IR 05000445/1993016
| ML20036A866 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 05/06/1993 |
| From: | William Jones, Yandell L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20036A864 | List: |
| References | |
| 50-445-93-16, 50-446-93-16, NUDOCS 9305170108 | |
| Download: ML20036A866 (30) | |
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APPENDIX
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U.S. NUCLEAR REGULATORY COMMISSION
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REGION IV
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Inspection Report:
S0-445/93-16
50-446/93-16
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Operating Licenses:
NPF-87 NPF-89 l
Licensee:
TV Electric
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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 i
Inspection Conducted: March 24-29, 1993 k\\D3
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Team Leader:
/ (A E B. Jones, Team Leade'
Section B, it Division of Reactor Pro
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Team Members:
L. J. Smith, Senior Resident Inspector, Section A,
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Division of Reactor Projects, Region IV i
J. M. Keeton, Licensing Inspector, Operations Section, Division of Reactor Safety, Region IV
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J. E. Whittemore, Reactor Inspector, Plant Support Section, Division of Reactor Safety, Region IV J. D. Wilcox, Special Inspection Branch,
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Office of Nuclear Reactor Regulation
Assisting:
C. Skinner, Intern, Technical Support Section, Division of Reactor Projects, Region IV
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Approved:
l. A. Yanfell, Chief, Project Section B Dat.
Division of Reactor Projects
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9305170108 930510 PDR ADDCK 05000445 O
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EXECUTIVE SUMMARY A readiness assessment team inspection was conducted on March 24-29, 1993.
The inspection team consisted of NRC staff members from Region IV and the Office of Nuclear Reactor Regulation.
The findings from this readiness i
assessment provided input for the NRC determination of TU Electric's readiness to safely conduct power operations before issuance of the full-power license i
at the Comanche Peak Steam Electric Station, Unit 2.
The NRC team utilized the guidance provided in NRC Inspection Procedure 93806,
" Operational Readiness Assessment Team (0 RAT) Inspection." Areas inspected
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included operations support, plant operations, and safety assessment / quality verification. During the inspection, the team observed over 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> of onshift activities related to the operation of Unit 2.
This included sustained control room observations, observation of maintenance and surveillance activities, technical support for operations, the effectiveness of management oversight and the identification and resolution of plant and programmatic deficiencies.
The team also reviewed the actions taken by the licensee in response to one of the deficiencies identified in NRC Inspection
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Report 50-446/92-201.
Management personnel maintained cognizance of plant status and were involved in assessing plant and program deficiencies as well as personnel performance
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concerns. Appropriate staffing levels were maintained to support dual unit maintenance and surveillance activities.
Engineering personnel were effective in resolving initial startup concerns and related technical issues.
The personnel involved in the various problem solving efforts were.well trained and demonstrated the appropriate awareness for potential safety problems. The team noted that the engineering
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supervisors and managers were cognizant of emerging technical issues.
These issues were generally promptly addressed and resolved.
The technical support provided by the training organization was very good,
was noted that the training organization had been proactive in providing the knowledge and skills required by operations personnel to safely operate two nuclear units with minor differences and some shared nonsafety-related
systems.
Potential problem areas such as operator awareness of the other unit i
and inter-unit communications were appropriately addressed.
The conduct of operational activities was controlled in an excellent manner.
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Shift turnovers were professional, well organized, and propagated pertinent plant status and planned activities.
Command and control by the shift and unit supervisors was very good.
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Communications between the control room staff were good.
It was noted that
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communications between the operators were occasionally open-ended; however, communications with the auxiliary operators (A0s) included consistent use of repeat back statements. Communications between the two units was appropriate.
i The shif t supervisor maintained overall awareness of plant activities.
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The licensee demonstrated excellent control of locked components.
Clearance controls were also well implemented. Main control board keys used tc
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manipulate control switches were not effectively controlled.
This condition
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was corrected by the licensee during the course of this inspection.
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.The operating staff demonstrated a good understanding of Technical Specifications requirements and did not inappropriately rely on special test
exceptions.
The cumulative effect of planned entries into action statements I
was appropriately considered.
l The A0s were found to be fully cognizant of their duties and conducted their activities in a professional manner.
The field support supervisors were
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effective in coordinating work activities between the A0s and the control room
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staff.
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r Work activities were performed in accordance with the work requirements.
j Startup and surveillance testing activities were also well performed.
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Communications between the personnel responsible for implementing the testing j
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activity were very good.
Startup test personnel were technically i
knowledgeable of the test requirements.
The operations staff closely I
monitored plant parameters and appropriately responded to anomalies detected j
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during testing.
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The licensee had implemented an ef fective self-assessment capability as l
demonstrated by the deficiencies identified through the Operations
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Notification Evaluation form process.
The licensee has proposed root cause
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analysis program enhancements to better establish accountability at the line organization level.
The root cause determination performed for the misaligned i
Borg-Warner pressure seat check valve was appropriate.
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The reviews conducted by the Operations Notification Evaluation Form Committee
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and the Station Operations Review Committee demonstrated an excellent
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awareness of conditions which could adversely affect plant safety.
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expected safety perspective was demonstrated by both committees.
'The licensee's 5 percent power self-assessment was well performed.
Conditions l
which could have an adverse impact or, power ascension activities and full
power operation were appropriately considered. The nuclear oversight
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department's involvement in the safety assessment process, including the self-
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assessment activity was well conducted.
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TABLE OF CONTENTS
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EXECUTIVE SUMMARY..
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l OETAILS.............
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1.
INSPECTION SCOPE AND OBJECTIVES.
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OPERATIONS SUPPORT
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2.1 Overview
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2.2 Management Support
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2.2.1 Plan of the Day Meeting
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2.2.2 Management Breakout Meeting
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2.3 Maintenance and Surveillance Scheduling
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2.3.1 Management and Organization
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l 2.3.2 Performance Trending..
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2.4 Engineerina/ Technical Support
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2.4.1 Engineering Support
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2.4.1.1 Temporary Modification............
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2.4.1.2 Low Power Physics Test.
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2.4.1.3 Main Feedwater Pump Overspeed Test....
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2.4.1.4 Safety injection Accumulator Level
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Indication.................
1 2.4.2 Technical Support
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2.4.2.1 Operator Training
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2.5 Conclusions
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3.
PLANT OPERATIONS.........
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3.1 Overview
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3.2 Conduct of Operations
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3.2.1 Shift Turnover.......
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3.2.2 Command and Control
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3.2.3 Control Room Communications and Logkeeping....
3.2.4 Configuration Control
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3.2.4.1 Key Control
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3.2.4.2 Locked Components Deviation tog
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3.2.4.3 Limiting Condition for Operation Tracking
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3.2.4.4 Control of Fire Doors Impairments
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3.2.5 Annunciator and Control Room Indication Response.
3.2.6 Auxiliary Operator Performance...........
3.2.7 Field Support Supervisor..
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3.2.8 Housekeeping....................
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3.3 Maintenance and-Surveillance Implement ation
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3.3.1 Maintenance Implementation.......
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3.3.1.2 Safety Injection Pump Preventive Maintenance.
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3.3.1.4 Station Service Water Strainers
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3.3.1.5 Centrifugal Charging Pump
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3.3.1.6 Condensate Pump
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3.3.2.1 Operation Performance Test.
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s 3.3.2.2 Rod Swap Measurements
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3.3.2.3 Train A Safeguards Actuation Test
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3.3.2.4 Service Water System.
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3.3.2.5 Leak Rate Test.
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i 3.4 Conclusions
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SAFETY ASSESSMENT / QUALITY VERIFICATION
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4.1 Overview.....
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4.2.1 Proposed Program Enhancements
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4.2.2 Borg-Warner Pressure Seat Check Valve
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i 4.3 Operations Notification and Evaluation Committee...
