ML20057D453
| ML20057D453 | |
| Person / Time | |
|---|---|
| Site: | Waterford  |
| Issue date: | 09/09/1993 |
| From: | Westerman T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20057D442 | List: |
| References | |
| 50-382-93-25, NUDOCS 9310040236 | |
| Download: ML20057D453 (18) | |
See also: IR 05000382/1993025
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APPENDIX d
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U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
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Inspection Report: 50-382/93-25
Operating License: NPF-38
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Licensee:
Entergy Operations, Inc.
Operations, Waterford
P.O. Box B
Killona, Louisiana
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Facility Name: Waterford Steam Electric Station, Unit 3
Inspection At: Waterford Steam Electric Station, Unit 3, Taft, Louisiana
Inspection Conducted: July 26-30 and August 26, 1993
Inspectors:
C. J. Paulk, Reactor Inspector, Engineering Section
Division of Reactor Safety
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R. B. Vickrey, Reactor Inspector, Engineering Section
Division of Reactor Safety
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P. A. Goldberg, Reactor Inspector, Engineering Section
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Division of Reactor Safety
Approved:
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F T. F. Westerman, Chief, Engineering Section Date
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Division of Reactor Safety
Inspection Summary
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Areas Inspected:
Special, unannounced inspectior, of activities within the
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engineering organizations and followup on previously identified items.
Results:
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The inspectors found that the licensee, in general, has been performing
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engineering activities in accordance with plant procedures. The
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inspectors did find that a nonsafety-related instrument setpoint was
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changed without documentation of an engineering evaluation, and that
actions recommended in a Problem Evaluation / Identification Request
report were not completed.
The licensee committed to performing a review of. condition
identifications to determine if any were closed without ensuring that
related design documents had been revised as necessary (Section 3.3).
9310040236 930928
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ADOCK 050003B2 B:
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The licensee was implementing a design change to provide a method of
evaluating the corrosion rate inside the component cooling water heat
exchangers (Section 3.13).
A violation, previously identified as an unresolved item, was identified
for the failure to implement procedures for the identification of the
pressurizer code safety valves and the main steam safety valves
setpoints exceeding tolerances allowed by the Technical Specifications
(Secticn 2.2).
Summary of Inspection Findings:
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Inspection followup Item 382/9314-01 was closed (Section 2.1).
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Unresolved Item 382/9314-04 was closed (Section 2.2).
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Violation 382/9325-01 was opened (Section 2.2).
Inspection Followup Item 382/9325-02 was opened (Section 3.3).
Inspection Followup Item 382/9325-03 was opened (Section 3.13).
Inspection Followup Item 382/9325-04 was opened (Section 3.17).
Attachment:
Attachment - Persons Contacted and Exit Meeting
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DETAILS
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1 PLANT STATUS
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During this inspection, the plant was operating at 100 percent power.
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2 FOLLOWUP (92701)
2.1
(Closed) Inspection Followup Item 382/9314-01:
Identification of ASME
Code Boundaries
This item concerned a modification which cut and capped a number of drain
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lines in the high and low pressure safety injection systems.
Each drain line
had a drain valve associated with it that was the piping safety class break
from ASME Class 2 or 3 to non-safety class piping. All of the pipe cuts were
to be performed on the downstream side of the seismic anchor with the-
exception of two lines which required modifications to the non-safety seismic
portion of the piping. The licensee had indicated that some of the drain
valves were leaking and would not be repaired before they were capped. Due to
the fact-that some of the valves were leaking and would be cut and capped
prior to the valves being repaired, the inspectors questioned whether the ASME
pressure boundary should be moved from the valve to the capped end and
modifications and repairs should come under the jurisdiction of the ASME
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Section XI Code.
-During NRC review of the followup item, the licensee stated that if leakage _ of
the. drain valve was discovered during implementation of' the modification the
valve would be repaired to ensure the integrity of the ASME code boundary.
The NRC staff position was that the valve was the code boundary and the cap
was a modification on the non-code section of the piping. The licensee stated
that the valves would be maintained in accordance with the commitments to the
ASME code requirements.
2.2
(Closed) Unresolved Item 382/9314-04:
Failure to Identify and Evaluate
Safety Valve Setpoint Outside of Technical Specification Limits
This item concerned the failure to initiate corrective actions to, evaluate
as-found set pressures of pressurizer and main steam safety valves, which
exceeded the il percent tolerance allowed by the ASME Section III Code and
Technical Specifications.
The inspectors reviewed Procedure UNT-005-002, " Administrative Procedure
Condition Identification," Revision 10, which provided the method for
identifying and resolving hardware conditions adverse to quality. The
procedure defined conditions adverse to quality as conditions affecting
quality-related activities, which included failures, deficiencies, and
deviations.
In accordance with this procedure, conditions adverse to quality
shall be processed by preparing a nonconformance condition identification in
accordance with Section 5.3.1.2 of Procedure UNT-005-002.
