ML20045F552
| ML20045F552 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 06/28/1993 |
| From: | Yandell L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20045F543 | List: |
| References | |
| 50-445-93-22, 50-446-93-22, NUDOCS 9307080024 | |
| Download: ML20045F552 (18) | |
See also: IR 05000445/1993022
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APPENDIX B
U.S. NUCLEAR REGULATORY COMMISSION
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REGION IV
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Inspection Report:
50-445/93-22
50-446/93-22
Operating Licenses:
NPF-89
Licensee:
TU Electric
Skyway Tower
400 North Olive Street
Lock Box 81
Dallas, Texas 75201
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Facility Name:
Comanche Peak Steam Electric Station, Units 1 and 2'
Inspection At:
Glen Rose. Texas
h-spection Conducted:
April 28 through May 29, 1993
Inspectors:
W. B. Jones, Senior Resident Inspector
D. N. Graves, Senior Resident Inspector
G. E. Werner, Resident Inspector
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Approved;
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L. A. Yahdell, Chief, Project Section B
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Division of Reactor Projects
Inspection Summar_y
Areas Inspected (Unit 1):
Routine, unannounced inspection of plant status,
onsite response to events, operational safety verification, engineered safety
features walkdown, maintenance and surveillance observations, followup on
corrective actions for a violation, and other followup.
Areas Inspected (Unit 2):
Routine, unannounced inspection of plant status,
operational safety verification, and maintenance observation.
Results (Units 1 and 2):
The licensee responded correctly to the Unit 1 safety injection
accumulator main control board indications and initiated prompt actions
to restore the accumulators to within the Technical Specification bands.
The procedural weaknesses with the chemistry sampling procedures were
appropriately addressed (Section 2).
The adequacy of the licensee's engineering assessments for the
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instrument air and diesel generator (DG) starting air systems were
9307080024 930630
ADOCK 05000445
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mixed. The instrument air system concerns presented to the
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Station Operations Review Committee (50RC), as the basis for the
SORC authorizing a design modification, were not well supported by
the engineering evaluations.
A concern was identified that all
the conditions which have resulted in equipment reliability
problems may not have been presented to the SORC. However, the
engineering conclusions for the DG starting air system were well
supported and appropriately considered the systems maintenance
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history and the short and long term effects on system reliability-
(Section 3.1).
Major flow path valves within the emergency core cooling system were
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positioned in accordance with Mode 1 lechnical Specification operating
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requirements (Section 3.2).
The security and radiation protection programs were well implemented.
Radiological hot spots in the plant were well controlled (Sections 3.3
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and 3.4).
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The auxiliary feedwater system surveillance requirements were
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implemented in accordance with the Technical Specification requirements
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and were consistent with the established Final Safety Analysis Report
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design basis statements.
The open work activities were appropriately
assessed by the licensee and should not have an. appreciable impact.on
system performance (Section 4).
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The development of the flow control valve (FCV) controller card work
order and instructions,-prejob briefing, activity coordination between
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operations and instrumentation and control (I&C), and the unit
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supervisor's command and control were_ outstanding. Management-oversight
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of this high risk activity was notable (Section 5.1).
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A routine maintenance work activity on the control room air conditioning
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unit was not conducted in accordance with management's established
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expectations for self-verification.
The work activity impact sheet
requirements were not adhered to, for the control of freon in the system
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(Section 5.2).
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A violation was identified for the failure to issue a technical
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evaluation for deferring a safety-related component preventive
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maintenance (PM) activity.
An issued technical evaluation for a
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nonsafety-related component deferred PM was inadequate because it failed
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to assess the impact on the equipment operability. The technical
evaluation documented a PM program weakness with outage and conditional
frequencies but failed to understand and address the generic
implications (Section 5.2).
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The licensee implemented the surveillance test program in accordance
with the Technical Specification surveillance requirements.
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personnel utilized excellent self-verification techniques (Section 6).
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Summar_y of Inspection Findings:
Violation 445/9322-01; 446/9322-01 was opened (Section 5.2).
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Violation 445/9141-01 was closed (Section 7).
Inspection followup Item 445/9141-02; 446/9141-02 was closed
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(Section 8).
Attachment:
Attachment 1 - Persons Contacted and Exit Meeting
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DETAILS
1 PLANT STATUS (71707)
At the beginning of this inspection period, Unit 1 was at 100 percent power.
Short term power decreases were conducted for planned. surveillance testing.
At the beginning of this inspection period, Unit 2 was operating at
approximately 48 percent reactor power with various initial startup testing
activities in progress.
On May 4, 1993, following a reactor power reduction
from 48 percent to approximately 23 percent, in preparation _for a~ remote
shutdown operability test, the unit was manually tripped in response to the
spurious closure of the feedwater isolation valve.