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4.4 Station Operations Review Committee
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f 4.5 Nuclear Oversight Department Integrated Activities..
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4.6 Licensee S Percent Self-Assessment.
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4.7 Unit 1 Licensee Event Report Review
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4.8 Conclusions
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5.
FOLLOWUP (92701)
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ATTACHMENT - EXIT MEETING AND ATTENDEES
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INSPECTION SCOPE AND OBJECTIVES
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On March 24-29, 1993, a team of NRC inspectors conducted a readiness
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assessment team inspection at Comanche Peak Steam Electric Station.
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primary objective of this team inspection was to evaluate the initial dual
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unit operations and the readiness of Unit 2 for full-power operation. This was accomplished through direct observation and evaluation of personnel and organizations that control and support plant operations in order to verify that they were functioning effectively.
L The inspection effort concentrated on Unit 2 control room operations and related activities that support the facility's safe operation.
The inspection
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team's efforts were mostly performance based to ascertain how well the
licensee's programs and management's expectations were being implemented.
The principle areas evaluated were operational support, plant operations, and safety assessment activities.
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During the inspection period the team was on site Unit I was at essentially
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100 percent power. Unit 2 had received a low power license (not to exceed 5 percent power) and was operating at or below 2.5 percent power.
2 OPERATIONS SUPPORT 2.1 Overview
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The team reviewed selected activities which impacted on the licensee's ability to support dual unit plant operations. This included management involvement with operational activities and the adequacy of the maintenance department staffing as reflected by the implementation of the maintenance and surveillance programs for both units.
The review also included engineering personnel involvement with the startup test program and resolution of plant deficiencies.
2.2 Management Support 2.2.1 Plaa-of-the-Day Meeting The team attended three plan-of-the-day meetings.
It was noted that the meetings were well organized and attended by a representative of each i
department, usually at the manager level.
The organizations which were represented included operations, maintenance, work control, radwaste, chemistry, engineering, procurement, nuclear oversight, licensing, radiation protection, and outage planning.
Both general interest and department action
items were discussed.
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The operations department provided a comprehensive overview of plant status, operating issues,-and applicable limiting conditions for operation action
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requirements (LC0ARs).
The work contro'I center representative reviewed the l
status of significant and emergent work activities.
The_ status of ongoing and t
planned work activities was-provided for those activities which required integrated department coordination or involved LC0ARs.
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The other departments reviewed ongoing action items and identitied estimated
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completion dates.
Examples included the status of technical evaluations and
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work issue dates for resolving problem annunciators.
It was noted that the j
interaction between the departments was very goed and that personnel were
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being held accountable for their items.
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A summary of Operations Notification Evaluation -(ONE) forms submitted since j
the last meeting was discussed for those involving a significant event or
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personnel error. The need to review selected ONE forms as plant incident
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reports was also discussed.
The team found that the. licensee openly discussed j
plant and program deficiencies and personnel errors during these meetings.
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2.2.2 Management Breakout Meeting i
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The licensee scheduled regular breakout meetings which immediately followed
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for discussing plant issues, future integrated activities, and special issues
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with the cognizant department' managers.
The team noted these breakout
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meetings included the discussion of issues pertaining to component l
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configuration control, plant chiller readiness for summer conditions, and Technical Specification program review.
It was found that the meetings were
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productive and usually resulted in good interaction between the cognizant j
groups.
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2.3 Maintenance and Surveillance Schedulinq
l 2.3.1 Management and Organization The team reviewed the licensee's maintenance organization staffing chart and
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Emphasis was placed on their ability to provide
backshift and weekend coverage.
The maintenance department was reorganized to
i-meet the format detailed on the organization chart dated December 30,1992.
J The team evaluated whether the licensee's maintenance staff could support the Unit 2 power ascension program operation and subsequent dual uni _t operations.
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During this inspection, par cicular attention was given to the backshift and
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weekend coverage from the mechanical, electrical, and instrumentation and
control.(I&C) crews that supported Unit 2 startup.
It was noted that the j
maintenance staff was consistent-with what was depicted in the organization
chart. The team observed that the licensee was able to implement planned and r'
emergent work activities for both units. Appropriate maintenance coverage was provided during backshift and on the weekend.
The team reviewed the number of completed work activities' for Unit I and common equipment during the period of August through September 1992.
A-similar review was conducted for the period January through February 1993.
l The second review also included completed Unit 2 work activities.
These work i
activities consisted of corrective, planned, and surveillance work.
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In August and September there were approximately 1160 and 1270 Unit I work
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activities completed, respectively.
Following the incorporation of Unit 2
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common equipment in January and February were approximately 1550 and 1260.
For Unit 2, 810 work activities were completed for February and 790 were completed for the first 3 weeks in March.
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The team reviewed the list of outstanding work on both units that was assigned to the mechanical, electrical, and I&C departments.
It was determined from this review that approximately 800 outstanding work items. remain for each unit. This review also showed that the total number of outstanding work i
activities had decreased over the last several months.
The team concluded i
that the licensee had established appropriate maintenance staffing levels.
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This was based on the licensee's demonstrated ability to effectively manage the maintenance backlogs for both units and promptly address emergent and significant work activities.
2.3.2 Performance Trending j
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The team reviewed the maintenance performance indicators developed by the j
licensee for the period March 16-22, 1993. This document assessed opened and
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closed work activities and trended the same for both units. The team noted j
that most of the trends were favorable or stable.
The only trend that was l
slightly negative was for the I&C corrective maintenance backlog.
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noted that the licensee's maintenance trending program provided an effective
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means for management to routinely assess the status of maintenance backlog and
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to identify areas where additional emphasis or resources may be needed.
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2.4 Engineering / Technical Support
j 2.4.1 Engineering Support
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2.4.1.1 Temporary Modification l
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On March 25, 1993, the licensee initiated Temporary Modification 93-2-06 to
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modify the reactor vessel head vent (2-HV-3608) valve position indication circuitry.
This temporary modification provided for the installation of l
jumpers in a control circuit cabinet to restore valve position indication and
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main control board annunciation.
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i The team noted that the licensee appropriately implemented the interim corrective actions to control temporary modifications as provided in their l
response to Notice of Violation 445/9262-01, -02, and -03 as described it. NRC-l Inspection Report 50-445/92-62; 50-446/92-62. The presentation of the
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proposed temporary modification before the station operations review
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committee (SORC) members was observed.
It was noted that the 50RC provided a j
thorough review of the proposed temporary modification.
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Following approval by the 50RC the temporary modification was implemented.
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The team observed the postmodification test performed on tL valve to assure l
operability. The test was conducted in accordance with the test instructions and the drawings were appropriately updated to reflect the installed jumpers
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2.4.1.2 Low Power Physics Test j
i During the performance of zero-power physics testing, the operators noticed a I
control rod out of alignment. While withdrawing Shutdown Bank A, Control
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Rod B-4 became misaligned by 10 steps.
Upon inserting Bank A, Control Rod B-4
remained misaligned by 10 steps. The operators determined that the rod was
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operable, but entered the Technical Specification action statement to restore the control rods to within the insertion limits.
The control rod was realigned, withdrawn again, and noted to be r.isaligned by 4 steps.
Engineering was asked to perform a technica.1 evaluation to determine the
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impact on continued testing.
The evaluation determined the following:
During testing the maximum misalignment of Control Rod B-4 was 10 steps.
-f Technical Specifications 3.1.3 and 4.1.3 stated that all control rods
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counter demand position.
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Control Rad B-4 was within 12 steps of the counter and could be
inserted, therefore, it was considered operable.
Based on the above review, the licensee concluded that the Control Rod B-4 met j
its operability requirements and would not impact future testing as long as it
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was aligned within 12 steps of the group demand counter. Since future testing would not require manipulation of Shutdown Bank A, the licensee determined that immediate corrective action was not necessary.