Criterion V of
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Appendix B to 10 CFR Part 50 requires that activities affecting quality shall
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be prescribed by documented procedures and shall be accomplished in accordance
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with these procedures.
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The licensee's failure to initiate nonconforming condition identifications for
the out-of-tolerance as-found set pressures is identified as Violation
382/9325-01.
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3 ENGINEERING AND TECHNICAL SUPPORT (37700)
The purpose of this inspection was to evaluate certain activities in the
design engineering department.
3.1 Mounting of Safety-Related Transmitters
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The inspectors evaluated the adequacy of the seismic qualification of
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safety-related transmitters which had been mounted with an incorrect grade of
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bolting and with missing bolts.
The inspectors reviewed Report PRE-90-063, initiated October 31, 1990, which
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stated, that while installing a Barton transmitter, the licensee found that
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the bolts did not meet the technical manual requirements since they were not
the material grade recommended. The bolts sheared before they could be
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torqued to the recommended 27.1 N-m (20 lbf-ft).
The licensee initiated NCI
271797 to document this nonconformance. A walkdown of the 26 accessible
transmitters had been performed by the licensee. The licensee determined that
incorrect bolt material had been used.
The inspectors reviewed this NCI,
along with Work Authorization 01068976. The inspectors found that the
NCI/ work authorization installed the correct bolts in the Barton transmitters .
located in containment.
The inspectors also noted that the bolts were torqued
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to 27.1 N-m (20 lbf-ft) with quality assurance witness required.
Prior to
issuing the work authorization, the licensee had a computer printout generated
which identified all of the Barton pressure transmitters. The remaining
Barton transmitters had the bolts replaced and tcrqued under Condition
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Identifications (CIs) 271156, 271707, and 271793.
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The inspectors also reviewed Calculation EC-M90-065, " Evaluation of the
Mounting Details for the Barton Model 764 Differential Pressure Transmitters
located in the Reactor Building," Revision 0.
The purpose of the calculation
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was to evaluate the structural integrity of the mounting of the transmitters
using the incorrect bolting material.
The calculation demonstrated that the
existing bolting was adequate for seismically mounting the safety-related
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transmitters.
The inspectors concluded that the licensee had adequately-
addressed the problem.
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A review of licensee documentation did not give any indication that bolting
had been found missing from the safety-related transmitters.
In addition, the
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inspectors checked with the former senior resident-inspector at the Waterford
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Steam Electric Station, Unit 3, during this time frame regarding his knowledge
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of any missing bolts. He was not aware of any cases of missing bolts on
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safety-related transmitters. Additionally, the inspectors reviewed NRC
Inspection Report 50-382/90-18 which also addressed the issue of the bolting
material discrepancy.
The inspectors concluded that the licensee had properly addressed the
incorrect bolting material issue and did not find any evidence that
safety-related transmitters had been found with missing bolts.
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3.2 Replacement of Valve Positioners
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The inspectors reviewed licensee documentation to determine if valve
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positioners had been replaced by drawing revision '10tices (DRNs).
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inspectors reviewed DRN 191-01491, which-was issued.against Drawing 5617-6550.
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The inspectors found that DRN 191-01491 was initiated on May 8, 1991, to
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revise the drawing to indicate the part number for a new positioner assembly.
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The new assembly was selected because the original positioner was obsolete.
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The licensee had performed an evaluation of the acceptability of the new
positioner in Spare Parts Equivalency Evaluation Report 91-660, which was
initiated on May 7, 1991.
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The licensee approved the replacement part on May 10, 1991. The DRN was not
approved until June 17, 1991. The inspectors noted that the licensee had
worked these documents in parallel; however, they did not make any changes
until approval was granted. The DRN was closed on August 21, 1991, after the
changes were made to the drawings.
The inspectors found that Procedure UNT-007-021, " Spare Parts Equivalency
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Evaluation Report / Parts Quality Level Determination," Revision 7, which was in
effect at the time DRN 191-01491 was initiated, allowed for. this sequence of
events.
The inspectors concluded that the licensee's actions were in accordance with
approved procedures in effect at the time.
3.3 Plant Modifications and Drawino Changes
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The inspectors reviewed' design engineering activities to determine if the
licensee had performed plant modifications with DRNs and work authorizations
instead of design change packages. The inspectors also evaluated the
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licensee's configuration control. The inspectors reviewed DRN I-9002977,
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C1 255672, CI 258712, Temporary Alteration Request (TAR)90-003, CI 272200,
DRN 190-03352, CI 267628, CI 267230, EC-M90-071, CI 267015, and EC-M89-074.
The inspectors reviewed Procedure PE-2-005, " Administrative Procedure
Engineering Work Authorization Processing," Revision 9, August 2, 1988, which
provided guidelines for processing work authorizations.