The unit was returned to
Mode 1 on May 5, 1993
Remote shutdown testing was completed on May 6, 1993,
and the turbine generator trip with loss of offsite power test was performed
on May 8, 1993. On May 20, 1993, with Unit 2 operating at approximately
73 percent power, an automatic turbine trip / reactor trip occurred as a result
of the loss of primary water flow to the generator stator.
Following this
event, the licensee elected to place the unit in Mode 5 and initiated a
planned surveillance outage. ~ At the conclusion of this reporting period, the
licensee's outage work planning activities were in progress.
2 ONSITE RESPONSE OF EVENTS (93702)
2.1
Safety injection Accumulator Parameters Exceeding Technical
Specification Limits
On April 12, 1993, during routine accumulator sampling, the pressures in
Accumulators 1-02 and 1-03, and the level in Accumulator 1-03 were decreased
to below the Technical Specification 3.5.1 limits of 623 psig and 39 percent.
An operator trainee scanning the control boards in the main control room
observed the abnormal indications at 1:10 p.m. and inmediately informed the
reactor operator and unit supervisor.
No alarms were received. Operations
personnel entered Technical Specification 3.0.3 due to . accumulator pressures
in two accumulators being out-of-tolerance and Technical Specification 3.5.1
due to the accumulator level that was low.
Both Technical Specifications
required that actions be taken within I hour to restore parameters to within
limits or proceed to lower modes of operation within the following_6' hours.
Chemistry personnel were directed to secure sampling and informed of the
out-of-specification conditions.
Immediate actions were taken by the
operators to restore level and pressure in the affected accumulators and were
completed at 1:28 p.m., at which time the Technical Specification action
statements were exited. Operations Notification and Evaluation (ONE) Form 93-
923 was initiated to document and evaluate the circumstances surrounding the
event.
The cause of the out-of-tolerance conditions was determined to be a failed
pressure regulator in the common sample line from the accumulators.
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sample lines were routinely purged for a specific length of time based on
sample flow rate.
The failed regulator caused a relief valve in the common
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sample line to lift and provided a path for excessive flow from the
accumulators during purging.
The sample line was purged for each accumulator
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prior to its respective sample, with an excessive loss of inventory from each
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sampled accumulator during the process accounting for the decreased level and
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pressures.
The operators detected the abnormal conditions while sampling of
the third accumulator was in progress and ordered sampling secured.
The licensee's review of the computer data associated with the event concluded
that, although the control board meters indicated that two accumulators were
out-of-tolerance, only one accumulator,1-03, had actually exceeded the
Technical Specification pressure and level limit.
The lowest pressure
indicated by the computer data acquisition system was 617 psig. While this
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was below the Technical Specification limit of 623 psig, it was still above
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the design basis minimum value of 588 psig and the accumulator could have
performed its intended design function. The data acquisition system provided
a more accurate indication of system parameters by removing the meter
inaccuracies from the indication instrument loop.
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The lack of alarm indication was reviewed and the inspectors noted that the
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alarm setpoints for accumulator level and pressure were below the Technical
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Specification limits. Technical Evaluation OP-90-969 had been initiated in
March 1990 to assess the alarms for accumulator level and pressure not
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annunciating when the indicated parameters were outside the Technical
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Specification limits. Technical Specification Interpretation 009, Revision 0,
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" Emergency Core Cooling Systems," issued November 11, 1991, appropriately
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addressed this condition.
Sufficient margin was determined to exist between
the Technical Specification specified parameters and the design basis
parameters, that a system operability concern did not exist. With the
existing equipment, a change in the alarm setpoints to coincide with the
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Technical Specification limits is not feasible since the narrow allowable band
together with the instrument inaccuracy of 3.7 percent of the instrument band
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would enable both the high and low alarms to actuate. simultaneously and would
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create a chronic nuisance alarm. The licensee had adequately demonstrated
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thrcugh its Technical Evaluation that a safety concern does not exist with the
alarm setpoints being above and below the Technical Specification limits.
To
re-emphasize operator awareness of accumulator parameters during sampling
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evolutions, the licensee issued Lessons Learned SR 93-065 dated April 26,
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1993.
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Major corrective actions implemented from the licensee's root cause analysis
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included evaluation and replacement of the failed pressure regulator, changes
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to the chemistry sampling procedure to ensure adequate monitoring of
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accumulator parameters during and following sampling, and limiting sampling to
one accumulator per unit per 24-hour period.
The licensee issued a memorandum
reinforcing the operator's responsibility to remain cognizant of evolutions
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that could change plant status.
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2.2 Conclusion-
The licensee responded correctly to the main control board indications and
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initiated prompt actions to restore the accumulators to within the Technical
Specification bands. The procedural weaknesses with the chemistry sampling
procedures were appropriately addressed.
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3 OPERATIONAL SAFETY VERIFICATION (71707)
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The inspectors conducted control room observations and plant inspection tours
and reviewed logs and lic'ensee documentation of equipment problems.
