the alternate borating line and gravity feed line from the boric acid storage tank.
Venting requirements were established for the gravity feed line to the boric' acid storage tank.
Periodic' monitoring of the gravity feed line for hydrogen accumulation was implemented.
Subsequent monitoring of the gravity feed line did not identify additional instances of voiding.
Technical Evaluation TE-SE-91-910 recommended cessation of perioitic venting. This-recommendation was based on no evidence of-additional gas accumulation, the line being adequately ventible, and Procedure 0WI-404, Revision 0, " Operations Vent and Drain Guidelines,"
providing appropriate guidelines for venting activities.
The licensee's evaluation was found to have properly considered Westinghouse Letter WPT-12930, Hydrogen Formation, dated October 29, 1990.
As part of the closecut review of this LER, the inspector idestified a related-
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concern, documented in Technical Evaluation TE 93-0509, that during a safety injection actuation signal, gas from the volume control tank could be injected into the centrifugal charging pump suction line. This condition could occur if the volume control tank pressure was greater than that provided by1the refueling water storage ~ tank.
The. Units 1 and 2 centrifugal charging system lineup has been revised to preclude this event, and the lines are vented once every 14 days. The inspectors are reviewing this condition for an industry generic concern and is identified as IFI 445/9313-02; 446/9313-02.
7.5 (Closed) LER 91-01f:
" Technical Specification Violations Due to Safety Chiller Beina Inopgrable Greater Than the Allowed Outage Time of the Supported-Systems" In October 1989, prior to initial fuel load, the licensee replaced the Train A safety chiller oil sump level ' switch. Approximately 18 months later, it was determined that the level switch was not_ operating in accordance with its intended design.
TFe switch was improperly closing on a high sump level and -
opening on a low sump level, causing some of.the oil not to return to the sump.
-The licensee determined that the switch failure was the result'of a manufacturing defect.
Similiar switches in the warehouse were verified to be operating correctly. :The licensee determined that the postwork test wa's.not
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adequate.to-identify the switch. defect. Training on this event and-the postwork test guidelines was provided in January and February 1992. The
- inspectors _found these corrective' actions to be appropriat.
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7.6 (Closed) LER 92-009:
" Reactor Trip Caused by Personnel Error During
- Testina" l
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The licensee's corrective actions associated with this event were reviewed-during the special inspection documented in NRC Inspection f
Report 50-445/93-12; 50-446/93-12, Section 4.
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7.7 (Closed) LER 92-012:
" Reactor Shutdown initiated Due to Both Control
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Room Air Conditioning Trains Inoperable" l
On June 3, 1992, a unit shutdown from 100 percent power was initiated because i
of both control room air. conditioning trains being-inoperable.
The shutdown
was terminated at 8 percent power. The in:,pectors observed the licensee's
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action to recover the air conditioning trains. The-observations' associated
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with this event are' documented in NRC Inspection Report'50-445/92-14; 50-446/92-14, Section 5.4. 'It was identified that the oil return' valves were -
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throttled open too far, resulting in the sump oil becoming saturated with
refrigerant.
I The licensee revised Procedure MSE-PX-7330, Revision 0, " Control Room HVAC
' Annual Inspection," to throttle the oil return valve to = 1/4 turn open..A
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plant label has been installed on each oil return valve identifying that its
position is controlled by Procedure MSE-PX-7330. The-inspectors concluded
these corrective actions were adequate.
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7.8 (Closed) LER 92-013:
" Personnel Error leading to the Loss Of Cooling
- Water Flow to the Spent Fuel Pool"
The licensee's corrective actions associated with this event were reviewed during the special inspection documented in NRC Inspection
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-Report 50-445/93-12; 50-446/93-12, Section 4.
l 7.9 (Closed) LER 92-016:
"High Winds Damage Transformer Causing an
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Engineered Safety features Actuation" i
In June 1992 high winds damaged an electrical line between Unit 1. Station
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l Transformer IST and the motor-operated disconnect switch. During the transfer
{l to'the alternate power source, an ESF. actuation occurred as expected.
The licensee determined that the electrical line between the transformer and the. disconnect switch was not adequately supported. A review of other offsite-f power line supports identified two additional concerns. TheLlicensee-i initiated design _ modifications for these:three electrical _ lines. 'The j
modifications were completed in December 1992.and the inspectors concluded
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that these corrective actions were adequate.