This procedure
allowed the use of work authorizations to perform a design change. The
inspectors reviewed DRN 190-02977, which added an air regulator and tubing to
a drawing to reflect the as-built condition. The inspectors found that the
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air regulator had been previously deleted from the drawing in error and this
DRN added it back onto the drawing. CI 255672 modified the incore nuclear
instrumentation system by plugging one of the incore nuclear instrumentation
thimble tubes that had a broken coupling. This modification was initiated in
May 1988. However, CI 255672 failed to correct drawings and documents which
were affected by the design change.
CI 258712 was initiated in February 1989
to revise the drawings and documents that were affected by CI 255672.
Since
CI 255672 had failed to update the necessary documents for the design change,
Mr. J. Hologa, Acting Diractor of Design Engineering, committed to sample the
design changes performed under CI/ work authorizations during that time frame
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to determine if there were any other design changes where there may have been
a failure to revise affected documents. The review of the licensees sample
and results was identified as Inspection Followup Item 382/9325-02.
The inspectors reviewed TAR 90-003, May 5, 1991, which installed pressure caps
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on the guide tubes of the movable incores.
A safety eva;oation was performed
for the temporary modification.
TAR 90-003 was closed out by Design
Change 3303, Revision 1.
The inspectors considered that the temporary
modification had been properly performed.
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CI 272200, November 27, 1990, revised a drawing to reflect as-built
conditions. This CI also added a note to the tubing drawing which stated that
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EC-90-071 justified the overspan condition for the tubirg.
The inspectors
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reviewed the calculation and determined that the tubing was acceptable for the
overspan condition.
DRN 190-03352 was part of CI 272200 and revised the
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tubing drawing.
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C1 267628 addressed a tubing overspan condition. The disposition of this CI
was that no work was to be performed since Design Change 3195 had replaced the
air-operated valves with motor-operated valves and the tubing was deleted with
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the modification. The inspectors considered the design change to properly
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address the CI.
CI 767230, December 6,1989, concerned a valve which had three unqualified
supports due to insufficient construction documentation.
Report PRE-89-136
was prepared which declared the valve operable without the supports.
Calculation EC-90-044 qualified the supports as Seismic I.
The calculation
was dated August 14, 1990, and the CI was closed August 21, 1990. The
inspectors considered that the unqualified supports had been properly
addressed.
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Nonconforming CI 267015 concerning overspan conditions was reviewed by the
inspectors.
The overspan conditions were qualified by Calculation EC-M89-074,
which was also reviewed by the inspectors and found acceptable.
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The inspectors concluded that the licensee implemented DRNs and work
authorization in accordance with approved plant procedures. The inspectors
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also concluded that the licensee's configuration control was in accordance -
with plant procedures.
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3.4 Calibration of Instruments in Heated Cabinets
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The inspectors reviewed the licensee's practice of calibrating instruments
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(transmitters) in heated instrument cabinets. The inspectors also reviewed
the operation of the heaters and blowers in the cabinets.
The inspectors found Problem Evaluation /Information Request (PEIR) 71193,.
dated. April 30, 1990, had been initiated to address the setpoints for the high
and low temperature alarms for the instrument cabinets. The inspectors did
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not identify any evidence of evaluations being performed until February 22,
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1992. The licensee received a letter from its contractor that stated there
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was sufficient conservatism in the setpoints to offset the effects of the
temperature differences. The licensee issued'an inter-office memorandum on
April 1,1992, regarding instrumentation calibration temperatures. This
memorandum addressed the inclusion of conservatism in the setpoint
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calculations for temperature effects.
It also established the lowest
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calibration temperature limit for calibrating instruments in the . reactor
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building, the reactor auxiliary building, the turbine building, the control
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room, the fuel handling building, and outdoors.
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The inspectors also found that the cabinets had heaters and blowers that both
energized when the cabinet temperature dropped below the temperature setpoint
range for the cabinet. These worked on a thermostat; and were energized only
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when the temperature dropped below the setpoint of the thermostat.
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licensee had controls in place in the calibration procedures to keep the
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cabinet doors closed as long as possible to minimize the change of temperature
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within the cabinets.
The temperature effect with the cabinet door open was
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considered by the licensee to be minimal.
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The licensee closed PEIR 71193 on September 9, 1992.
The recommended actions
were to eliminate the temperature alarms, the cabinet heaters and blowers, and-
associated controls, which were not required for normal operations, for
cabinets located in the reactor building and the reactor auxiliary building.
This recommendations had not been implemented but the inspectors were informed
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that a work authorization was being drafted. Additionally, the PEIR informed
maintenance personnel of the importance of performing the calibrations in
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accordance with the temperature limits established in the April 1992 inter-
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office memorandum, which accounted for the difference between operating.
temperatures and the lowest acceptable calibration temperatures. The licensee
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had initiated a task in accordance with Procedure UNT-005-012, " Repetitive
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Task Identification," Revision 2.
This task documented ambient temperature in
containment during the current refuel cycle for planning review to ensure
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calibration .within the temperature limits of the April 1992 letter. The
inspectors verified that this task was documenting containment temperatures at
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four locations on at least a daily frequency.