Security
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activities were observed at the primary access point and from the alarm
stations.
Through in-plant observations and attendance of the licensee's
plan-of-the-day meetings, the inspectors maintained cognizance over plant
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status and Technical Specifications action statements in effect.
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3.1 Air Systems Reliability
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3.1.1
Instrument Air System
On April 27,1993, Unit 1 experienced a partial loss of instrument air.
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system lineup consisted of lead instrument air compressor (IAC) 1-02 (rotary
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compressor) with IAC 1-01 (reciprocating compressor) in standby.
Swing
IAC X-02 (rotary compressor) had been removed from service in order to add oil
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to the compressor.
IAC 1-02 tripped and could not be restarted. With'
1 AC X-02 unavailable, IAC 1-01 attempted to maintain system pressure but did
not have the necessary capacity.
System pressure was restored after
operations concurred with the system engineer to start IAC X-02 with the low
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oil level.
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The inspectors were in the control room during the partial loss of instrument
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air. Operators responded to the loss of instrument air in accordance with
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Procedure ABN-301A, Revision 4, " Instrument Air System Malfunction."
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Operations Notification and Evaluation (ONE) Form 93-953 was initiated by the
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operations department to document the partial loss of instrument air.
Comments on the ONE Form suggested that instrument air usage was excessive and
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that engineering should evaluate.
Subsequentl.y, the inspectors reviewed the
in:trument air system to determine if the system was able to function as
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designed, and if maintenance and engineering support had been appropriate
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considering the importance of the nonsafety-related system.
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The inspectors reviewed NRC Generic Letter 88-14, a licensee task team report,
maintenance and surveillance activities, and quality assurance audit
activities related to the instrument air system.
Internal licensee
documentation of equipment / system problems were also reviewed to assess how
well management had been informed of the system status.
Additionally,
conversations were conducted with the system engineers, Independent Safety
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Engineering Group (ISEG) personnel, design engineers, operations personnel,
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and engineering management in an attempt to understand system problems,
planned modifications, and allocation of resources.
The inspectors attended a SORC meeting where engineering personnel were
reviewing Design Modification (DM)93-022, " Trim Coolers for the Instrument
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Air Rotary Compressors to Cool Intake Air and Cooling. Water Supply." This
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DM 93-022 intends to reduce the maximum seasonal ambient and cooling water
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temperatures seen by the IACs located in the turbine buildings. Maximum
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seasonal operating temperatures have been measured as greater than the rotary
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air compressors manufacturers maximum allowable temperatures.
Engineering
personnel presented a forecast of almost certain instrument air' system failure
(99 percent) for this summer precipitated by inadequate cooling if the DM was
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not installed. Numerous component failures were listed as having been
contributed to by exceeding maximum operating temperatures.
The DM was
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approved and installation of the cooling equipment began for IAC 1-02.
The inspectors reviewed instrument air technical evaluations, quarterly
trending reports, and had detailed discussions with several instrument air
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system engineers.
The licensee was unable to identify any engineering
evaluations that related the various instrument system failures to overheating
as was presented to SORC.
Reviews of work history did show an apparent
increase in system failures during the summer months, although similar
failures were noted to occur at other times of the year. A review of the
corrective maintenance work history did not indicate that the system was
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troubled or had a large amount of corrective maintenance work items.
System engineering management agreed that the engineering documentation and
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the corrective maintenance work history did not support the presentation made
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to 50RC for approval of DM 93-022.
Engineering management indicated that part
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of the failure to properly document the instrument air system historical
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problems was due in part to the numerous and scattered reporting criteria
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contained within station and engineering procedures.
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The licensee has formulated a schedule to revise the following procedures:
Procedures STA-512, " Failure Analysis"; STA-680, " Equipment History Program";
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STA-514, " Nuclear Plant Reliability Data System Program"; REl-502, " Equipment
History Trending"; TSP-510, " Nuclear Plant Reliability Data System"; and
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STA-736, " Equipment Performance Monitoring Program." The licensee _ identified
the procedure revisions as an iterative process to best identify the
attributes necessary to effectively trend and identify equipment problems.
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addition, the supervisor of technical support indicated that the repetitive
maintenance program was being reviewed, and changes to the procedure and
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software were planned.
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The inspectors did find that the various instrument air system engineers were
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knowledgeable of the various component failures; however, not all agreed that
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high operating temperatures were the root cause for the failures or air
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capacity problems during the summer months.
Although the instrument air
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system had not been documented as a troubled system, engineering personnel and
senior management were sensitive to the importance of a reliable instrument
air system.
Routine discussions at the daily plant meetings kept senior
management cognizant of the instrument air problems and proposed solutions.