Engineering personnel
initiated Work Request 132804 to hook up test equipment (Visicorders) to monitor the Control Rod B-4 coils during future shutdown Bank A manipulation.
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Operator performance during this test is documented in Section 3.3.2.2 of this
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report.
i 2.4.1.3 Main F4 edwater Pump Overspeed Test
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On March 26 and 27, the licensee conducted overspeed testing on Main feedwater Pumps 2-01 and 2-02, respectively.
Prior to performing these overspeed tests, j
operations personnel identified a potential concern which was referred to
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engineering for resolution. This concern involved the potential to exceed the
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5 percent license power limit based on whether the power range nuclear i
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instrumentation was sufficiently accurate to assure that-the low power license l
limit would not be exceeded during testing in the power range.
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i Engineering subsequently provided a readily measurable means of assuring reactor power did not exceed the 5. percent low power license. A value of l
0.25 percent on the power range monitor was assigned to the nuclear instrument j
power range monitors as the point where nuclear heat was being generated.
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This corresponded to a value on~ the intermediate ranga nuclear instrumentation
of 6x10(E-7) amps. This later value was determined during performance of l
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Procedure NUC-109, Revision 5, " Determination of the Point of Adding i
i Heat (PDAH)."
Based on the power range nuclear instrumentation being i
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value 10 times that of POAH would equate to 2.5 percent core thermal power.
l The final recommendation was that operations should set a limit of
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5x10(E-6) amps on the intermediate range monitor to assure that the license power limit was not exceeded.
The technical response included a number of
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parameters that would either affect or indicate changes in reactor power.
The vendor concurred with the resolution and cautioned the licensee not to use i
these numbers for nuclear instrumentation calibration or the unit
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calorimetric.
The licensee decided to proceed with the tests after i
establishing an effective means of monitoring reactor thermal power and identifying parameter limits, l
The team observed the main feedwater Turbine 2A overspeed trip test conducted
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by operations in the Unit 2 control room and locally.
This test was performed
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in accordance with Procedure PPT-P2-2028A, Revision 1, " Main Feedwater l
Turbine 2A Overspeed Test."
All personnel involved were well briefed on the i
test activity.
During the test, the unit operators monitored plant conditions
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to ensure that power level remained steady and within the operating limits.
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2.4.1.4 Safety Injection Accumulator Level Indication f
The team reviewed the licensee's resolution of a problem involving the level indication on the Unit 2 Safety Injection Accumulator 3.
Unit 2 had entered
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Mode 3 on March 11, 1993, and subsequently a safety injection accumulator level channel check was performed as required by the Technical Specifications.
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The acceptance criteria for this check were that the two independent level indicator channels (2-LI-954 and 2-LI-955) should agree within 5 percent on i
the 0-100 percent instrument range. A review of the shift surveillance logs
indicated that, since the unit had entered Mode 3, the level indicator
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instruments had differed by approximately 5 percent.
Several work orders had a
been initiated to reduce the disagreement to less than 5 percent.
The team
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reviewed the licensee's efforts to resolve the level indication problem.
t These activities included-i Calibrating instrument Channel 2-954 rack on March 13, 1993.
- Calibrating instrument Channel 2-955 transmitter on March 15, 1993.
The identification of a linearity problem with the instrument l
Channel 2-954 transmitter on March 16, 1993, and replacement of the
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circuit board.
The transmitter subsequently failed.
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The instrument Channel 2-954 transmitter was replaced on March 21, 1993; <
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however, the difference in the instruments continued to remain at
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5 percent I
Engineering then initiated a field survey to verify the level tap elevations
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and calibration inputs used in the scaling calculations. The surveys revealed i
that the elevation inputs were incorrect for both channels.
Based on the l
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i identified errors in elevation on Unit 2 Accumulator 3, engineering provided a j
reduced operability range for level in all accumulators for both units.
It was also determined that an operability concern did not exist.
The operations
department invoked the new recommended limits, which were more restrictive than the Technical Specification limits.
Field elevation surveys were initiated for the remaining Unit 2 accumulator instrument taps.
A minor elevation error was identified on another accumulator.
The licensee later obtained the original elevation survey data for the Unit 2 accumulators.
This data was found to be in close agreement with the recent
.l survey data. A comparison of the survey results to the values used to t
determine the calibration data was performed. This comparison identified that
the data transcription errors occurred between the original survey data and
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its use in the scaling calculations. To address the generic implications, the
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licensee reviewed the accumulator level instrument survey data and its use in i
i the calibration data scaling calculations.
'A minor error was noticed for j
Unit 2 Accumulator 2.
At the end of the inspection, the licensee had resolved
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the channel check deviations and was preparing a new calibration procedure i
that would provide more accurate insitu testing of the accumulator level
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indicating systems. This insitu testing would provide for measuring the level i
in the standpipe using ultrasonic techniques.
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2.4.2 Technical Support
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2.4.2.1 Operator Training l
Late in the construction phase for Unit 2, the licensee had developed and implemented a program to identify and assess the differences between the l
units. This program and its application to the. licensee's training programs j
was. addressed in NRC Inspection Report 50-445/92-45; 50-446/92-45. The i
program was considered to be effective for identifying and assessing unit j
differences.
Once the differences had been identified and initially assessed, I
the licensee's engineering organization initiated a comprehensive effort to j
identify any operational problems that could result from the identified unit differences.
Project Technical Report 29 issued in July 1992 identified
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problems that could result from the two units in similar and dissimilar modes.
-j The results of the unit difference assessment and the engineering evaluation of the effects of these differences were provided to the licensee's training j
organization. The training material was revised to include this information.
l The material was initially included in a lesson plan that addressed unit
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differences which was used during the continuing training _ sessions for i
operational and technical programs.
For operational programs, the training
organization was in the process of integrating the unit differences
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information into specific system or functional training guidelines (lesson
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plans).
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The training department had also developed and implemented operator training j
for the initial startup and physics testing sequence. The completed startup
testing program for Unit 1 was reviewed and a lessons learned list was j
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A classroom training session was developed from the lessons
learned list and the Unit 2 initial startup testing program.
This training
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was administered to all licensed operators prior to initial criticality on
Unit 2.
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The training department management had developed the following goals and expectations to address expected problems with operation of two units:
l Revise training simulator scenarios to reflect two unit operation.
- l Standardize operator communications to require that specific units be
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identified for simulator training and evaluation sessions.
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Revise job performance measures to allow them to be performed on either
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unit.
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I Develop separate scenario computer disks that will simulate the i
performance of each unit.
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2.5 Conclusions
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The licensee had demonstrated an appropriate level of management oversight of
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plant activities. The plan-of-the-day and breakout meetings provided i
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management with a current status of plant activities and an effective forum
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for identifying plant and program deficiencies as well as personnel
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performance concerns. Appropriate staffing levels were established to support
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dual unit maintenance and surveillance activities.
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i Engineering personnel were effective in resolving initial'startup concerns-and l
related technical issues The personnel involved in the various problem
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i solving efforts were well trained and demonstrated the appropriate awareness j
for potential safety problems. The team noted that the engineering supervisors and managers were cognizant of emerging technical issues.
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The licensee's technical resolution of the safety injection accumulator level j
indication channel discrepancy was good.
The inspectors noted good
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engineering involvement in determining the reason for the deviation.
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Appropriate compensatory measures were taken in response to a scaling
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calculation error.
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The technical support provided by the training crganization was very good.
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was noted that the training organization had been proactive in providing the j
knowledge and skills required by operations personnel to safely operate two i
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nuclear units with minor differences and some shared nonsafety-related i
systems.
