IR 05000445/1993012
| ML20035E943 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 04/12/1993 |
| From: | Yandell L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20035E931 | List: |
| References | |
| 50-445-93-12, 50-446-93-12, NUDOCS 9304200095 | |
| Download: ML20035E943 (18) | |
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APPENDIX B U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Inspection Report:
50-445/93-12 50-446/93-12
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Operating Licenses:
NPF-87 NPF-89 Licensee: TU Electric Skyway Tower 400 North Olive Street Lock Box 81 Dallas, Texas 75201 Facility Name: Comanche Peak Steam Electric Station, Units 1 and 2 Inspection At:
Glen Rose, Texas Inspection Conducted:
February 18 through March 3, 1993 Inspectors:
W. B. Jones, Senior Resident Inspector G. E. Werner, Resident Inspector T. Reis, Project Engineer Aoproved:
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L. A. Yandell, Chief, Project Section B Date Division of Reactor Projects Inspection Summary Areas Inspected (Units 1 and 2):
Special, announced inspection of licensee efforts to enhance personnel performance and reduce personnel errors, sustained control room and in-plant observations, and an evaluation of corrective actions taken to previously identified violations.
Results (Units 1 and 2):
The failure to complete the reconciliation of Unit 1 field work request e
tags with the outstanding work computer database resulted in a deviation (Section 4.1).
- The licensee has obtained quantifiable results in reducing personnel errors and enhancing personnel performance (Section 2.2).
The licensee has made significant progress in its program for improving e
personnel performance and reducing personnel errors. The establishment of the Performance Enhancement Review Committee has provided an effective process for licensee management and supervisory personnel to 9304200095 930414 PDR ADOCK 05000445 G
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significant personnel errors; however, documentation does not support that the program was consistently implemented in accordance with its l
charter (Section 2.2).
e The licensee has numerous administrative means of identifying, l
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analyzing, and correcting personnel performance issues; however, a l
cohesive document which coordinates all the various programs has not l
been established (Section 2.2).
The licensee's ability to track, trend, analyze, and categorize e
personnel performance issues was evaluated to be outstanding (Section 2.2).
The licensee has incorporated, in draft, the methods available for e
identifying personnel performance problems and for clearly communicating management's expectations in a concise manner (Section 2.2).
Operations shift turnovers were conducted in a professional manner and
provided a very good status of plant equipment and planned ongoing activities (Section 3.2.1).
Main control board annunciators were generally well understood and e
administrative controls for assessing annuncistor status were well implemented (Section 3.2.2).
A repetitive annunciator resulted in the operator not immediately identifying that the diesel generator had started (Section 3.4.2).
The definition and implementation of requirements for problem e
annunciators appeared to be unclear (Section 3.2.2).
Communication between licensed operators, auxiliary operators (A0s) and
craft personnel was very good. An observation was made that not all causes for control room annunciator alarms investigated by an A0 were repeated back to the reactor operator (Section 3.2.3).
e The A0s demonstrated that they were knowledgeable of the activities required by their assigned watch station. Appropriate self-verification techniques were utilized when operating equipment (Section 3.2.4).
The licensee's procedure for securing compressed air cylinders used in
safety-related areas lacks specificity, and an example was encountered where a cylinder was not properly secured (Section 3.2.4).
The field support supervisors were effective in coordinating A0 e
activities.
They provided an essential oversight function and helped to assure that licensee management expectations were met. However, during
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-3-periods of high activity, the field support supervisor was used to augment the A0 staff and was not always available to supervise A0 field i
activities (Section 3.2.5).
e Surveillance activities were conducted in accordance with procedure requirements.
Good communications were noted between the personnel performing the activity (Section 3.3).
One instance was noted where management's expectations with respect to e
performance of procedural instructions was not met. Operators only partially opened a valve procedurally called for to be open.
Prompt investigation was taken by engineering and corrective actions were developed (Section 3.4.1).
Maintenance activities were generally performed in accordance with work e
instruction and procedure requirements. The solid state safeguards sequencer troubleshooting activity was very well coordinated.
The engineering involvement and management oversight was notable (Section 3.4.2).
Personnel generally demonstrated a very good understanding of the self-e verification process; however, this was not consistently true for personnel who may not be expected to routinely use this process (Section 3.5).
Summary of Inspection Findings:
Deviation 445/9312-01 was opened (Section 4.2)
Inspection Followup Item 445/9312-02 was opened (Section 3.4.2).
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e Violation 445/9220-01 (EA 92-107) was closed (Section 4.1).
e Violation 445/9214-01 was closed (Section 4.2).
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Violation 445/9214-02 was closed (Section 4.3).