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As an interim measure, the licensee installed a temporary high capacity rental
air compressor to supplement the permanent plant IACs. Additionally, the
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instrument air system engineer performed Technical Evaluation 93-873 which
requested operations to align two rotary air compressors (IACs 1-02 and X-02)
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in parallel to prevent the rotary compressors from overheating. The
inspectors reviewed Procedures 50P-509A, Revision 7, " Instrument Air System";
and ABN-301A, Revision 4, " Instrument Air System Malfunction," and found that
the procedures appropriately addressed these interim actions.
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The inspectors reviewed NRC Generic Letter 88-14, SOER 88-01, and the
licensee's instrument air evaluation team report (CPSES-9131417). The
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licensee has appropriately addressed the required and/or recommended actions
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in each of the documents.
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Instrument air quality samples were reviewed for the past 2 years.and'were
found to meet the requirements of American National Standard ISA-57.3,
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" Quality Standard for Instrument Air."
No recent examples of' water intrusion
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into the instrument air system have been documented or have been identified as
contributing to component failures.
Particles in excess of the 3 micron limit
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have been identified during the routine air sampling; however, the contractor
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performing the examinations has indicated to the licensee that the small
population of particles in excess of 3 micron were normal background
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associated with the sample filter medium. The licensee performed several
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technical evaluations that documented no equipment operability concerns
existed'in relation to the instrument air particulate size (TE-91-2030,
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TE-92-1369, and TE-92-1578).
The licensee currently has no method to determine instrument air system usage
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and therefore can only estimate when air system usage becomes excessive. This
does not allow the maintenance and engineering organizations to provide
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proactive troubleshooting and repairs to minimize instrument air' system losses
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due to leakage.
System engineering requested to add an in-line flow indicator
in January 1991 (Design Request DMRC 89-1-016). The ISEG Report 93-07
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concludes that the instrument air system may be undersized and recommends a DM
to add two new 100 percent compressors based on qualitative analysis. The
report also recommended that updated instrument air usage calculations be
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performed.
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Although the system engineering organization had not provided an integrated .
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system performance evaluation to provide the technical basis to assimilate the
numerous and varied instrument air component failures, the inspectors have
determined that an adequate understanding of instrument air system failures
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has been discussed and evaluated within the engineering and management
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organizations. The instrument air system has been able to function as
designed with the various configurations of IACs.
DM 93-022 should decrease
the extreme seasonal ambient operating temperatures associated with the rotary
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air compressors and the DM will possibly decrease the failure rates on the
instrument air system.
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3.1.2
DG Starting Air System
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The inspectors noted numerous DG starting air system equipment performance
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problems over the past year. This was evidenced by intermittent control board
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annunciators, dryer and compressor failures, and other starting air component
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problems. Additionally, on February 26, 1993, an automatic start of DG l-01
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was masked as a result of a nuisance main control board annunciator associated
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with the respective starting air system (Refer to Section 3.4.1 of NRC
Inspection Report 50-445/93-12; 50-446/93-12 for details).
The inspectors
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reviewed NRC Generic Letter 88-14, a licensee task team' report, maintenance
and surveillance activities, quality assurance audit activities, and Part 21
followups related. to the DG starting air system.
Internal licensee
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documentation of equipment / system problems were also reviewed to ensure
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management was aware of the system status.
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Review of various maintenance activities encompassed the areas of predictive.
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and corrective maintenance.
The licensee has been performing vibration .
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analysis on the starting air compressors to monitor for equipment degradation.
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Discussions with an engineer in technical support indicated that the data
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collection has been difficult since the air compressors cycle on and off at
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various intervals. No abnormal vibration trends have been identified. The
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corrective maintenance work order history was reviewed and found to contain
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routine repetitive work items.
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Failures of various components in the starting air system have been linked to
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the air dryer skids.
Technical Evaluations92-885, 91-3364, 90-2048, 90-3177,
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and others have attributed the bulk of starting air system problems to the
problems with the air drying components.
Quarterly failure history trending
and equipment performance monitoring have identified the DG starting air
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system as having significantly higher failure rates than industry average.
These failures were associated with dryer malfunctions and relief valve
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location.
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The licensee has provided excellent bracketing of the various component
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failures. Currently, the licensee has DM 92-034 in the development stages.
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This DM will replace the vendor supplied air dryer skids (Kahn) with an air
dryer model similar to that being used by Grand Gulf ca it's Division 3 DG.
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ISEG also evaluated the DG air compressor and dryer operability and
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availability (ISEG-FN-92-109 and 93-159).
ISEG concluded that the DM will
correct the problems, and that the current system is sufficiently reliable to
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allow continued' plant operations. Minor modifications have.been requested to
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improve system reliability until the DM is installed.
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The system engineer was found to be extremely knowledgeable of the air
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starting system historic problems and was aware of daily maintenance,
surveillance, and component problems. He indicated that discussions with the
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Enterprise DG Owner's Group identified that other utilities were also having
similar problems with the Kahn air dryers.