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The inspectors concluded that the licensee was addressing the issue of
temperat'are effects on instrument calibrations.
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3.5 Maintenance of Solenoid-Operated Valves
The. inspectors reviewed the replacement of age-sensitive materials in
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solenoid-operated valves. The inspectors evaluated the licensee's maintenance
program to determine if the replacement of the age-sensitive materials on a
pe.90dic basis was properly addressed.
The inspectors reviewed the licensee's procedures for maintenance of valves
manufactured by Target Rock, ASCO, and Valcor. The procedures were:
ME-007-009, " Maintenance Procedure Target Rock Solenoid-Operated Valves,"
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Revision 5; ME-007-019, " Maintenance Procedure ASCO Solenoid Valve,"
Revision 4; and, ME-007-020, " Maintenance Procedure Valcor Solenoid-Operated
Valves," Revision 4.
The inspectors also reviewed the licensee's programs for
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preventive maintenance and environmental qualification as they related to
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solenoid-operated valves.
The inspectors concluded that the procedures, along with the preventive
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maintenance program and the environmental qualification program, would ensure
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the age-sensitive materials were replaced as required.
3.6 Overpressurization of Solenoid-Operated Valves
The inspectors reviewed the licensee's actions to determine if the effects of
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overpressurization of solenoid-operated valves were evaluated. The inspectors
reviewed the licensee's response to NUREG 1275, " Operating Experience Feedback
Report Solenoid-0perated Valve Problems," as it related to the
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overpressurization issue. The licensee identified 44 solenoid-operated air
valves in the instrument air system. Of the 44, 36 were safety-related with
maximum operating pressure differential limits less than 827.4 kPa (120 psig),
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the maximum credible pressure for the air system. The inspectors found that
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the licensee recommended raplacing the solenoid-operated valves with maximum
operating pressure different.ial rating less than 827.4 kPa (120 psig);
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establishing unique identification numbers for the solenoid-operated valve
regulators and controlling the setpoints for the regulators; performing an
evaluation to determine which solenoid-operated valve applications did not
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need regulators; and evaluating the suitability of the pressure switches on
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the accumulators. The licensee had scheduled the completion of the
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recommended actions by the end of Refueling Outage 6.
The inspectors concluded that the licensee was addressing the issue of-
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essurization of solenoid-operated valves in a controlled manner as
information was obtained, and developed a comprehensive approach to the issue.
3.7 Calibration of Safety-Related Pressure Switches
The inspectors reviewed documentation to determine if two safety-related
pressure switches were calibrated with revised setpoint values. The
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inspectors questioned whether or not the pressure ' switches on the accumulators
for two containment vacuum release valves, CVR-101 and CVR 201, were reset to
values in accordance with Setpoint Change 91-011.
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The inspectors reviewed the calibration history of the pressure switches on
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Valves CVR-101 and CVR-201 (CVRIPS5222A and CVRIPS52228, respectively). The
inspectors found that the pressure switch set points were not set.in 1991
prior to the restart from a refueling outage. The licensee did issue,
however, Standing Order 91-09 to provide special instructions, as interim
action, to the operators for those times when the instrument air header
pressure dropped below 586.1 kPa (85 psig) until the switches could be
calibrated. The pressure switches were calibrated in February 1992 with the
revised setpoints and the standing order was cancelled.
The inspectors concluded that the licensee made a conscious decision to defer -
the calibration of these two switches, which were part of several instruments
that required recalibrations, until the next outage of sufficient time. The
licensee placed administrative controls in force to account for abnormal
operating conditions.
3.8 Class Breaks in Instrument Air Lines
The inspectors reviewed drawings to determine if class breaks were identified
on the B430 V drawings. The inspectors found that the licensee had
identified, as early as January 25, 1989, that class breaks were not always
identified on the drawings. The licensee initiated Work Authorization 261147
on January 25, 1989, for the inspection of instrument tubing that appeared to
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be non-safety-related. Also, CI 261147 was initiated on January 25, 1989, for
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engineering to evaluate the questhnable tubing. On May 10, 1989, PEIR 61167
was initiated to address the class breaks not being identified on the B430 V
drawings.
The issue was also identified in PEIR 71149 dated August 24, 1989.
The licensee closed PEIR 61167 by reference to PEIR 71149 on August 24, 1989.
As part of the actions taken under the work authorizacion, the licensee
performed inspections of the questionable tubing and determined that the issue
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was larger than first anticipated. The scope was expanded to address all air-
operated valves listed in the Final Safety Analysis Report Table 3.9-9.
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result of the expanded scope, 20 nonconformance identification documents were
initiated.
The inspectors found that the design criteria for the air supplies to non-
safety-related valves, or to safety-related valves whose failure to the " safe"
position was acceptable post-accident, was to have the tubing be totally non
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safety.
For those valve: that were required to stroke or modulate
post-accident, air or nitrogen accumulator systems were designed as Seismic
Category I.