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17.10 (Closed) LER 92-022:
" Manual Reactor Trio Due to Feedwater Flow Control
.l Valve Failure" i
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On October 12, 1992, a manual reactor trip was initiated because of a partial j
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loss of feedwater flow. The licensee's initial response to the event is
documented in NRC Inspection Report 50-445/92-47; 50-446/92-47, _ Section 2.1.
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It was determined that the Steam Generator No. 4 flow control valve pressure regulator had failed, causing the partial loss of feedwater flow.
A 0-60 psig
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pressure regulator had been installed when a 0-125 psig regulator was
required. The master parts list had incorrectly identified the 0-60 psig as
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an acceptable replacement.
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The licensee verified that the remaining pressure regulators installed in
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Units 1 and 2 were correct.
The master parts list was revised to.specify the
.i 0-125 psig pressure regulator for the flow control valve. The immediate
corrective actions were found to be adequate to resolve the component i
deficiency. A quality assurance deficiency, documented in Operations j
Notification and-Evaluation Form FX-92-1255, addressed a potential negative trend in _ general material control.
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7.11 (Closed) LER 92-024:
" Personnel Error leading to the Invalid
Performance of Technical Specification Surveillance"
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The licensee's corrective actions to ensure surveillance activities are adequate,' including the verification that the entire instrument channel is in
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calibration, is documented in Section 6.
i 7.12 (Closed) LER 92-027:
" Personnel Error Leading to inadvertent Actuation i
of Main Steam Isolation Valves During Testing"
.i During performance testing activities on December 20, 1992, two main steam j
line isolation valves were inadvertently closed. The plant was in Mode 4 at
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the time of the event. A test engineer was connecting test leads when he l
grounded one test lead to the cabinet causing the actuation.
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i The licensee determined that the event resulted from personnel error when the l
test engineer grounded the test lead.
In addition, it was found-that the
engineer.had relatively little experience with connecting test equipment to
plant components.
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i The licensee has initiated extensive actions to address and reduce personnel errors. These' actions were reviewed during the'special inspection documented-
-j in NRC. Inspection Report 50-445/93-12; 50-446/93-12..
.A performance
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enhancement review committee;was held on December 23, 1992,3 to determine what l
corrective actions were needed to address the personnel error and any other
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areas of concern rega_rding the event-A memorandum to all maintenance
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engineering personnel was issued on-January 7,1993, to reiterate management's-
expectations.for working.on plant equipment.
These corrective actions were t
~found to adequately address the event.
IF1 445/9259-02, identified in NRC-
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Inspection Report 50-445/92-59; 50-446/92-59, Section 4.3, is open to review
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the licensee's ' control and -installation of electrical jumpers c
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ATTACHMENT 1
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1 PERSONS CONTACTED 1.1 TU ELECTRIC 0. Bhatty, Senior Licensing Specialist W. J. Cahill, Group Vice President, Nuclear Engineering and Operations R. D. Calder, Manager, Reactor Engineering, Site P. C. Chin, Senior Engineer
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J. W. Donahue, Manager, Operations S. Ellis, Power Ascension Manager W. G. Guldemand, Manager, independent Safety Engineering Group C. Harrington, Mechanical Engineering Supervisor
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T. A. Hope, Site Licensing Manager
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B.1. Lancaster, Manager, Plant Support F. W. Madden, Mechanical Engineering Manager D. M. McAfee, Manager, Quality Assurance l
P. Mills, Senior Quality Assurance Specialist J. W. Muffett, Manager of Technical Support / Design Engineering M. W. Sunseri, Manager, Maintenance Engineering C. L.. Terry,'Vice President, Nuclear Engineering and Support R. G. Withrow, Component Test Supervisor 1.2 NRC Personnel W. B. Jones, Senior Resident Inspector i
G. W. Werner, Resident Inspector
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The personnel listed above attended the exit meeting.
In addition to these personnel, the inspectors contacted other personnel during this inspection period.
2 EXIT MEETING i
An exit meeting was conducted on March 19, 1993. During this meeting, the inspectors reviewed the scope and findings of the report.
The licensee did not identify as proprietary any information provided to, or reviewed by, the inspec* ors.
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