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The inspectors found that the licensee had appropriately addressed NRC Generic Letter 88-14, Instrument Air Evaluation Team Report, and industry operating
experience reports.
Air humidity readings and daily air system blowdowns have
been added to monitor and minimize water intrusion into the starting air
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system.
Overall, the licensee has performed sound technical evaluations to establish
the basis for common root cause failures of various components within the DG
starting air system. Upper management has been informed of these problems
through quarterly trending and plant performance reports. The licensee has
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incorporated industry experience into the review and planned resolution of
system problems.
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3.2
Emergency Core Cooling System Lineups
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The inspectors verified that valves within the Unit I emergency core cooling
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system major flow paths were properly aligned.
The inspectors walked down
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accessible portions of those systems and verified that the valve lineups were
in accordance with the operating procedures.
Required auxiliary systems were
found to be operable.
The main control board indications were found to be
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consistent with the field conditions.
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3.3
Radiation Protection
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The inspectors observed personnel entering the radiologically controlled area
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at the Unit 2 access point.
It was noted that the briefings on radiological
conditions conducted by radiation protection technicians were appropriate.
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Additional radiation protection technicians were posted in the Unit 2
safeguards building to assist in coverage of numerous work activities. A
radiological hotspot was posted in an emergency core cooling system valve
room.
It was determined that the area was properly posted. Discussion with
radiation protection personnel identified that it was not feasible to flush
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the line to remove the source.
It was determined that excellent operational
support was provided to flush hotspots. At the end of the inspection period,
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there were only three additional hotspots located in areas where personnel
periodically enter.
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3.4 Security Observations
On April 29, 1993, the inspectors observed security activities from the
central alarm station.
All perimeter detection aids were functioni..g
properly; however, some pan-tilt-zoom cameras used by the security officers
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only for observation assistance were inoperable
Two of the cameras have been
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out-of-service since January 1993. The officers stated.that the pan-tilt-zoom
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cameras were a dated model and replacement parts were hard to obtain.
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Discussions with the officers indicated that instrumentation and control (I&C)
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technicians repaired required surveillance equipment in an expeditious manner.
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The inspectors noted that perimeter camera clarity was excellent, and, at the
time, there was no reliance on compensatory posts.
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The interior of the' protected area fences was walked down by the inspectors
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and found to be in good condition.
3.5 Conclusions
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The licensee's engineering assessments for the instrument air and diesel
generator starting air systems were mixed. The instrument air system concerns
presented to the SORC, as the basis for the SORC authorizing a design
modification, were not well supported by the engineering evaluations.
However, the engineering conclusions for the diesel generator starting air
system were well supported and appropriately considered the systems
maintenance history and the short and long term effects on system reliability.
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The security and radiation protection programs were well implemented.
Radiological hot spots in the plant were well controlled.
Major flow path valves within the emergency core cooling system were
po:itioned in accordance with Mode 1 Technical Specification operating
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requirements.
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4 ENGINEERED SAFETY FEATURES WALKDOWN (71710)
4.1
Unit 1 Auxiliary Feedwater System
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The inspectors completed a review of the auxiliary feedwater system from the
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previous inspection period (NRC Inspection Report 50-445/93-18; 50-446/93-18,
Section 3).
The previous findings concluded that the system was properly
aligned to meet its intended safety function.
This subsequent review assessed
the surveillance program established in the Final Safety Analysis Report'
Section 10.4.9, AUXILIARY FEE 0 WATER SYSTEM; the Master Surveillance Test List;
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and Technical Specification Requirements Sections 4.7.1.2 and 4.7.1.3.
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review of the open auxiliary feedwater system work activities was also
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performed.
It was found that the Master Surveillance Test List identified each of the
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auxiliary feedwater cystem Technical Specification surveillance requirements.
The referenced surveillance procedures met the surveillance test requirements
in the Technical Specification.
These surveillances were last performed
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within the req # ed test frequency. The review of the open Unit 1 auxiliary
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feedwater system work activities did not identify any deficiencies which would
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have an appreciable adverse impact on the system's ability to meet its design
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basis requirements.
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4.2 Conclusion
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The auxiliary feedwater system surveillance requirements were implemented in
accordance with the Technical Specification requirements and were consistent
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with the established Final Safety Analysis Report design basis requirements.
The open work activities were appropriately assessed and should not have an
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appreciable impact on system performance.
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5 MAINTENANCE OBSERVATION (62703)
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5.1
Steam Generator (SG) FCV Circuit Card Replacement
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A Westinghouse Infogram, titled "7300 Process System NCD Card Power Supply
Circuit," detailed a failure problem with controller driver circuit cards used
in the SG FCV circuitry . The cards were found to be operating'in an
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increased thermal load environment which could significantly decrease the
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meantime between circuit card failures. Westinghouse recommended that the
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cards be replaced with a revised version of the driver circuit' card which
consisted of new transistors, capacitors, zero-ohm jumpers, and a heat sink
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assembly to eliminate the heat induced failure mechanism.