Additionally, stainless steel tubing was to be run from the
isolation (check) valve upstream of the accumulator, to the actuator
component (s) requiring an air supply. This tubing was to be ASME material and
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installed in accordance with a Seismic Clnss I design.
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The inspectors reviewed the calibration history of the pressure switches on
Valves CVR-101 and CVR-201 (CVRIPS5222A and CVRIPS5222B, respectively). The-
inspectors found that the pressure switches were not calibrated in 1991 prior
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to the restart from a refueling outage.
The licensee did issue, however,
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Standing Order 91-09 to provide special instructions, as interim action, to
the operators for those times when the instrument air header pressure dropped
below 586.1 kPa (85 psig) until the switches could be calibrated.
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pressure switches were calibrated in February 1992 with the revised setpoints
and the standing order was cancelled.
The inspectors concluded that the licensee made a conscious decision to defer
the calibration of these two switches, which were part of several instruments
that required recalibrations, until the next outage of sufficient time. The
licensee placed administrative controls in force to account for abnormal
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operating conditions.
3.8 Class Breaks in Instrument Air Lines
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The inspectors reviewed drawings to determine if class breaks were identified
on the B430 V drawings. The inspectors found that the licensee had
identified, as early as January 25, 1989, that class breaks were not always
identified on the drawings.
The licensee initiated Work Authorization 261147
on January 25, 1989, for_the inspection of instrument tubing that appeared to
be non-safety-related.
Also, CI 261147 was initiated on January 25, 1989, for
engineering to evaluate the questionable tubing. On May 10, 1989, PEIR 61167
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was initiated to address the. class breaks not being identified on the B430 V
drawings. The issue was also identified in PEIR 71149 dated August 24, 1989.
The licensee closed PEIR 61167 by reference to PEIR 71149 on August 24, 1989.
As part of the actions taken under the-work authorization, the licensee
performed inspections of the questionable tubing and determined that the istue
was larger than first anticipated.
The scope was expanded to address all air-
operated valves listed in the Final Safety Analysis Report Table 3.9-9.
As a
result of the expanded scope, 20 nonconformance identification documents were
initiated.
The inspectors found that the design criteria for the air supplies to non-
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safety-related valves, or to safety-related valves whose failure-.to the " safe"
position was acceptable post-accident, was to have the tubing be totally non
safety.
For those valves that were required to stroke or modulate
post-accident, air or nitrogen accumulator systems were designed as Seismic
Category I.
Additionally, stainless steel tubing was to be run from the
isolation (check) valve upstream of the accumulator, to the actuator
component (s) requiring an air supply.
This tubing was to be ASME material and
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installed in accordance with a Seismic Class I design.
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The licensee closed CI 261147 on June 12, 1990, on the basis of the evaluation
of the inspection results and the engineering evaluation that determined the
classification of the various tubing. The licensee also commenced a long-term
corrective action to revise all of the B430 V drawings, as necessary, to show
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class breaks in accordance with plant' procedures.
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On September 28, 1990, PEIR 71149A was initiated to raise the issue again.
The licensee voided this PEIR on the basis that a program was in place to
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correct the drawings. Additionally, the program included assigning unique
identification numbers to all components that previously had none.
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.The inspectors concluded that the licensee was properly identifying and
addressing the issue of class breaks in instrument tubing.
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3.9 Scaffolding Inside Containment During Plant Operations
The inspectors reviewed Procedure NOCP-207, " Construction Procedure Erecting
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Scaffold," Revision 5. which established the system for evaluating, erecting,
maintaining, removing, and inspecting scaffolding.
The procedure stated that
if scaffolding is installed in containment during operation, system
engineering concurrence must be obtained. The procedure also required that an
evaluation of scaffold built above safety-related equipment not tagged
out-of-service be performed.
In addition, only previously approved
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scaffolding shall remain in containment during plant operation.
The inspectors asked the licensee if there had ever been erected scaffolding
inside containment when the plant was operating. The licensee stated that
scaffolding had been erected near one of the reactor coolant pumps and was
left in place during plant operation for inspection, rework, and surveillance
purposes in early 1991. The inspectors reviewed the evaluation for this
installation.
The evaluation, "2 over 1 evaluation for scaffold request 9061,
scaffolding for RCP 2A Boron Leak," dated October 11, 1990, had a
comprehensive 2 over l' evaluation performed.
The inspectors concluded that the licensee had followed their scaffolding
procedure when leaving scaffolding erected inside containment during this
period.
3.10 Plant Protection System Grounding
The inspectors reviewed drawings to determine if the grounding system for the
plant protection system or the process analog cabinets was annotated properly.
The licensee identified problems with the plant protection grounding system in
PEIR 60885, dated March 1, 1988.
The inspectors reviewed the PEIR and found it described the grounding problems
in great detail. The inspectors found the personnel in the Design Engineering
Organization to have been knowledgeable of the grounding systems. The
licensee developed Design Change 3301 to replace cables for resistance
temperature detector circuits.