Attachment:
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e Attachment - Persons Contacted and Exit Meeting
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DETAILS
INTRODUCTION The purpose of this inspection was to review the licensee's actions to reduce
personnel errors and to evaluate the overall effectiveness of these actions.
To accomplish this purpose, the inspection consisted of a review of the licensee's Performance Enhancement Program; corrective actions taken in
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response to escalated Enforcement Action EA 92-107, and Violations 445/9214-01
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and -9214-02, in which personnel errors contributed to significant regulatory concerns; and extensive control room and in-plant observation of personnel performance.
2 FOLLOWUP (92701)
2.1 Background in the fall of 1991 the licensee identified a concern with the number of personnel errors which had occurred. The licensee initiated a task team to identify ihe root causes for the repetitive personnel errors and to recommend correct'4e actions.
The results of this task team were documented in internal corret..Jence from the personnel error task team manager to the plant manager dated December 19, 1991. The inspectors noted that the task team effectively utilized root cause and management oversight risk tree analysis techniques to identify the areas which needed improvement. These areas included supervisory relationships, communications, coordination and priority, distractions, time restraints, and the overall human performance enhancement system program.
2.2 Analysis The inspectors found the results of the task team's findings to be objective and appropriate given the personnel errors that had been analyzed since January 1991.
The inspectors found the recommendations provioed to senior management to be specifically directed toward improving performance and attainable, based on the establishment of realistic goals.
The licensee was in the process of incorporating the task team's recommendations to reduce personnel errors when a personnel error resulted in a Technical Specification violation because of a residual heat removal valve being mispositioned.
This event occurred in December 1991 and is documented in NRC Inspection Report 50-445/91-62; 50-446/91-62. A personnel error in January 1992 resulted in turbine trip / reactor trip when the turbine generator cooling water system was incorrectly operated.
This is documented in NRC
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Inspection Report 50-445/91-70: 50-446/91-70.
A third event occurred in May 1992 when several personnel errors resulted in the spent fuel pool being without cooling for approximately 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br />.
This is documented in NRC Inspection Report 50-445/91-62: 50-446/91-62.
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The task team's recommendations were augmented and their implementation accelerated following each of these events.
It was not until after the spent fuel pool cooling event, however, that senior management established a program
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to formally and programmatically involve themselves in the corrective action process associated with significant personnel errors.
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This was accomplished through the establishment of a Performance Enhancement
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Review Committee (PERC).
The purpose of this committee is to provide a forum
for openly discussing significant personnel performance errors with senior licensee management, the individual (s) involved, the individual's peer (s), the i
individual's supervisor or manager, and other cognizant personnel.
The inspectors reviewed the committee's charter with senior licensee management.
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11 was ascertained that their expectations are that the committee will convene j
within 5 working days of the event. A written report is to be developed summarizing the meeting and to provide additional insights to help resolve the associated operations notification and evaluation (ONE) form.
The licensee identified that, although this process supplements the ONE form review, human performance evaluation system assessment, and root cause analysis processes, it was their intent to not proceduralize the process.
Plant personnel were notified on June 23, 1992, that the PERC process was being implemented.
The inspectors found that the PERC had reviewed 19 significant personnel
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errors.
It was later determined that the licensee was only able to produce
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From subsequent discussions with senior licensee management, it was concluded' that, although the meeting summaries could not be retrieved, Committee meetings were held and
the seven missing meeting findings had been considered during the associated
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ONE form evaluations. The licensee did note that they would begin including
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the meeting summaries with the associated ONE form. The inspectors reviewed l
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8 of the 12 documented PERC meeting summaries and found all of the them to have been beneficial to the corrective action process.
It was noted that there was a wide variation in the format and content of the PERC meeting
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documentation.
The inspectors attributed the variation to the lack of any i
formal guidance for content of.the meeting summaries.
j The inspectors found the licensee's tracking, trending, analyzing, and
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categorizing of personnel errors to be outstanding. The nuclear overview i
department trend analysis manager provided management reports on personnel errors to the responsible organizations.
The inspectors reviewed the trend analysis manager's report on Unit 1 performance enhancement data for the year i
ending 1992.
Each department had est;blished a goal to reduce personnel errors by 10 percent and a goal to reduce significant personnel errors by 50 percent. The licensee identified 393 reported personnel errors in 1992, which represented a 38 percent reduction in the overall personnel error rate.
For significant personnel errors, the licensee achieved a reduction of 45 percent.
A total of 30 significant personnel errors occurred in 1992.
The inspectors performed a detailed review of 10 of the 393 nonsignificant personnel errors identified in 1992. The licensee's classification of each of the events as nonsignificant was consistent with their established guidance.