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The inspectors observed I&C technicians change out the controller driver
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circuit card on SG 2 (Work Order 1-93-042856-00) and observed control-room
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operators' response during the change out of SG 1 FCV circuit card.
During the controller driver card replacement, automatic and manual control of
the FCV from the main control board were expected to be lost. The licensee
had the following contingencies in place to control SG water level:
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Maintain power steady and a constant throttled feedwater flow through
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the FCV, while positioning the FCV bypass as necessary to keep SG level
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constant.
The FCV bypass valve was initially positioned approximately
half open to allow for adjustments in flow.
An extra licensed reactor operator was positioned at _the equipment racks
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such that he could position the FCV using the service module card if
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directed by the main control board reactor operator. This contingency
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would only be used in the event that the FCV bypass was unable to
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compensate for SG level deviations.
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After the FCV was throttled, the reactor operator had an auxiliary
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operator gag the FCV to prevent the valve from inadvertently closing.
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The licensee conducted a detailed prejob brief since this maintenance was
classified as a "high risk activity." The unit supervisor provided an
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outstanding brief that discussed the details concerning the possibility of the
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FCV inadvertently shutting, and what response each individual would be
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required to perform in order to maintain SG water level.
The I&C manager was
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present during the prejob brief and portions of the work.
He reminded the
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technicians not to hurry.
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The card replacement for SG 2 FCV was accomplished without any problems. The
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I&C technicians worked in a deliberate and controlled fashion.
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communications _ and self-verification were used during the ' card replacement.
The inspectors observed control room operators' communications and control of
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equipment during the replacement of the controller card for SG 1 FCV. The
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evolution proceeded smoothly, until the 1&C technicians replaced SG 1 FCV
circuit card. As the system was being restored to a normal lineup, the new
card experienced a sudden failure causing the FCV to close.
The unit
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supervisor immediately directed the I&C technicians to reinstall the service
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module card and had the extra reactor operator take control of the FCV from
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the electrical rack and open the valve. After SG level was restored and
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stable, the old controller driver card was reinstalled and.the control system
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was returned to service. The system responded normally
All personnel .
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involved in the loss of control of the FCV responded in a~ calm and deliberate
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manner, thereby allowing a rapid recovery from the card failure. The unit
supervisor provided excellent command function during all phases of the
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circuit card replacement and failure.
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The licensee has sent the failed circuit card to Westinghouse fee failure
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analysis. The remaining three controller driver cards in the FCVs will be
replaced when operations department determines the appropriate schtduling
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criteria.
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5.2 Control Room Air Conditioning
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Electrical maintenance (EM) technicians were observed performing the PM annual
inspection for Control Room Air-Conditioning Unit X-03 (Work
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Order 3-92-307295-01) in accordance with Procedure MSE-PX-7330, Revision 0,
" Control Room HVAC Annual Inspection." The technicians were observed
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referencing the procedure and using good work practices.
Clearance X-93-01093 which isolated the air-conditioning unit was reviewed and
found to provide for proper component and personnel protection. The
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inspectors did note that the clearance had a special instruction to remove the
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refrigerant prior to hanging the clearance; however, contrary to the special
instruction, the refrigerant had not been removed.
Discussions with the EM
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technicians and a review of the applicable portions of the maintenance
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procedure identified no safety concerns with the refrigerant remaining in the
compressor. ONE Form 93-1133 was initiated by operations to address this
inspector identified deficiency.
The inspectors observed that the EM technicians failed to utilize proper
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self-verification techniques during the isolation of a freon filter. The
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maintenance procedure had vendor valve numbers referenced in the work
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instructions, while the air conditioning unit had unique valve numbers for
each component.
The technicians did not cross-reference valves numbers with
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Attachment 10.1 of Procedure MSE-PX-7330 which had vendor identification and
plant labeling comparison data.
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The inspectors reviewed the work order and found that the PM had last been
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performed in January 1991. Vendor Manual CP-0087-001 specified an annual
inspection for the air-conditioning compressor as well as other PMs for
various components. This PM was originally scheduled to be completed in June
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1992 under Work Order P900003292 with a scheduled due date of July 12, 1992.
This activity was not worked and had been rescheduled three other times.
Discussions with the EM manager indicated the scheduling delays existed
because the operations department has been reluctant to remove the equipment
from service to perform the PM.
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Station Administration Manual Procedure STA-677, Revision 2, " Preventive
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Maintenance Program," Section 6.4.6 requires plant engineering evaluation of
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PM work orders that become delinquent. The evaluation shall be documented as
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a technical evaluation containing the effect on equipment operability and
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scheduling of the activity.
No technical evaluation had been initiated.