Potential problem areas, including operator awareness of the other
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unit and inter-unit communications, were appropriately addressed.
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t 3 PLANT OPERATIONS
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3.1 Overview i
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f The team performed over 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> of direct control room observations ~.
These observations were conducted to review plant operations department activities
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and to determine the level of support to the operations department by the
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other parts of the licensee's organization. The team observed several shift j
turnovers, briefings, startup test briefings, and maintenance and surveillance l
prebriefings.
l-r 3.2 Conduct of Operations
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t 3.2.1 Shift Turnover i
The team attended the 6 a.m. and 6 p.m. shift turnover meetings conducted by i
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the relief and offgoing shift supervisors (SS).
These turnover meetings were j
i held in the technical support center which eliminated any distractions.
The i
turnover meetings were found to be well organized, professional, and effective i
in propagating the needed information to assess the plant status and planned activities.
Following the turnover in the technical support center, the
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operators received their watch turnover at their duty assignment, in each
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case the operators were cognizant.of the plant status prior to. assuming their i
watch.
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Control room staffing met the requirements established in Procedure ODA-102, l
" Conduct of Operations," which implemented Technical Specification 6.2.2.b.
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reactor operator was always observed to be in the "At the Controls Area," as
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defined in Final Safety Analysis Report Section 13.5.13 and Figure 13.5-1.
j 3.2.2 Command and Control
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The team observed the command and control function to be well implemented by
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operations supervisory personnel.
Each unit supervisor (US) maintained direct i
control of all. evolutions involving the unit for which he was-responsible.
The SS maintained appropriate oversight of both units.
All tests and
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infrequent operations were preceded by a briefing of all individuals involved.
One example involved the increase of reactor power to approximately 2 percent-in the power range.
Prior to beginning the evolution, the SS quizzed the
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operators on parameters to watch, what to expect, and actions to take if the j
evolution did not proceed as predicted.
A second example involved a US's l
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assessment of a planned work activity which required the excore detectors to i
be moved. Although the detectors had only been activated for a short period and were not believed to be highly radioactive, the US maintained that the
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work activity would be performed consistent with appropriate radiological l
control practices. The US did not authorize the activity until health physics l
personnel had evaluated the activity.
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The team noted that personnel access to the "At the Controls Area" was l
appropriately restricted.
Quiet periods were established prior to beginning-l
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significant plant evolutions to permit the operators time to review the planned activity.
The US and SS did not hesitate to bring in additional operators to assist in evolutions being performed or to provide additional
coverage.
Based on discussions with operations personnel in the control room,
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it was determined that operations maintained a continuous awareness of
activities beyond the scope of their individual responsibilities. The role of i
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the field support supervisor to maintain oversight and coordination of i
auxiliary operator (AO) activities outside of the control room was' effective.
3.2.3 Control Room Communications and Logkeeping The team noted that routine communications among the crew members for each unit were good; however, several instances of open-ended information transfers l
were noted.
The communication techniques improved when the significance of
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the information increased, such as responding to alarm annunciation and
preparing to make changes in plant status.
The team noted that communication
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between' the control room and A0s was very good.
The use of repeat-back statements were consistently utilized.
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The USs communicated very well between units. One example involved a Unit 2
event which caused an annunciator on Unit 1.
Procedures were properly
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followed. All members of the operating crews referred to procedures
frequently when performing evolutions.
The alarm procedures were referenced
when new alarms were received and also to check alarms that had been received
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earlier and were sealed-in to verify their reason and validity. The expected
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questioning attitude was observed of the operators.
3.2.4 Component Configuration Control i
3.2.4.1 Key Control l
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The team observed preparations to cycle the reactor head vent valve.
The manipulation of this valve required the use of a specific main control board _
i key.
The team noted that, although the key was located in the US's desk, it was not immediately retrievable. The control of similiar keys in the SS's l
office was then assessed.
The team member noted that it took approximately
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3 1/2 minutes to locate the proper key.
It was then found that a similiar
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condition existed for Unit-1.
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The licensee initiated prompt action to uniquely label main control board
- l keys. The team reviewed the licensee'.s actions and found _that this and similiar keys could be promptly~ retrieved.
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i 3.2.4.2 Locked Components Deviation Log
The team verified the status of approximately 200 locked valves associated
with safety-related systems. All of these valves were found in their correct
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position and were properly secured.
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-10-On March 28, during a plant tour, a lock wire was found near the remote
operator for Valve 2RH-8734B-RO, "RHR Hx 2-02 to CVCS Ltdn Iso Vlv Rmt Oper."
l The valve was observed not to be locked.
The valve was in the required closed
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position. The team questioned whether or not Valve 2RH-8734B-R0 was required
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to be locked.
The SS consulted Procedure 50P-102B, Revision 0, " Residual Heat Removal System," and ' determined that the required valve configuration was closed and not locked.
i 3.2.4.3 Limiting Condition for Operation Tracking
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t The Unit 2 LC0AR Notebook was used to track the status of Technical l
Specifications as required by Procedure ODA-308, Revision 5, "LC0 Tracking i
Program." Procedure ODA-308 contained appropriate review requirements to ensure that the cumulative effect of planned entries into action statements
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was considered and established procedural restrictions against planned entry i
into Technical Specification 3.0.3.
The team verified that selected entry and
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exits from Technical Specification action requirements were properly logged.
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3.2.4.4 Control of Fire Door Impairments
I On March 28, the te, noted that two sets of double fire doors were blocked i
and open. A hose was running through the fire doors which was being used
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intermittently to drain the reactor makeup water storage tank to a drain in
the component cooling water pump room.
The door posting indicated that they i
should both be open and not blocked.
It was subsequently determined that the i
doors were properly identified on the " Fire Protection Equipment / System j
Impairment Status Report" and that an hourly fire watch had been implemented
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as a compensatory measure.
3.2.5 Annunciator and Control Room Indication Response At the beginning of the inspection, the team observed that the-operators were j
not routinely announcing unexpected alarms. This was discussed with licensee i
management and increased emphasis was placed on calling out annunciators.
l Subsequently the operators announced r t' the alarms. They announced all l
of the significant alarms and were a'
2 to the-routine recurring low j
power alarms. The callout of annunciawrs was addressed during the shift
turnover briefings. The team noted that the emphasis was on meeting what was
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perceived as an-NRC expectation and not TU Electric's management's j
expectation.-
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On March 27 an unexpected alarm came in on the safety system inoperability i
indication panel.
The US promptly referenced the alarm response procedure and
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determined that the alarm _was expected, due to an instrument air system
maintenance activity.
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The operators responded promptly to steam generator level deviation alarms for Steam Generators 2-01 and 2-04.
The steam generators' fill rate had been j
increased in preparation for a main feedwater pump turbine test.
The test was j
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subsequently aborted because of questions raised prior to beginning the test.
l The fill rate was decreased when the alarms came in.
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i During the briefing on the main feedwater pump test, an annunciator for
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emergency Diesel Generator 2-01, DG UNAVAIL, alarmed.
The US and SS immediately stopped the briefing and directed the actions of the operators in attending to the alarm.
The safeguards building A0 identified the problem as
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a low starting air pressure on one of two redundant air banks, resulting from the associated compressor not starting. The compressor breaker was found in the tripped position. When the A0 closed the breaker at the US's direction, j
the compressor started and starting air pressure was restored.
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3.2.6 A0 Performance i
The team accompanied several 40s during the conduct of their rounds.
Selected shif t turnovers were also observed.
It was noted that the A0's performance t
was consistent with management's expectations.
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The A0s demonstrated a good working knowledge of systers and components in f
their areas of responsibility. There appeared to be an increased sensitivity
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to the possibility of operating components on the wrong unit. When the A0 was
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directed to operate a component, he was deliberate in verifying that the
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equipment to be operated was on the correct unit.