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l The inspectors found the definition of a significant personnel error, as provided in the letter dated March 5, 1992, from the Manager, Work Control, to
be appropriate.
The inspectors noted that the documented definition of a significant personnel error could not be readily retrieved; however, the ONE form committee manager was able to verbally define a significant personnel error in terms equivalent to what was later produced in the referenced letter.
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The licensee identified to the inspectors that they were considering adding the significant personnel error definition to the ONE form procedure, as well
as identifying the use of the PERC process,
The Manager, Plant Analysis provided the inspectors with a draft " white paper" which proceduralized the performance enhancement program for Comanche Peak Steam Electric Station. The " white paper" was found to have been primarily generated to address Significant Operating Event Report 92-1, " Reducing the Occurrence of Plant Events through improved Human Performance." At the conclusion of the inspection, licensee management was reviewing whether the draft " white paper" should be made into a station procedure.
The draft " white paper" comprehensively communicated management's expectations relative to personnel performance, supervision, communications, accountability, and the id rtification and resolution of deficiencies in a concise manner.
2.3 Conclusion The licensee has made significant progress in its program for improving personnel performance and reducing personnel errors.
The establishment of the PERC has provided an effective process for licensee management and supervisory
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personnel to directly assess conditions and personnel actions which resulted i
in significant personnel errors.
The licensee incorporated, in draft, the methods available for identifying personnel performance problems and for clearly communicating management's expectations in a concise manner.
If appropriately implemented, the document should prove to be an effective tool for management, operators, and the craft personnel to use in further enhancing personnel performance.
l 3 SUSTAINED CONTROL ROOM AND IN-PLANT OBSERVATIONS (71715)
i 3.1 Discussion of Areas Reviewed The inspectors observed operator and craft personnel performance in the control room and plant to assess the effectiveness of licensee management's actions taken to enhance personnel performance and minimize personnel errors.
The focus of the inspection was on operator and craf t personnel knowledge of assigned tasks; awareness and use of self-verification techniques; effectiveness of communications between operator and craft personnel and supervision, as well as across organizational boundaries; and awareness of actions to take upon the recognition of nonconforming conditions.
An assessment was made of the effectiveness of the field supervisor position.
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l 3.2 Control Room Observations 3.2.1 Shift Turnover The inspectors observed five shift turnovers.
It was noted that the status of l
plant equipment and planned activities was appropriately reviewed by the off-
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i going and relief shift and unit supervisors.
An auxiliary building watch turnover was observed. This turnover was well performed and included a i
i comprehensive review of activities in progress.
3.2.2 Annunciator Status The licensee has established two principal administrative controls for assessing the status of main control room annunciators. These controls are
identified in Procedures ODA-301, Revision 10, " Operating Logs"; ODA-302, Revision 10, " Relief of Personnel"; and, ODA-401, Revision 5, " Control Of Annunciators, Instruments and Protective Relays."
Procedures ODA-301, l
Section 6.5.1, and ODA-302, Section 6.2.4, establish a licensee management expectation for maintaining an informal shift turnover alarm status log.
Procedure ODA-401 establishes, in part, the method by which operations personnel are to respond to, control, track, and correct problems with all annunciators (main control board and local); track removal from and return to service of plant instruments for corrective maintenance, and provide
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l compensatory monitoring actions for the above.
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On February 26, 1993, the inspectors observed the status of Unit 1
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annunciators. A total of 16 control board annunciators were illuminated.
Fourteen of these had been identified as problem annunciators in accordance l
with Procedure ODA-401. This procedure defines a problem annunciator as, "Any Control Room, local panel annunciator or Plant Computer alarm which cannot be i
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reset due to equipment failure, required maintenance, or engineering actions i
for the annunciator or is otherwise inoperable." As an aid to the operator, problem annunciators are accented with an opaque colored adhesive dot l
(approximately 1/2 inch diameter) to identify a problem or nuisance
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annunciator which cannot be deactivated.
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l The inspectors reviewed the status of two illuminated alarm windows. The
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first annunciator, Annunciator Window (1.1), " Service Air Comp Trip," on Panel 1ALB-1, was marked with an opaque sticker per the Procedure ODA-401
process. A second illuminated annunciator, Annunciator Window (1.19) on
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Panel 1ALB-10B, " Vent Chiller Overcurrent Breaker Open," was not identified in the Procedure ODA-401 log of problem annunciators.
The inspectors reviewed the reason for the one annunciator being identified per the Procedure ODA-401
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process and the ofher not being included.
It was determined that the service air compressor had tripped and an active corrective maintenance work order
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existed to correct the adverse condition.