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inspectors identified the failure to initiate a technical evaluation to
determine the potential adverse effects on safety-related equipment
operability in accordance with Procedure STA-677 as a violation of Technical
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Specification'6.8.1 and Procedure STA-677 (445/9322-01; 446/9322-01).
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CNE form 93-1155 was initiated to document the delinquent PM and the failure-
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to perform a technical evaluation prior to the delinquent date.
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It was subsequently determined that the data-based Plant Reliability-
Integrated System for Management (PR-ISM) computer coding for certain PM
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activities (outage and conditional) will not show that a PM is delinquent.
No
due date is provided for the outage or conditional frequency PMs in the
corresponding PR-ISM data-base field, and therefore no delinquent date
calculation can be performed.
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Technical Evaluation 93-751, dated April 25, 1993, described the condition
where a PM on a generator auxiliary component was going to be delinquent.
Plant engineering's evaluation stated that the PM could not be delinquent
since it was an outage frequency PM and had no calculated due date.
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technical evaluation was found to be inadequate in that it did not address the
effect deferring the PM activity may have on equipment operability.
Additionally, at the end of the inspection period, ISEG was conducting a
review of delinquent PM technical evaluations (ISEG-FN-93-322) and found that
the majority of the evaluations did not address the effect on equipment
operability.
5.3 Various Maintenance Activities
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The inspectors observed the following maintenance activities:
Mechanical maintenance technicians were observed sampling, draining, and
filling Valve Actuator 2-HV-2134-H0 hydraulic oil reservoir using Work
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Order 1-93-045716-00.
Proper cleanliness and housekeeping practices
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were used while the system was open.
1&C technicians increased the nitrogen alarm setpoint on Pressure
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Switch 2PS-2137B (SG 2-04 Feedwater Isolation Valve).
The work was
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performed in accordance with Work Order 2-93-044548-00.
The alarm
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setpoint was increased from 2240 psig to 2250 psig to be consistent with
that of Unit 1.
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Portions of the initial troubleshooting on SG Atmospheric Relief
Valve 1-03 (IPV-2327) to identify / repair valve seat leakage (Work
Order 1-93-033570-00). The mechanical maintenance technicians were
assisted in the troubleshooting activity by the system engineer.
Good work practices were utilized by all technicians. Management's
expectations were met for each of these work activities.
5.4 Conclusions
The development of the FCV controller card work order and instructions, prejob
briefing, activity coordination between operations and I&C, and the unit
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supervisor's command and control were outstanding.
Management oversight of
this high risk activity was notable.
Routine maintenance work activities on
the control room air conditioning unit were not conducted in accordance with
management's established expectations for self-verification.
The work
activity impact sheet requirements were not adhered to for the control of
freon in the system. A violation was identified for the failure to develop a
technical evaluation for deferring a safety-related component PM activity.
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technical evaluation for a nonsafety-related component deferred PM was
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inadequate because it failed to assess the impact on the equipment
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operability. The technical evaluation documented the-PM pt ogram weakness with
regard to outage and conditional frequencies but failed to address the generic
implications.
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6 SURVEILLANCE OBSERVATIONS (61726)
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The inspectors observad the surveillance testing of safety-related systems and
components listed below to verify that the activities were being performed in
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accordance with the Technical Specifications. The applicable procedures were
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reviewed for adequacy, test instrumentation was verified to be in calibration,
and test data were reviewed for accuracy and completeness.
The inspectors
ascertained that any deficiencies identified were properly reviewed and
resolved.
The inspectors witnessed portions of the following surveillance test
activities:
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6.1
Reactor Coolant Flow Instrumentation Calibration
The inspectors observed 1&C technicians perform Procedure INC-7761A,
Revision 4, " Analog Channel Operational Test and Channel Calibration Reactor
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Coolant flow Loop 1, Protection Set II, Channel 0415." The technicians
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performed only the analog check in accordance with Work Order 5-93-500838-AB.
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All as-found data was within specification and no instrument adjustments were
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necessary.
Previous Work Order 5-93-5000838-AA completed February 1993 was
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reviewed and the recorded data was consistent with the most recent
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surveillance.
Self-verification and communication with the licensed operators
were excellent.
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6.2 Unit 2 Class lE Electrical Under Voltage Relay Test
The inspectors observed an auxiliary operator and EM technician, with
supervision provided by the field support supervisor, conduct surveillance
test Procedure OPT-221B, Revision 0, " Cold Shutdown Class IE Electrical UV
Relay Test," Sections 8.1.1 and 8.1.4.
This test was performed under Work
Order 5-93-503253-AA.
The surveillance test was performed to verify the
operability of the 6.9kV and 480V relays (Technical Specification 4.3.2.1.8).
The field support supervisor was coordinating, directing, and supervising the
relay surveillance test.
The field support supervisor provided excellent
oversight.