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During an observation period by the inspector, an A0 was instructed to remove i
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tags and return the Unit 1 positive displacement pump to operation by opening the suction and discharge valves. Upon arriving at the pump, both valves were discovered to be in a contaminated area with both valves (along with the tags on the handwheel) wrapped in plastic.
The plastic and clearance tags were
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radiologically contaminated. The A0 properly notified his supervisor, who
then contacted the health physics department..The bags were removed from the valves and the valves were decontaminated The clearance tag was found to be
.i highly contaminated and required proper disposal. The A0 demonstrated the use
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of good radiological practices in this situation.
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i The team noted that the valves could have been wrapped in plastic without j
including the handwheel and clearance tags. This.would have permitted the A0 to remove the clearance tag and return the system to operation without j
requiring decontamination of the valve or the generation of additional
contaminated waste.
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.While accompanying the A0 on his rounds, it was noted that use of calibration
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stickers on local instruments appeared to be inconsistent.
For example, on
the local steam generator blowdown _ panel which is common to both Units 1 and 2, all Unit 1 instruments had calibration stickers, but no stickers were
on the corresponding Unit 2 instruments. When questioned on use of j
calibration stickers, there appeared to be some confusion related to the
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implementation of this policy. A manager cognizant of the pcactice stated
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that they were working on the problem and_ that stickers were being placed on i
Unit 2 instruments in accordance'with current policy.
The team identified j
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that management had not been effective in assuring that the A0s understood l
that the calibration stickers provided a means of assuring they were taking i
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log readings from instruments within their calibration cycle.
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l The licensee demonstrated that each instrument's calibration was tracked by a i
computer program and the calibration schedule was in accordance with
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Procedure STA-677, Revision 2, " Preventive Maintenance Program." The team i
verified that the identified instruments were within their current calibration i
cycle.
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During the routine performance of Procedure OPT-218B, Revision 0, " Containment l
Penetrations Non-automatic Isolation Component Position Verification (ORC),"
i the A0 identified that the descriptions for two process sampling vent valves, 2MS-0599 and -0600, were incorrect in the procedure and on the tag.
j Valve 2MS-0599 was listed as being on a sample line from Steam Generator 2-04;
however, based on the field installation and a review of Drawing M2-020,
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Sheet 2, it was determined that the sample line was actually connected to
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Steam Generator 2-01.
Similarly, Valve 2MS-0600 was listed as being on a
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sample line from Steam Generator 2-01 when the sample line was actually
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connected to Steam Generator 2-04.
The US further checked the master
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l equipment list, the corresponding Unit I drawing, and System Operating Procedure 50P-314, Revision 1, " Steam Generator Recirculating System," to
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verify the finding. He initiated an ONE form in accordance with the corrective action program to identify the discrepancy.
i 3.2.7 Field Support Supervisor-
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Following a loss of spent fuel pool cooling event in May 1992, the licensee
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implemented a field support supervisor (FSS) position to coordinate and-j oversee A0 activities for bMh units.
Procedure ODA-102, Revision 14,
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" Conduct of Operations," Sitt ion 6.4, established that the FSS was responsible to the US for directing anc :oordinating operational activities outside the control room.
This included directing the activities of the A0s to ensure-
proper-equipment operation and clearance implementation and restoration.
j During the inspection, the team noted some confusion about the reporting f
responsibility of the FSS.
Licensee management responded by issuing a shift i
order on March 26, 1993, stating the FSS reports to the SS.
If the FSS was
performing a function related to a particular unit, the FSS would take
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functional instructions-from the US, but the overall FSS responsibilities were.
i to'be controlled by the SS.
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The team noted there'were no specific training requirements for this position; however, personnel were required to be a fully qualified A0 and a licensed operator, er have a senior reactor operator certification.
The team reviewed the training records for the current incumbents in~the FSS position. This
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review revealed that the incumbents had been given training to enhance their supervisory skills.
The review also indicated that incumbents were participating fully in the current applicable training program.
The team j
observed the FSS performance in the plant and activ.ities which involved
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coordination between the USs and the Aos.
It was found that the FSS's I
position was being effectively implemented.
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3.2.8 Housekeeping l
Previous NRC inspection reports had noted an improving trend in housekeeping
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as construction activities were completed and the plant was turned over to operations. During this inspection, the team noted that, generally, housekeeping was good; however, some debris was found in several rooms.
This
was brought to the attention of the licensee and action was taken to clean up i
those areas.
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3.3 Maintenance and Surveillance' Implementation j
i 3.3.1 Maintenance Implementation j
i 3.3.1.1 Work Request Tags j
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i The team conducted several tours through the plant. Very few deficiencies
were identified which were not identified by deficiency tags. A review of i
several work request tags hanging in the field did not identify any that were
'I older than 6 months.
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3.3.1.2 Safety Injection Pump Preventive Maintenance (PM)
i The team reviewed the PM history for Safety Injection Pumps and Motors 2-01 and 2-02.
This review included a review of the vendor's Technical
Manual CP-0001-032. " Safety Injection Pumps and Motors." The team had a
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question related to the documentation provided. The vendor manual provided
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specific guidance for lube oil change recommendations and vibration
guidelines. The PM summary provided for these components identified a
frequency of 91 days to sample oil and 182 days to monitor vibration. The j
initial work order history provided to the team on these components suggested there might have been some delinquent PMs.
Addition data was needed to ensure
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the proper preventive maintenance had been performed.
The licensee provided l
the team with the necessary documentation to support the view that proper
preventive maintenance had been given to the safety injection pumps and
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3.3.1.3 Diesel-Fire Pump The team observed the performance of Work Order 92-302973-01, which involved l
the PM activities on the diesel-driven Fire Pump X-05.
The work was performed
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according to the written instructions.
It was noted that a drawing was l-provided on the work package which contained penciled-in additions. ~The planner apparently added in valves and components from connecting drawings.
I One additional item noted by the inspectors was that the inoperable fire pump i
was reading 1400 rpm because of a broken gage and the cond; tion had not been
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previously identified.
The licensee initiated a work request to repair the i
gage.
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i 3.3.1.4 Station Service Water Strainers t
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Mechanical Work Order 93-301045-01 entailed cleaning the strainer on the l
Safety injection Pump 2-01 lube oil cooler station service water inlet i
strainer. The work activity was well coordinated with operations and maintenance departments.
3.3.1.5 Centrifugal Charging Pump
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Maintenance Work Orders 93-030172-00 and 042556-00 entailed replacing a test j
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tee adapter on the Centrifugal Charging Pump 1-01 Suction and Disc 5arge valves 0187 and 0118, respectively. The team observed the preparation phase'
of the activity.
Good support was noted to erect the scaffolding and provide
'l radiation protection coverage.
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'I 3.3.1.6 Condensate Pump l
The team observed the performance of Work Order 1-93-032339-00. This work
entailed cleaning Fan Motor 1-41 on the condensate pump / heater drain pump area l
vent supply fan.
The work activity was accomplished in accordance with-l prescribed instructions.
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3.3.2 Surveillance Implementation
3.3.2.1 Operation Performance Test l
Surveillance Observations - Surveillances were observed on the CCW system (OPT-2088, Revision 1, "CCW System") and on Emergency Diesel Generator 2-01
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(OPT-214B, Revision 0, " Diesel Generator Operability Test," Section 8.1).
All
surveillance activities were conducted in accordance with the procedures and
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good engineering practice. Any unexpected conditions or questionable
parameters were directed to the supervisors and the appropriate engineer for
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interpretation and resolution.