Although the annunciator was operable and was not required to be tracked as a problem annunciator, the
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licensee determined that a heightened sensitivity to existing plant conditions
was warranted. This included a review for possible compensatory actions as provided for in Procedure ODA-401-1.
The second illuminated annunciator was
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In this case the condition was understood and planned.
The existing plant condition was reviewed as part of i
the work activity " impact review."
Although this particular discrepancy in apparently similar conditions was justified by operations management, two unit supervisors interviewed could not
differentiate why one annunciator was identified by the Procedure ODA-401 process and the other was not. The inspectors left the licensee with the
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observation that the definition provided for a problem annunciator in l
Procedure ODA-401 is not clear.
In particular, it is not clear whether i
" equipment failure" in the definition pertains to failure of the equipment l
which the annunciator services or merely the annunciator itself.
The inspectors reviewed the licensee's implementation of corrective actions to
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previous events where operators did not properly respond to illuminated annunciators.
This included the review of Procedures ODA-301 -302, where the
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licensee instituted a management expectation in which all active annunciators l
and the reason for the alarm would be logged within I hour of shift turnover.
i On two occasions the inspector determined that a review of the logged annunciators had not been completed by 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> into the shift.
Further, it I
was not clear that the oncoming shift was actually logging the illuminated
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annunciators within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
It appeared that a cursory review of the log
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turned over from the previous shift was what may have been performed.
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Operator adherence to management's expectations with respect to logging of annunciators was identified in NRC Inspection Report 50-445/93-07; 50-446/93-07 as an inspection followup item.
l 3.2.3 Control Room Communication and Logkeeping
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Communications between the licensed operators, auxiliary operators (A0s), and
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craft personnel were conducted in a professional manner. The reactor operators (R0s) maintained cognizance of system status throughout the entire j
shift.
It was noted that Unit 2 shift operators' conduct was consistent with
Unit 1 operations. The R0s and A0s utilized appropriate repeat-back
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statements when specific orders or activities were described. The inspectors noted on two occasions that, after a licensed operator directed an A0 to investigate the cause for a main control board annunciator, the cause for the j
alarm was not relayed back to the control room. The inspectors verified that these occurrences only involved conditions which did not involve system operation.
The inspectors reviewed the Unit 2 safeguards building A0 and the R0 logs
required by Procedures OWI-104, Revision 9, " Operations Department Logkeeping l
and Equipment Inspections"; OWI-104-43, Revision 3; and OWI-104-47, l
Revision 2, for February 26, 27, and 28, 1993.
The logs were reviewed for j
abnormal trends or readings which were consistent with plant conditions.
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I inspectors noted three out-of-specification readings; however, the equipment was nonsafety-related and equipment operability was not affected. Operations management was informed of these discrepancies and they were promptly
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t corrected. Overall, the inspectors noted that equipment parameters and l
conditions were properly logged and abnormal conditions were identified.
l 3.2.4 Routine Field Activities On February 27, 1993, the inspectors toured the safeguards building, Unit 1, with the assigned watch stander.
The A0 was qualified on all watch stations and had been qualified in the safeguards building for 2 years.
The rounds l
were performed in accordance with Operations Work Instruction (0WI)-104,
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Form 24, " Equipment tog Safeguards Building - Unit 1."
In addition to the specific log entries, the A0 examined the material condition of all safeguards
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areas.
The tour took slightly over 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> to complete.
The A0 was very adept at his rounds and had no problems locating any equipment designated on the logs.
- When called upon to test alarms, the A0 established good communications with the control room. During the rounds, no equipment was found operating outside its expected parameter. One indicating bulb was burned out on the breaker for Centrifugal Charging Pump 1-02 and the bulb was replaced. The A0 exhibited the expected level of knowledge of his duties and for operation of plant equipment. One observation was made concerning the use of a small bore pipe as a stepping pad when it could have been avoided.
The inspectors ooserved an A0 remove Clearance 2-93-00960 on the main
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feedwater system for Steam Generator'2-04. The A0 utilized good self-l verification techniques. While removing the clearance the A0 identified an
air leak on a feedwater regulating valve regulator.
This condition was reported to the field support supervisor and appropriate corrective actions
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initiated. The clearance was revised to leave the air supply valve closed and a work request was written.
l While touring inside the radiation controlled area, the inspectors noted a nitrogen bottle inside the Train A emergency diesel generator room which was loosely secured at a single point to a stanchion with an approximately 1 inch diameter nylon rope.
The inspectors were concerned that the bottle could be inadvertently knocked over.
The inspectors reviewed Procedure STA-728,
" Storage and Handling of Flammable / Combustible Material and Compressed Gases,"
which established the requirements for securing compressed air cylinders.