Excellent self-checking, communications, and use of procedures
were utilized by the auxiliary operator. The inspectors did note that the
auxiliary operator and EM technician were wearing their metallic wrist watches
while working in an energized cabinet. They removed their watches after inis
poor work practice was brought to their attention.
6.3
DG 2-01 Air Receiver Check Valve Inservice Test
The inspectors observed the performance of surveillance Work
Order 5-93-503533-AA for the DG 2-01 Air Dryer ?.-02 isolation check
Valves 2-00-0075 and 2-D0-0059.
These check valves (positioned in series)
provided separation of the safety-related air receiver from the nonsafety-
related air dryer skid and compressor.
This surveillance activity did not
render the DG air start system inoperable.
The work activity involved depressurizing the line upstream of the check
valves and opening a flange connection at the first upstream check valve to
verify that no leak by occurred.
The surveillance activity was conducted in
accordance with the work instructions and Procedure OPT-517B, Revision 0,
" Diesel Generator Starting Air Receiver Check Valve Operability Test." During
the performance of the test, a step was performed out-of-sequence and part of
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the work activity had to again be performed.
It was noted that the prejob
briefing had not specifically stepped through the procedure and the work
instructions.
The need to reperform aspects of the test did not affect the
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test results. The valves were determined to be operable and the air dryer
tower and compressor were returned to service.
6.4
Unit 1 Steam Generator Narrow Range Level
The inspectors observed the performance of surveillance Work
Order 5-93-500636-AA, Revision 4, "ACOT & Channel Calibration Steam Generator
NR Level, Loop 2, Prot Set II, Ch 0552," for the Steam Generator 1-02 Narrow
Range Level Instrument 1-L-0552.
The surveillance was conducted in accordance with the procedure utilizing
excellent self-verification techniques. The as-found voltages were very close
the desired values.
A review of the previous surveillance test
(2-92-500731-AA) performed in February 1992 identified that the as-found
values were nearly identical to the later test.
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Conclusions
The licensee implemented the surveillance test program in accordance with the
Technical Specification surveillance requirements.
I&C personnel utilized
excellent self-verification techniques.
7 FOLLOWUP ON CORRECTIVE ACTIONS FOR VIOLATION AND DEVIf.TIONS (92702)
(Closed) Violation 445/9141-01:
Failure to Properly Implement Procedures
This violation identified three examples of failure to properly implement
procedures.
The examples involved failures to open a local instrument root
valve following a surveillance test, update an annunciator response procedure,
and ensure the adequacy of a safety clearance boundary.
The licensee promptly repositioned the valve and updated the annunciator
response procedure.
Personnel responsible for reviewing and implementing
safety clearances were instructed on their responsibilities for the clearance
process.
A generic concern was identified involving procedural compliance and
attention to detail.
Subsequent to these violations the licensee implemented
a performance enhancement program to monitor personnel performance, and
evaluate and take corrective actions for personnel error.
The inspectors have
noted an improvement in personnel performance since the implementation of the
personnel enhancement program. The overall effectiveness of the licensee's
efforts to identify and correct personnel performance problems has been
assessed.
The inspectors concluded that the licensee has addressed the
personnel performance concerns as documented in NRC Inspection
Report 50-445/93-12; 50-446/93-12. These corrective actions were found to be
appropriate.
8 FOLLOWUP (92701)
(Closed) Inspection Followup Item 445/9141-02: 446/9141-02:
Water in the
Instrument Air System
This inspection followup item was initiated to review the licensee's task team
recommendations for an instrument air system water intrusion event.
This also
included the licensee's implementation of commitments made in response to
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The inspectors reviewed the task team's report and the licensee's actions
taken in response to the generic letter.
The details of this review are
documented in Section 3.1.1.
It was found that the licensee's actions were
appropriate, and that it had implemented Generic Letter 88-14 commitments.
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ATTACHMENT 1
1 PERSONS CONTACTED
1.1 TV ELECTRIC
0. Bhatty, Site Licensing
W. J. Cahill, Group Vice President, Nuclear Engineering and Operations
R. R. Carter, Assistant to Manager, Maintenance
D. L. Davis, Manager, Plant Analysis
J. W. Donahue, Manager, Operations
S. L. Ellis, Work Control Manager
R. Flores, Shift Operations Manager
J. R. Gallman, Trend Analysis Manager
T. A. Hope, Site Licensing Manager
B. T. Lancaster, Manager, Plant Support
D. M. McAfee, Manager, Quality Assurance
D. R. Moore, Manager, Maintenance
J. W. Muffett, Manager of Technical Support & Design Engineering
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1.2 NRC Personnel
D. N. Graves, Senior Resident Inspector
R. M. Latta, Resident Inspector
The personnel listed above attended the exit meeting.
In addition to the
personnel listed above, the inspectors contacted other personnel during this
inspection period.
2 EXIT MEETING
An exit meeting was conducted on May 28, 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
inspectors,
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