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3.3.2.2 Rod Swap Measurements On March 25 appropriate precautions and limitations were discussed in the i
prejob brief prior to reinitiation of Procedure NUC-120, Revision 3, " Rod Swap j
Measurements." During performance of the rod swap test for Shutdown Bank A, l
the~ reactor operator noticed that the intermediate range monitor indicated 2 x
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10" amps which exceeded the procedural guidance of 1.5 x 10" amps from.
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Procedure ISU-101B, Revision 1, " Initiated Criticality.and Low Power Test
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Sequence," Step 9.1.2.
It was-determined that the reactivity computer
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received input from the Power Range Excore Detector N-41 which was shielded
during manipulation. of Shutdown Bank A and, therefore,' the reactivity computer -
l recorder was not indicating actual power. level _ because of the control rod
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shadowing' effects. As a result, operation within=the range of the reactivity
-computer recorder did not assure operation within the guidance of
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Procedure 15U-1018.
Because test data was taken below the P0AH which occurred l
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at 6 x 10" amps, operation at 2 x 10' amps did not affect test validity. At all times, the reactor power was below the license limit of 5 percent.
The operating staff demonstrated a thorough understanding of the intent of Special Test Exception STE 3.10.3 during the inspection.
Each oncoming crew reviewed the action requirements associated with Test STE 3.10.3 during shift
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turnover.
Reactor power and reactor coolant system temperature were i'
maintained within required limits and logged periodically.
An anomaly occurred during control rod worth measurement for Shutdown Bank A.
As discussed in Section 2.4.1.2 of this report, Control Rod B-4 misaligned 10
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steps while being withdrawn from the core. When the misalignment occurred,
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the SS correctly identified that Limiting Condition for Operation 3.1.3.5
(shutdown bank insertion limits) had been exceeded.
Because of this
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misalignment, Rod B-4 was at 218 steps when Shutdown Bank A was fully withdrawn at 228 steps. Technical Specification 3.1.3.5 requires "All
shutdown rods shall be limited in physical insertion as specified in the CORE
OPERATING LIMITS REPORT (COLR)." The COLR states, in Section 2.2.1, "The
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shutdown rods shall be fully withdrawn.
Fully withdrawn shall be the l
condition when shutdown rods are at a position within interval of 222 and j
231 steps withdrawn inclusive."
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Special Test Exception 3.10.3 suspended the insertion limits "during the
performance of PHYSICS TESTS." Even though the misalignment occurred during physics testing, it was not a planned part of the test.
The SS appropriately assessed the plant conditions and did not invoke Test STE 3.10.3.
He did meet-
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the action requirements of Technical Specification 3.1.3.5 because the insertion of Control Rod B-4 was beyond the limits of Technical Specification 3.1.3.5.
I The control rod was realigned using Procedure ABN-712, Revision 5, " Rod
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Control System Malfunction." The control rod swap test was repeated to
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determine if misalignment would recur.
Control Rod B-4 misaligned 4 steps.
i An ONE form was initiated in accordance with their corrective action program i
t to document the problem.
Procedure OPT-106B, Revision 0, " Control Rod Exercise," was performed to prove operability of Control Rod B-4 after each
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misalignment'and no binding was identified.
Control Rod B-4 was declared operable.
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Form 207 was initiated to improve _ the description of the realignment process j
in Procedure ABN-712 to better account for the variation in steps associated
with the digital rod position indication system. However, the operators _had a j
good understanding of the' systems involved and used the procedure as written
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to confirm the alignment of the control rod with the group,- reset the step
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counter based on the prior indication of the whole group, pull the ' group to
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demand Step 232 (one. greater than the limit of rod withdrawal) and reset steu counter to demand Step 231 (the limit of rod withdrawal).
Boron samples were taken as required to ensure consistent concentrations between the reactor coolant system and the pressurizer.
The team noted that
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test personnel were not consistent when responding to questions about the j
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source of information used to confirm the il degree / hour temperature change l
limit and to monitor the pressurizer level.
However, the operating staff
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controlled the reactor coolant system temperature within the required band at j
all time.s.
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The reactor operator and the lead test engineer communicated effectively
during the test.
As an aid, the operator marked the control rod group i
selector to indicate the test bank and the reference bank during each control
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rod swap.
This helped him to prevent manipulating an incorrect control rod i
bank.
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Overall, test personnel demonstrated a good understanding of the test results.
They were able to correctly evaluate the impact of anomalies as they occurred.
The operating staff was alert and carefully utilized all available indications l
j during performance of the test.
l 3.3.2.3 Train A Safeguards Actuation Test j
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On March 27 the team observed the performance of Procedure OPT-455B, Revision 1, " Train A Safeguards Slave Relay K614 Actuation," Procedure
Change 1, authorized by Work Order 5-93-502896-AA. A good prejob brief was
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conducted by the US, i
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Procedure OPT-455B, Step 6.4, stated, " Ensure Train A SSPS is in the Slave
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Relay Testing Lineup OR the Normal Lineup per SOP-711B." The normal lineup
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was described on Attachment 3 of Procedure SOP-711B, Revision 0, " Solid State i
i Protection System." The reactor operator used Attachment 3 and independently
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i confirmed that the normal lineup was in place, but he did not document the i
verification of each switch position. The team questioned the SS regarding
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the procedure use policy. He stated that a documented valve alignment and i
verification was performed after each switch manipulation.
For example, a j
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documented valve alignment and verification would be performed during a j
clearance installation or removal. What the team had been observing was a
third confirmation of the alignment which was not required to be documented j
for each switch.
Further, Step 9.2 stated. " Ensure Train A SSPS is in the-l
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appropriate lineup per SOP-7118 for current plant conditions, as directed by
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the shift supervisor." No action was necessary.since the prerequisite step
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l had established a normal lineup and the test did not affect the lineup. This
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was determined by the inspectors to be acceptable.
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3.3.2.4 Service Water System l
On March 27, the. team observed portions of the performance of
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Procedure OPT-207B, Revision 1, " Service Water System," Procedure Change
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p Notice 5.
The prejob.brief was conducted by the US, who as. signed test l
activities to various personnel. The A0 was assigned the task of closing the
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service water discharge valve on the component cooling water heat exchanger l
when instructed by the control room.
The US indicated that care should be l
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-17-exercised since vibration had previously occurred during valve manipulation.
The team monitored the manipulation of the valve.
Vibration was present but not excessive.
Work Order 5-93-503637-AA was written to ccatrol installation of associated test instrumentation.
The pro re in use was the correct revision and included all of the applicable ;
ure change notices.
The team questioned the A0 regarding the adequacy of communication with the control room.
The operator indicated he had no problems understanding the control room.
However, the job was delayed somewhat because both Unit 1 and Unit 2 shared the same radio channel.
It was necessary to wait for access to the radio channel during testing.
This was discussed with licensee management for their consideration.
3.3.2.5 Leak Rate Test On March 27 the team observed portior s of the performance of Procedure PPT-52-8023. Revision 0, " Appendix J Leak Rate Test of Penetration 2-MIV-000(b) (2-HV-4168, 2-H-4169, 2-HV-4170, and 2-PS-0503),"
which was a premaintenance local leak rate test for Valve 2-HV-4170 and Relief Valve 2-PS-0503.
The local leak rate test was performed at 49.2 psig.
After the pressure stabilized, the leak rate peaked at about 30 standard cubic centimeters.
This was well below the administrative review limit of 518 standard cubic centimeters.
During a previous crew brief, the operators had discussed the lifting of H, Sample Return Relief Valve 2PS503, which was a containment penetration boundary valve.
During the brief, the operators stated that the penetration had not been declared inoperable.
The US stated that the leak was small (less than 100 milliliter per minute at full pressure) and, therefore, was not an operability problem.
The test resuits confirmed the operator's prior operability determination for the valve.
3.4 Conclusions The conduct of operational activities was well controlled.
Shift turnovers were professional anu well organized and propagated pertinent plant status and planned activities.