Revision 1 was initiated to install isolation
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cards in the process analog cabinets. The licensee initiated Revision 2 to
properly install the shield leads for the instrument circuits. These changes
addressed the noise problems in the instrument circuits due to system ground
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differences.
The licensee stated that there had been approximately six other
design changes that could be associated with the instrument grounding system.
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The inspectors reviewed these changes and determined that they were not
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associated with the instrument grounding system. The inspectors reviewed two
other design changes that were associated with the instrument grounding
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system. The inspectors determined that these changes had been implemented in
accordance with plant procedures.
The inspectors reviewed the licensee's documents for grounding drawings for
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the plant protection system and the process analog instrument circuits. The
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inspectors found the specifications for the grounding systems in
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Specification 00000-ICE-3001, " General Engineering Specification for Plant
Protection System," Revision 3, and Specification 9270-ICE-3001, "Waterford 3
Engineering Specification for Plant Protection System," Revision 3.
The
inspectors also found that the grounding for the plant protection system was
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shown on Drawing 5817, " Plant Protection System Simplified Functional
Diagram," Sheets 8443, 8444, 8445, and 8447. The grounding for the process
analog system was provided in Vendor Manual 457000013, Volumes I and II,
" Westinghouse Process Controls 7300 System"; on Drawing B351, " Instrument
Ground Cabling Schematic," Sheets 14,15, and 16; and, on Drawing Series B425,
" Process Loop Diagrams."
The inspectors concluded that the licensee did have drawings to identify the
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grounding for the plant protection system and the process analog system.
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These drawings may not have been in one convenient location; however, they
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were available for use.
3.11
Control of Electrolytic Capacitors
The inspectors reviewed the licensee's program for the replacement and control
of electrolytic capacitors. This issue had been previously identified in NRC
Inspection Report 50-382/85-27.
The inspectors found that, on January 15, 1986, the licensee had initiated an
internal commitment (All593) to track the issue of electrolytic capacitor
repl acement.
The licensee initiated a program in September 1987 to address
the degradation of electrolytic capacitors both on the shelf and in use. The
NRC closed the item identified in 1985 in NRC Inspection Report 50-382/89-15
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and the licensee continued in its efforts to improve its program.
In October 1990, the licensee developed an action plan to identify all
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safety-related electrolytic capacitors in use, identify nonsafety-related
electrolytic capacitors in use and in the warehouse, and develop a program to
systematically replace all electrolytic capacitors in use before reaching the
end of the component service life.
In May 1993, the licensee re-evaluated
these initiatives and developed new initiatives which would place greater
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emphasis on the safety-related electrolytic capacitors.
These initiatives
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were to identify all components containing electrolytic capacitors that were
necessary to activate to safely shut down the reactor or to allow
post-accident monitoring systems to function; identify service and shelf life
for electrolytic capacitors in the components in-use and on the shelf;
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identify the age of electrolytic capacitors in plant systems and their
associated spares in the warehouse; develop a method to systematically replace
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electrolytic capacitors or components containing electrolytic capacitors
before the service or shelf life identified above was exceeded; and, expand
the replacement program to other components as warranted due to plant
reliability concerns.
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The inspectors reviewed Aoministrative Procedure UNT-005-017, " Control of
Electrolytic Components," Revision ]; and Maintenance Procedures ME-013-015,
" Battery Charger Capacitor Replacement," Revision 6; and ME-013-016, " Inverter
Capacitor Replacement," Revision 3.
The inspectors found that the procedures
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were well written and adequately addressed the replacement of electrolytic
capacitors for those components.
The inspectors concluded that the licensee had developed a program as early as
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1987 for the replacement of electrolytic capacitors and that the licensee has
continued to refine and improve its program.
3.12 Engineerina Evaluation of Setpoint Changes
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The inspectors reviewed documentation to determine if Setpoint Change
Document 88-02 was changed without performing an engineering evaluation. The
setpoint affected by this change was the lo-lo level alarm for the blowdown
tank that alerts the operator that the diverse circuitry to stop the blowdown
pumps had failed.
This is a nonsafety-related circuit.
The inspectors reviewed the change document and found that no engineering
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evaluation had been documented in Setpoint Change Document 88-02.
The
inspectors found that the engineer claimed to have performed the evaluation,
but did not document the evaluation.
The licensee did document an evaluation
as part of its setpoint and loop uncertainty calculations in 1992
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(Calculation EC-192-029) that the inspectors found to support the value
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selected in Setpoint Change Document 88-02.
The licensee's setpoint and loop uncertainty calculation program was reviewed
in 1989 and documented in NRC Inspection Report 50-382/89-39. The inspectors
concluded, in that report, the program should produce accurate and auditable
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calculations. The licensee has refined and increased the scope of the initial
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effort and was upgrading the program even further.
The inspectors concluded that the licensee had a program for addressing
instrument calculations and was upgrading their calculations based on safety
significance.