The procedural requirements were nonprescriptive and merely required that the cylinders be secured.
The inspector lef t the licensee with the observation that the procedure lacked specific guidance on how the cylinders are to be secured.
3.2.5 Field Support Supervisors The inspectors reviewed the field support supervisors' duties and supervisory responsibilities.
Based on discussions with several shift supervisors, it was determined that the field support supervisors have provided an essential supervisory oversight function of AD activities. This has included the coordination of A0 activities for integrated plant activities and has helped
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During the inspection
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j period, it was noted that a significant amount of the field support i
supervisors time involved Unit 2 activities.
This was commensurate with the i
proportionate amount of activities ongoing for each unit.
It was noted that i
during periods of high activities the field support supervisors were
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i performing the duties of the A0s, independent of an A0 being present. An t
observation was made regarding the time available for the field support
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l supervisors to periodically tour with each of the A0s.
It was found that several A0s had not been accompanied by a field support supervisor for a
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significant period (in excess of several months).
j 3.3 Surveillance Observation
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j 3.3.1 Motor-Driven Auxiliary Feedwater Check Valve Test l
The inspectors observed the performance of Procedure OPT-506B, Revision 1, "FW
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Section XI Valves," Section 8.3, to verify Motor-Driven Auxiliary
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Feedwater 2-02 check valve operability. All valves fully stroked and the surveillance was completed satisfactorily.
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j The inspectors noted that the R0 used good self-verification practices. One instance was noted where the incorrect valve designator was relayed from the
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R0 to the A0 in the field. The RO requested the A0 to close Valve 2AF-0299
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when the procedure stated Valve 2FW-0299. The A0 recognized the error and l
l clarified the discrepancy with the R0 before proceeding with any action. The R0 later verified that Valve 2FW-0299 had been shut.
3.3.2 Diesel-Driven Fire Pump Test i
Diesel Fire Pumps X-06 and X-07 were started and secured in accordance with
Procedure SOP-904, Revision 4, " Fire Protection Main Water Supply and Fire Pumps System." The inspectors noted that the field support supervisor was
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j present to observe the A0's performance during the evolution.
i 3.3.3 Diesel Generator Air Roll Check
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The inspectors observed the water roll check on Diesel Generator 1-01.
The activity was conducted in accordance with Procedure SOP-609A, Revision 8,
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" Diesel Generator System." Excellent use of the procedure and self-verification techniques was noted.
I 3.3.4 Residual Heat Removal Valve Stroke Test The inspectors observed the postmaintenance valve stroke test on residual heat i
removal Valve 2-8809B with the system in a static condition.
The test was conducted in accordance with Procedure OPT-512B, Revision 1, " Residual Heat
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Removal and SI Subsystem Valve Test," Section 8.4.
The valve satisfactorily
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passed each of the applicable surveillance requirements. The procedure was
utilized throughout the test.
Good use of the seven step self-verification
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3.4 Maintenance Observation
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r 3.4.1 Postmaintenance Test Observation j
On February 26, 1993, the inspectors observed two A0s and one A0 trainee perform Procedure OPT-205A, " Containment Spray System Operability. Test,"
Section 8.3, Train A Pump Operability Test.
The procedure was performed to i
verify operability of the containment spray pump after the pump feeder breaker i
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had been out of service for maintenance.
The inspectors noted that Step 8.3.7 of the procedure directed the A0 to open
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discharge test line isolation Valve ICT-0050. The inspectors observed that
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the valve had a placard on it indicating it took 189 turns to open the valve.
i The A0 was observed to have stopped opening the valve at 120 turns as indicated on the valve's position indicator.
The inspectors questioned the A0 as to why he had stopped opening the valve
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and he responded that he had received radio communications from the RO that the maximum flow called for in Step 8.3.9 had been obtained.
The inspectors were concerned that, had the valve been fully open as
instructed by the procedure, pump runout may have occurred. The concern was brought to the attention of the system engineer who was able to demonstrate that a pump runout condition would not occur through the test line.
The inspectors provided an observation to the licensee that, given the primary purpose of this test was to satisfy ASME XI operability criteria, the fact that the A0 did not fully open the valve could result in erroneous data for trending purposes. The system engineer agreed that this potential existed.
He communicated this observation to operations in the form of a " Lessons Learned." The lessons learned form provided operators with instructions to fully open the valves as directed and identified that a pump runout condition could not be obtained by fully opening the valve.
The inspectors discussed the scenario with shift and unit supervisors who were not on duty when the inspectors identified the concern.
Both indicated it was their expectation that the A0 should have fully opened the valve as directed by the procedure.