Command and control by the SS and US was very good.
Communications between the control room staff were good.
It was noted that communications between the operators were occasionally open-ended; he 'ver, communications with the A0s included consistent use of repeat back stotements.
Although communications improved at the end of the inspection, the teem believed that it was because of the NRC presence.
The team observed that the communications between the two units were appropriate.
The licensee demonstrated excellent control of locked components.
Clearance controls were also well implemented.
An observation was made that main control board keys used to manipulate control switches were not ef fectively c ont rol l ed.
This condition was corrected by the licensee during the course of this inspectio __
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P The operating staff demonstrated a good understanding of the Technical i
Specifications and did not irappropriately rely on special test exceptions.
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The cumulative effect of planned entries into action statements was appropriately considered, f
The A0s were found to be fully cognizant of their duties and conducted their
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activities in a professional manner; however, the means of assuring that they l
were making log entries from calibrated instruments was not well understood.
j The field support supervisors were effective in coordinating work activities
between the A0s and the control room staff.
i The team observed safety-and nonsafety-related work activities and noted that
these activities were performed in accordance with the work requirements.
i Startup and surveillance testing activities were well performed, Communications between the personnel responsible for implementing the testing activity were very good.
Startup test personnel were knowledgeable of the test requirements. The operations staff closely monitored plant parameters
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and appropriately responded to anomalies detected during testing.
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4 SAFETY ASSESSMENT / QUALITY VERIFICATION
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i 4.1 Overview i
The team reviewed selected activities which reflected on the licensee's self-l assessment capabilities. This included the threshold for identifying deficiencies, resolution of concerns, and the implementation of corrective t
actions.
In addition, the team reviewed the licensee's oversight l
organizations for their ability to critically evaluate facility programs and-l performance issues.
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4.2 Root Cause Analysis
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4.2.1 Proposed Program Enhancements
i The _ team discussed the licensee's proposed actions to enhance the root cause i
determination process.
The purpose of these enhancements will be to better
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provide for more effective corrective actions by directly involving the responsible line organization in the process. ONE forms would continue to be
evaluated by the work. control committee; however, the determination of root
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- causes will be the responsibility of the nuclear oversight department. _ The i
determination of the corrective action to'be taken will be performed by the
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line organization. Assignment of the corrective action and closure of the
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plant incident report were expected to remain consistent with the present program.
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4.2.2 Borg-Warner Pressure Seal Check Valve i
On March 8,1993, with the reactor in Mode 4 (prior to initial criticality),
i auxiliary feedwater swing check Valve 2-AF-106, failed a back flow test.
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It is located on the
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Unit 2 turbine-driven auxiliary feedwater pump discharge to Steam Generator 4.
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Its purpose is to permit forward flow to the steam generator while preventing l
backflow and inadvertent overheating of the upstream auxiliary feedwater
system piping.
The licensee was performing Procedure PPT-S2-8067. Revision 1, "TDAFWP Check l
Valve Reverse Flow Test," when the failure of the check valve to seat was r
noted. Work Order 1-93-041068-00 was initiated to inspect the valve internals l
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and rework or replace the internals as necessary.
The findings associated
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with the initial work activity are documented on ONE Form 93-678.
It was identified that the valve bonnet, which orients the swing arm and valve disc, had been rotated approximately 10 degrees, which prevented the check valve
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from properly seating.
This later finding is documented on ONE form
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The licensee had initiated Design Modification 92-028 to install internal
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spacers and an antirotation device on the Borg-Warner pressure seal check
valves. On October 17, 1992, the licensee installed the antirotation device
on Valve 2-AF-0106.
The modification consisted of an alignment block and key l
device, which was welded to the valve body and bonnet, respectively.
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intent of this device was to provide a permanent means of ensuring that the j
disc remained properly oriented to the seat, while reassembling the valve
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internals and bonnet. This design modification was implemented-by Work
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Order 1-92-023733-00.
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A review of the work history on Valve 2-AF-0106 determined that the valve had
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been worked and reassembled in September 1992. A blue check was performed on
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the valve during reassembly to verify the disc was properly aligned and a l
reverse flow test was successfully completed on September 29, 1992.
No i
i additional testing was performed on the valve until March 1993. The licensee
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I concluded that between September 29 and October 17, the valve bonnet had rotated approximately 10 degrees and that the alignment device had been installed with the misalignment present.
The licensee conducted a root cause analysis to ascertain how the bonnet
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became misaligned prior to. installation of the alignment device.
Three i
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possible scenarios were deduced; however, a definitive cause was not
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identified.
The possible causes were:
(1) unauthorized work was. performed on
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the valve; (2) authorized work was performed on the valve but the work package was improperly coded; and (3) operational conditions caused the valve to
rotate prior to the bonnet being hot torqued following the September 1992 work
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activity. Although the licensee was uncertain as to how the bonnet became
misaligned, it was determined that the f ailure to perform an alignment
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verification when the alignment block and key devices were installed was a
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contributing factor to the current problem.
j The team reviewed the design modification anti Work Order 1-92-023733-00.
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Page 5 of the work order instructions required that a biue ch k be performed-i when the valve was reassembled; however, no additional testing was required
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following the welding of the block and keys to the valve.
The team determined I
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that the failure to establish and implement adequate instructions to verify l
that the valve disc was properly aligned is a violation of 10 CFR 50, l
Appendix B, Criterion V, " Instructions, Procedures, and Drawings."
This
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criterion requires that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings.
This violation will not be cited because it was determined that the criteria established in paragraph Vll.B(2) of Appendix C
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to 10 CFR Part 2 were satisfied.
The condition was properly identified and evaluated using the ONE form process.
The valve was properly aligned and Procedure MSM-CO-8801, Revision 3. "Borg Warner Check Valve Maintenance," was
revised to require disc alignment verification.
These corrective actions were i
also deemed to be effective in preventing similar problems on Borg-Warner pressure seal check valves where the block and key alignment devices are not yet installed.
The inspectors determined that similar valves located in the
auxiliary feedwater, feedwater, and main steam systems have been verified to j
be properly aligned.
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i 4.3 ONE Form Committee
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The team members attended two ONE form committee meetings to assess the
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licensee's initial review of plant personnel concerns identified through the ONE form process.
It was noted that the ONE form committee provided an
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indepth and comprehensive assessment of each deficiency as identified on an
ONE form.
The committee was composed of individuals with diverse backgrounds
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and included an SS, licensing, engineering, and work control personnel.
i During the first meeting on March 25, 1993, the committee addressed ONE
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Form 93-773, which reported the identification of errors within the Plant Reliability - an Integrated System for Management (PR-ISM) system.
The PR-ISM
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system is a computer-based interactive data system used for numerous tasks.
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The identified errors were specific to the voltage level tree (VLT) system.
l This system is a portion of the master equipment list and it fune.tions to allow a user to quickly identify electrical sources and loads for a specified
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component or piece of equipment.
The meeting attendees agreed-that the VLT system was not used for safety-related work and the assignment of the ONE form j
to design engineering would initiate. the -corrective action to resolve the
noted errors.
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The team reviewed the ONE form committee's assessment and followup actions to assure that the licensee's procedures would not allow an invalidated system.to s
be used in the performance of safety-related activities.
The following i
documents were reviewed:
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l PR-ISM Manual, Chapter 17, " Voltage Level Tree Users Manual,"
Version 2.1 l
Procedure STA-309, " Master Equipment List," Revision 4
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Procedure STA-605, " Clearance and Safety Tagging," Revision 11
t Procedure 0WI-110. " Operations Department Work Control and Clearance
Guideline," Revision 2 l
The team noted that these documents did not preclude the use of the VLTs for f
safety-related activities.