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3.13 Component Cooling Water Heat Exchanger Corrosion
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The inspectors reviewed the acceptability of the component cooling water heat
exchanger due to corrosion of the carbon steel internal supports and the
existence of chemical water treatment prior to 1984.
The inspectors reviewed Request SMR-007, " Corrosion Rate Monitoring of CCW
[ Component Cooling Water] Heat Exchangers," Revision 0, dated March 27, 1990,
which recommended a corrosion rate monitoring system for the component cooling
water heat exchangers to determine the effectiveness of the chemical
treatment. The station modification request recommended that a coupon rack
should be installed inside the heat exchanger, which would be removed
periodically to analyze for corrosion rate. Attachment 3 to the station
modification request stated that a fiber optic video tape inspection of the
A train heat exchanger shell side had been performed during Refueling
Outage 3.
The results of the fiber optic inspection, although limited and
inconclusive, indicated that there was some corrosion on the carbon steel
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surfaces and some indication of microbiological induced corrosion, which did
not appear to be active.
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The inspectors also reviewed Design Change 3311, " Corrosion Rate Monitoring of
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CCW and ACCW [ Auxiliary Component Cooling Water) Heat Exchangers A & B,"
Revision 1, dated April 9, 1993. This design change added corrosion
monitoring equipment to the ACCW and CCW systems. A corrosion test loop with
a coupon rack and corrater (sic) connection was added in each heat exchanger
room to monitor the corrosion on the shell side of the heat exchanger.
Additionally, the modification installed a corrosion test loop with a coupon
rack and corrater (sic) connection to the CCW system non-essential sample and
cleanup loop. The licensee indicated that the modification was not fully
installed, but should be in approximately 1 month. The licensee indicated
that the toapons would be examined about every 3 months and the corrosion rate
would be trended by the chemistry department.
Examination of coupons,
however, was not proceduralized at the time of the inspection.
During Refueling Outage 4, on April 5, 1991, ultrasonic thickness measurements
were taken of both CCW heat exchanger shells to determine if corrosion had
reduced the wall thickness below the minimum allowable. The heat exchanger
shells are made of carbon steel.
The inspectors reviewed the ultrasonic wall
thickness reports for the two heat exchangers and noted that the minimum wall
measured was greater than the minimum allowable. The wall thickness
measurements were performed in accordance with Work Authorizations 01074080
and 01074108.
On February 18, 1992, the licensee performed an acoustic inspection along the
length of each heat exchanger to determine baseline vibrations. The licensee
stated that the inspection would be performed again to determine if there was
any degradation from the previous inspection since corrosion could cause a
change in.the vibration measurement. The acoustic inspection was not
proceduralized.
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The inspectors reviewed CCW heat exchanger c % ;al water treatment control
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and noted that the licensee had performed a . lash and hydrostatic test of the
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system in 1982.
The water used in this process was stated to have been
treated with hydrazine.
The licensee stated that, prior to 1984, the
chemistry department's technical procedures controlled the hydrazine
concentration in the system.
Since 1984, the CCW heat exchangers at the
Waterford Steam Electric Station, Unit 3, have been treated by products
manufactured by Calgon Corporation. This was documented in Attachment 3 to
Request SMR-007. The inspectors reviewed Procedure CE-2-003, " Maintaining Wet
Cooling Tower Chemistry," Revision 0, February 7, 1983, which provided
instructions for maintaining chemistry control in the ACCW system wet cooling
towers.
The inspectors concluded that there had been chemistry controls prior to 1984,
when the system was declared operational. The inspector.s also considered the
results of the Refueling Outage 3 fiber optic inspection of the CCW Heat
Exchanger A Shell Side to have been limited and inconclusive. The evaluation
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of the results of the corrosion monitoring program was identified as an
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inspection followup item (382/9325-01).
3.14 Safety Evaluations Performed for Drawing Revision
The inspectors chose 17 DRNs prepared during the 1990 and 1991 timeframe and
reviewed them to determine if safety evaluations had been performed. The DRNs
reviewed were 190-01628, 190-01769, 190-02550, 190-02571, 190-02601,
190-02566, 191-00099, 191-00167, 191-00168, 191-00169, 191-00613, 191-00614,
191-00808, 191-00809, 191-00810, 191-00811, and 191-00812.
Each-DRN reviewed
had the nuclear safety review block checked either for " Prepared for
Initiating Document" or "Not Required." Most of the DRNs had the safety
review block checked for prepared for initiating document.
The inspectors
reviewed the initiating documents which were Design Changes 3299, Revision 0;
3195, Revision 1; and 3309, Revision 0.
Each design change had a safety
evaluation screening or a safety evaluation attached to it and each design
change had the applicable DRNs listed.
The inspectors concluded that the DRNs did not require an additional specific
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safety evaluationK since some had been prepared for the initiating document in
accordance with plant procedures.