3.4.2 Unit 1 Train A Sequencer On February 26.1993, at 10:05 p.m.,
the Unit 1 Solid State Safeguards Sequencer (SSSS) Train A started on a 1 of 6 safety injection system signal.
This resulted in the Train A uninterruptible power supply, X-01 control room air conditioning and Train A & B electrical area fans starting.
The licensee determined that the initiation signal had originated from within the sequencer and was not the result of a valid safety injection signal. The actuated equipment was shut down ano troubleshooting Work Order 1-93-040174-00 was l
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N-12-initiated to correct the SSSS deficiency.
Concurrent with the initiation of t
the troubleshooting work order, the cognizant system engineer was contacted to assist in the troubleshooting activity.
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i The inspectors noted very good communication between the system engineer, instrumentation and control (I&C) technicians, and the operators. An I&C i
supervisor was present throughout the troubleshooting activities to coordinate
the work order, assist with developing troubleshooting instructions, and
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requisition parts. An observation was made that drawings designated for
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" engineering office use only" were used to develop the troubleshooting plan.
The drawings, however, were found to accurately reflect the Train A SSSS.
l The shift supervisor determined, based on a review of the system drawings and discussions with the system engineer, that the Train A SSSS was operable.
The
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SSSS failure code indicated that a valid safety injection signal would be properly processed.
During the troubleshooting activity, it was noted that a
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monitoring device had been connected to the Train A SSSS to try to capture a signal which was causing a Sequencer F26 alarm problem. The monitor installation was authorized by Work Order 1-92-000890-00 and a work-in-progress tag hung on the front of the sequencer cabinet.
The shift supervisor questioned whether the monitor could contribute to the problem. He was subsequently informed that it could not be readily determined what the equipment was actually monitoring, but it was believed that the monitor was a passive device. The inspectors were concerned that the licensee was not readily able to determine what affect the existing work in progress may have had on the SSSS.
The inspectors will review the process for assessing the status of work-in-progress as an inspection followup item (445/9312-02).
The inspectors noted that the I&C technicians utilized good self-verification techniques. The licensee's troubleshooting activities resulted in the determination that the affected component was Card XA39 located in the Train A SSSS rack. This card had been previously replaced during the conduct of Work Order 1-92-000820-00. The card was replaced and the Train A SSSS energized.
When the sequencer was turned on, the SSSS Train A displayed AL (auto lockout)
and the safety injection signal illuminated. The operators identified that the battery room Fan 11 tripped and the south vent stack particulate-iodine-gastuus monitor stopped. The sequencer was again
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deenergized and the original card placed back in the card rack. When the i
f sequencer was turned on, the AL display again illuminated.
The R0 subsequently was notified that the Train A diesel generator had started. An annunciator was received when the diesel generator had started; however, this same annunciator had activated several times earlier in the shift because of work on the air start system. The inspectors noted that the R0 had promptly dispatched an A0 to investigate the alarm.
Although a main control board indicator was available to show the diesel generator was running, the annunciator alarm received on several occasions during the shift led the operator to believe the annunciator was alarmed because of work on the l
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-13-air start system. The inspectors noted that the RO responded promptly to the notification and appropriate actions were taken to secure the diesel generator in accordance with the station operating procedure.
Following the second series of actuations, the shift supervisor declared the Train A SSSS inoperable and dated the active limiting condition for
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operation (LCO) back to the original event.
This placed Unit 1 into a 6-hour shutdown LCO as required by Technical Specification 3.3.2.11, Action 26. The inspectors noted that licensee management personnel promptly responded to the
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site to oversee the work activity and Unit I shutdown if required.
The
licensee decided to exchange the Unit 2 Train B SSSS card rack with the Unit 1
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Train A SSSS card rack.
Unit 2 was in Mode 4 and the SSSS was not required to i
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be operable. The inspectors observed the subsequent exchange and testing of the Unit 1 Train A SSSS.
The sequencer tested satisfactorily and the LC0 was exited. The card rack which was placed in the Unit 2 was analyzed at a later i
time without the LC0 time restraint.
i 3.4.3 Installation of New Reactor Vessel Level Indication Coding l
i The inspectors observed portions of the final installation of a new shielded 3'
cable which was part of the reactor vessel level indication system.
The work was governed by Work Order 2-93-040163-00, " Rework M1 Cables to Maintain Air Drop Per Design." The work was performed directly over the reactor vessel head. Through interviews, the inspectors determined the craft to be knowledgeable of their task and procedural requirements.
The inspectors found
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the task to be appropriately monitored by quality control personnel.
Good communication was established between the craft and quality control personnel.