It was noted that the VLT user's manual provided
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an example of using the VLT system to develop a clearance for a motor-driven-
auxiliary feedwater pump.
The team discussed with licensee management that i
the VLTs could be used in safety-related work activities for clearances.
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was subsequently learned that the licensee had initiated a shift order stating that the VLT portion of the PR-ISM was not to be used for safety-related activities.
The team did not identify any instance where the VLTs had been
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used in the performance of a safety-related activity.
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i 4.4 SORC
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The team attended the SORC meeting held on March 26, 1993.
The areas reviewed
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included draft Licensee Event Report 445/93-03, " Actuation of Unit.1 Train A
Solid State Safeguards Sequencer," Temporary Modification 93-2-06, and the licensee's 5 percent self assessment.
The team noted that the SORC members were fully cognizant of the issues being l
presented and questioned the presenters on potential safety issues which did not appear to have been completely addressed.
In reviewing the plant incident-l report associated with the licensee event report, the 50RC members held lengthy discussions on what programmatic enhancements should be considered for installing test equipment.
The same indepth discussions were held for the
reactor vessel. vent valve temporary modification.
The team noted that the l
SORC had appropriately considered the plant performance indicators and each j
departments assessment which made up the 5 percent self assessment review.
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4.5 Nuclear Oversight Department Integrated Activities
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t The nuclear oversight department had implemented a regularly scheduled meeting I
between the oversight organizations.
Each organization within the oversight
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department was represented.
The organizations included plant analysis,
.i quality assurance, quality control, and the independent safety engineering f
group (ISEG).
The purpose of this meeting was to provide a forum for
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reviewing potential issues identified by the oversight organizations.
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The team noted that the meetings were well conducted and the discussions were
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Two areas were identified where additional oversight activity was expected based on the discussions.
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il 4.6 Licensee 5 Percent Power Self-Assessment l
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The team reviewed the licensee's 5 percent power readiness self-assessment in preparation for a full power license. The purpose of this assessment was to assure that Unit 2 was ready for full-power operation and that power ascension and dual unit operation would be conducted safely.
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The self-assessment was performed by the each line function department, such as operations, maintenance and engineering, work control, and quality control.
The ISEG organization also conducted an overview assessment of each of the
line organizations.
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Overall, the team concluded that the licensee had performed a comprehensive I
sel f-as ses sment.
It was found to include reviews of ONE forms, technical
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evaluations, and work requests.
The Plant Performance Overview Report results
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were effectively incorporated into the self-assessment. One issue was identified by the ISEG during their overview assessment.
This involved the.
adequacy of a technical evaluation for not having cleaned each motor control center prior to licensing. The engineering organization enhanced the basis
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for delaying the cleaning activity which was found to be acceptable by the i
ISEG.
The results of the self-assessment were subsequently reviewed and j
accepted by SORC.
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4.7 Unit 1 Licensee Event Report Review The team reviewed seven Unit I licensee event reports which identified plant deficiencies which where also applicable to Unit 2.
It was found that the i
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corrective action implemented for Unit I had also been implemented for Unit 2.
l These actions were completed prior Unit 2 receiving a low power license.
4.8 Conclusions i
The licensee had implemented an effective self-assessment capability as i
demonstrated by the deficiencies identified through the ONE form process. The licensee has proposed root cause analysis program enhancements to better
- establish -accountability at the line organization level.
The root cause j
determination performed for the misaligned Borg-Warner pressure seal check i
valve was appropriate.
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The reviews conducted by the ONE form committee and the-SORC demonstrated an
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excellent awareness for conditions which could adversely affect plant ' safety.
Prompt attention was provided to a concern involving the potential use of a nonvalidated data base for safety-related activities. The expected safety perspective was demonstrated by both committees.
t The licensee's 5 percent power self-assessment was well performed.
Conditions'
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assessment activity, was well conducted.
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r 5 FOLLOWUP
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5.1 Contract Auxiliary Operator Training i
Deficiency 446/92201-01 was identified in NRC Inspection Report 50-446/92-201-
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with regard to the failure of contract A0s to meet training requirements.
The deficiency noted that the licensee had transferred contract operators to
the operations department'for Unit 2 to perform valve lineups and implement clearances, but a review of training records determined that experience and
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educational levels had not been verified.
Additionally, there were deficient conditions related to qualification criteria, training record maintenance, l
incomplete qualification cards, training waivers, and unqualified instructors.
The license was not in compliance with Final Safety Analysis Report Sections 13.1.3.1 and 13.2.1.2(4).
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t The licensee submitted an ONE form to address the identified deficiency. The j
licensee's immediate response was to suspend all use of contract A0s. The t
following additional items were initiated by a memo from the Unit 2 shift i
operations manager to the manager of Comanche Peak Steam Electric Station operations:
i A review of all clearances placed or cleared between December 21, 1992.
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and January 21, 1993, was performed.
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A review was performed to determine which safety-related system lineups
had been performed at least partially by the contract operators during j
that same period.
l The clearances and lineups identified above were verified by qualified
TU Electric operators.
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A standing order was issued prohibiting the use of contract operators in-
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safety-related activities.
A separate memo from the Unit 2 manager of shift operations, dated March 9, j
1993, stated that the use of contract operators had not occurred since
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January 21, 1993, and there were no plans to use contract operators.
In later l
memos, contract operator-personnel were authorized to install operator aids, i
perform label verification, and perform research for clearances which were
required to be reviewed by a licensed operator. The team concluded that the
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licensee had taken appropriate corrective actions to correct this deficiency.
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ATTACHMENT 1 PERSONS CONTACTED 1.1 TU Electric L. G. Barnes, Manager, Training T. D. Baughman, Assistant to Site Licensing Manager G. Bell, Supervisor, Emergency Planning 0. Bhatty, Site Licensing R. D. Bird, Jr., Manager, Work Control Center M. R. Blevins, Director of Nuclear Overview D. M. Bozeman, Manager, Chemistry and Environmental R. C. Byrd, Manager, Quality Control W. J. Cahill, Group Vice President, Nuclear Engineering and Operations C. Cotton, Assistant to Vice President, Nuclear Operations M. Deen, Shift Supervisor J. W. Donahue, Manager, Operations S. L. Ellis, Manager, Power Ascension R. Flores, Manager, Shift Operations W. G. Guldemond, Manager, Independent Safety Engineering Group B. A. Hartman, Auditor, Quality Assurance T. A. Mope, Manager, Site Licensing J. J. Kelley, Vice President, Nuclear Operations J. J. LaMarca, Manager, Engineering Outage B. T. Lancaster, Manager, Plant Support M. L. Lucas, Manager, Instrumentation and Control T. C. Lutkellaus, Work Control Center F. W. Madden, Manager, Mechanical Engineering T. Marsh, Shift Supervisor T. Mewhinney, Maintenance Supervisor D. R. Moore, Manager, Maintenance J. W. Muffett, Manager of Technical Support & Design Engineering M. D. Palmer, Manager, Event Analysis D. J. Reimer, Manager, System Engineering G. Stein, Manager, Mechanical Maintenance S. Smith, Manager, Work Control Center W. Taylor, Executive Vice President C. L. Terry, Vice President Nuclear Engineering and Support C. Wells, Operations G. Westhoof, Assistant to Quality Assurance Manager R. G. Withrow, Supervisor, Performance and Test 1.2 NRC D. N. Graves, Senior Resident Inspector G. E. Werner, Resident Inspector L. Yandell, Chief, Projects Section B The personnel listed above attended the exit meeting.
In addition to the personnel listed above, the inspectors contacted other personnel during this inspection perio.
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2 EXIT MEETING i
An exit meeting was conducted on March 29, 1993.
During this meeting, the
team reviewed the scope and findings of the report.
The licensee did not
identify as proprietary any information provided to, or reviewed by, the team.
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