3.15 Design Change Calculation impact on Technical Specifications
The inspectors reviewed a calculation performed for Design Change 3098, "CVAS
[ Control Ventilation Air System] Modulating Make Up Dampers." The inspectors
reviewed Calculation EC-190-004, " Loop Error Calculation for CVAS and FHB
[ Fuel Handling Building) Negative Pressure Control Systems," Revision 0.
The
inspectors did not identify anything in the calculation that would have caused
the Technical Specification limits to have been exceeded.
The inspectors
noted that the calculation had been performed, reviewed, and approved in
accordance with the licensee's procedures.
Additionally, the inspectors found
that the design change had been voided and never implemented.
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3.16 Desian Chance Review
The inspectors reviewed Design Change 3295, " Steam Generator No. 2 Blowdown
System," including reviews performed by plant engineering, in accordance with
Entergy Nuclear Operations Engineering and Construction Procedure N0ECP-303,
" Design Change Packages". The inspectors did not identify technical problems
with the package and concluded that the nonsafety-related design change had
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been prepared and approved in accordance with plant procedures.
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3.17 PEIRs Closure
The inspectors reviewed PEIRs 10509, 10515, and 10528, which had been issued
in the 1988-1991 time frame.
The inspectors found that the actions
recommended in PEIR 10515 and 10528 had been completed. The actions for
PEIR 10509, however, had not been completed. The inspectors observed that the
computer data base for model and manual numbers had been revised as
recommended, but the vendor technical manuals had not.
The licensee's procedure for PEIRs, NOAP-018, " Problem Evaluation /Information
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Request," Revision 1, did not contain any steps to ensure the recommended
Lctions were implemented. The inspectors considered this to be a weakness in-
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the procedure.
The licensee stated that a review of the PEIR process would be
performed to evaluate how implementation of recommended actions should be
addressed. NRC review of the licensee's evaluation of the PEIR process is
identified as Inspection Followup Item 382/9325-04.
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3.18 Oualifications of Personnel Performina Enoineerina Work
The inspectors reviewed the degree and experience level of personnel in the
Design and Systems Engineering Groups between 1988 and 1991. The licensee's
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requirements for personnel performing engineering work without 4-year
engineering or related science degrees were in accordance with
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ANSI /ANS-3.1-1978.
D.erican National Standard for Selection and Training of
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Nuclear Power Plan Personnel."
The inspectors found that there were 13 individuals that did not have 4-year
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engineering degrees. None of these individuals held the title of engineer and
were classified as engineering assistants, technical specialists, or
engineering technicians. The individuals had at least 9 years of experience.
Section 4.7.2 of ANSI /ANS-3.1-1978 allows for at least 8 years of experience
in lieu of a 4-year engineering or related science degree and 3 years of
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experience.
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The inspectors reviewed the licensee's descriptions for the engineering
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assistant and technical specialist positions. The inspectors found that the
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engineering assistants were permitted to provide technical support in the
areas of project management, technical design activities, and engineering
studies.
The technical specialist was capable of performing technical support
activities of an engineering nature. This may include maintenance,
modifications, design engineering, and system engineering.
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The inspectors. concluded that these individuals met the requirements set forth
by the licensee to perform the level of work assigned.
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ATTACHMENT
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1 PERSONS CONTACTED
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1.1 Licensee Personnel
- R. Azzarello, Director, Design Engineering
- R. Burski, Director, Nuclear Safety and Regulatory Affairs
- A. Cilluffa, Maintenance Engineering Supervisor
- D. Dormandy, Technical Assistant, Design Engineering
- T. Gates, Licensing Engineer
- T. Gaudet, Operational Licensing Supervisor
- J. Hologa, Acting Director, Design Engineering
J. Houghtaling, Director, Plant Modification and Construction
- P. Melangon, Reactor Engineering and Performance Supervisor
- J. Messina, Chemistry Engineer
- D. Packer, General Manager, Plant Operations
- P. Prasankumar, Manager, Design Engineering, Electrical / Instrumentation and
Controls
B. Proctor, Supervisor, Mechanical Systems, Design Engineering
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- R. Thweatt, Engineering Programs
F. Titus, Vice President Engineering, Entergy Operations, Inc.
- D. Vinci, Operations Superintendent
G. Wilson, Technical Support Coordinator
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1.2 NRC Personnel
- E. Ford, Senior Resident Inspector, Waterford 3
J. Dixon-Herrity, Resident Inspector, Waterford 3
W. Smith, Senior Resident Inspector, River Bend Station
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In addition to the personnel listed above, the inspectors contacted other
personnel during this inspection.
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- Denotes personnel that attended the exit meeting on July 30, 1993.
- Denotes personnel that attended the exit meeting on August 26, 1993.
2 EXIT h5EETING
Exit meetings were conducted on July 30, 1993, and August 26, 1993.
During
these meetings, the inspectors reviewed the scope and findings of the report.
The licensee did not identify as proprietary any information provided to, or
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reviewed by, the inspectors.
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