3.4.4 Centrifugal Charging Pump Breaker Inspection and Cleaning I
The inspectors observed electrical maintenance personnel troubleshoot and repair centrifugal charging pump Breaker CCPl-01 BKR 1APCH1 per Work Order 1-93-037411-00 and Procedure MSC-J0-6301, Revision 2, "6.9kV Air Circuit Breaker Inspection and Cleaning." The work was completed in accordance with i
procedures and good work practices.
The work order was initiated because the breaker would not " rack-in" and the technicians identified the racking mechanism as the most likely component. A new mechanism was installed; however, the breaker still would not " rack-in" due to an improperly factory assembled racking mechanism.
A ONE form was initiated to address the condition.
Further troubleshooting identified a sticking shutter guide which was lubricated to correct the condition.
The new racking mechanism was removed and the old mechanism was reinstalled.
The breaker was successfully " racked-in" and tested.
3.5 Self-Verification The inspectors conducted random interviews with 21 personnel in the field to determine their familiarity with the licensee's program for self-verification.
The inspectors asked the personnel to identify the seven steps of self-i
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verification.
It was found that personnel who perform activities in
accordance with specific instructions, such as station operating procedures, (
surveillance procedures, and specific work instructions, were generally very
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familiar with the self-verification process. However, it was found that other i
personnel, such as security, TU quality control, and contract craftsmen, were not fully cognizant of licensee managements' expectation for understanding and utilizing the self-verification process.
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i 3.6 Conclusions Operations shift turnovers were conducted in a professional manner and provided a good status of plant equipment and planned ongoing activities.
Main control board annunciators were well understood and administrative controls for assessing annunciator status were well implemented.
Communication between licensed operators, A0s, and craft personnel was very l
good. An observation was made that not all causes for control room annunciator alarms investigated by an A0 were repeated back to the R0. A
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second observation was made regarding inconsistent interpretation of the problem annunciator procedure.
The A0s demonstrated that they were knowledgeable of the activities required l
l by their assigned watch station. Appropriate self-verification techniques I
were utilized when operating equipment. Three examples were identified where A0 logs did not properly identify out-of-specification conditions.
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The field support supervisors were effective in coordinating A0 activities.
They provided an essential oversight function and helped to assure that licensee management expectations were met.
However, during periods of high activity, the field support supervisors were used to supplement the A0 staff.
l This may have contributed to some A0s not being observed by the field
supervisor in the field for several months.
An observation was made that the licensee's procedure for securing of l
compressed air cylinders lacks specificity. An example of a cylinder being F
inadequately secured was encountered in an emergency diesel generator room.
Surveillance activities were conducted in accordance with procedural requirements.
Good communications were noted between the personnel performing
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the activity.
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Maintenance activities were generally performed in accordance with work instruction and procedure requirements. The SSSS troubleshooting activity was very well coordinated. The engineering involvement and management oversight was notable. A repetitive annunciator resulted in the R0 not immediately identifying that the diesel generator had started and the A0s were observed to l
have not properly operated a valve when procedurally directed to open it.
Personnel who would be expected to regularly utilize the self-verification process were cognizant of the technique. However, other personnel did not
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demonstrate that they were fully cognizant of management's expectation for understanding and utilizing self-verification.
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4 FOLLOWUP DN CORRECTIVE ACTIONS FOR VIOLATIONS (92702)
4.1 (Closed) Violation 445/9220-01 (EA 92-107):
Interruption of Spent Fuel Pool Coolinq l
l On May 12, 1992, the senior resident inspector noted discrepancies in I
indications on the main control board concerning component cooling water
cooling to the spent fuel pool cooling heat exchangers. The licensee's
investigation found that the systems were not correctly configured and that
the fuel pool had been without cooling for approximately 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br />.
Region IV
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dispatched a special inspection team to investigate the event on May 15, 1992.
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The inspection identified seven violations, some of which had multiple examples.
The causes of the violations were far reaching and involved various disciplines within the TU Electric organization.
Collectively, these violations resulted in a Severity Level III violation and the imposition of a
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5125,000 civil penalty on July 23, 1992.
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The licensee responded to the Notice of Violation and Proposed Imposition of Civil Penalty by letter dated August 13, 1992.
The response included the i
licensee's corrective actions, and the inspectors concluded that they were
extensive and addressed each of the concerns identified by the escalated enforcement action. These corrective actions included-Augmenting the control room staff with individuals with extensive
industry experience to act as consultants and advisers to senior management; Implementation of field support supervisor position to provide direct
supervisory oversight of the A0s; Reducing the administrative burden on shift and unit supervisors through
augmentation of the operating crew clerical staff; Establishment of goals for supervision to spend at least half of their
time in the field observing subordinate performance; Clarification and augmentation of the controls for locked valves;
Augmenting the design modification review group's involvement in
operational impact assessment; Enhancing the implementation of an existing program to promote self-
verification; and Reinforcing to the staff the importance of and the requirements for use
of the ONE form process.
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The inspectors reviewed 17 of the
39 specific commitments which the inspectors considered to have the greatest i
impact on correcting the conditions contributing to the violations.
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The inspectors found the licensee's corrective actions to have been
comprehensive and effectively implemented. Although personnel performance i
does not yet fully reflect managements's expectations, significant improvements resulting from the licensee's efforts have been recognized by the l
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l NRC staff. The inspectors have noted improved performance on the part of l
licensee personnel.
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4.2 (Closed) Violation 445/9214-01:
Failure to Follow Procedures
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This violation preceded the escalated enforcement action associated with NRC f
Inspection Report 50-445/92-20; 50-446/92-20.
However, since it also was the i
result of personnel performance problems, the licensee was requested to
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respond to this violation along with its response to escalated Enforcement l
Action EA-92-107. This response was provided in TUE Letter TXX-92364 dated
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August 13, 1992.
1 This violation involved four examples of failure to follow procedures. Three of the examples identified occurrences of inattention to detail on the part of
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operators or craft personnel. The inspectors found that the licensee's corrective actions appropriately addressed the personnel performance concerns l
for these three examples. The fourth example involved the failure to remove
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field work request tags from components after work had been completed. As
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discussed in the licensee's letter of August 13, 1992, a program to walk down
field work request tags, reconcile field tags with the outstanding work
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computer database, and enhance the program as necessary was to be undertaken
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and completed by the fourth quarter of 1992.
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On February 27, 1993, the inspectors determined that the program to walk down
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computer database, and enhance the program as necessary had not been
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It was later determined that substantial work still remained to be
completed. An extension to the documented commitment date had not been
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requested. The inspectors identified the failure to complete corrective i
actions as identified in TU Letter TXX-92364 dated August 13, 1992, as a deviation to a commitment (445/9312-01).
Subsequently, the licensee provided Letter TXX-93131 dated March 11, 1993, which expands the scope of the previous commitment and provides a revised date of May 31, 1993, by which corrective actions will be completed. The inspectors concurred with the expanded scope and revised completion date and will review the corrective actions associated with TU Letter TXX-93131 during the follewup to the deviation.
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4.3 (Closed) Violation 445/9214-02: Missed Technical Specification i
Surveillance Test
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This violation also preceded the escalated enforcement action associated with NRC Inspection Report 50-445/92-20; 50-446/92-20, and the licensee provided a i
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response to it in their letter of August 13, 1992.
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r This violation involved an instance where a Technical Specification
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surveillance test was missed due to inattention to detail on the part of the
1&C surveillance test coordinator. The licensee assigned a task team to
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l address a repetitive problem of missed surveillances.
The results of the task team findings and corrective actions taken are discussed in NRC Inspection i
Report 50-445/92-22; 50-446/92-22, which concluded that the licensee was
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implementing appropriate corrective actions to preclude the recurrence of
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The inspectors concluded that the licensee's corrective
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actions were appropriate.
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!li ATTACHMENT 1 1 PERSONS CONTACTED 1.1 TU ELECTRIC R. D. Bird, Jr., Manager of Work Control M. R. Blevins, Director of Nuclear Overview R. C. Byrd, Manager, Quality Control W. J. Cahill, Group Vice President, Nuclear Engineering and Operations R. R. Carter, Assistant to Maintenance Manager D. L. Davis, Manager, Plant Analysis J. W. Donahue, Manager, Operations S. Ellis, Power Ascension Manager R. Flores, Shift Operations Manager J. R. Gallman, Trend Analysis Manager l
W. G. Guldemond, Manager, Independent Safety Engineering Group T. A. Hope, Site Licensing Manager L. N. Johnson, Trend Analyst D. C. Kross, Shift Operations Manager J. W. Muffett, Manager of Technical Support & Design Engineering S. S. Palmer, Stipulation Manager E. J. Schmitt, Operations / Engineering Training Manager S. L. Smith, Work Control Center Manager J. E. Thompson, Licensing R. D. Walker, Manager of Regulatory Affairs for Nuclear Engineering Organization D. R. Woodlan, Docket Licensing Manager 1.2 NRC Personnel D. N. Graves, Senior 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
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i An exit meeting was conducted on March 3, 1993.
During this meeting, the inspectors reviewed the scope and findings of the report.
The licensee did
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not identify as proprietary any information provided to, or reviewed by, the i
inspectors.
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