ML20235R766
| ML20235R766 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 02/23/1989 |
| From: | Bennett W, Constable G, Greg Pick NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20235R746 | List: |
| References | |
| 50-298-89-01, 50-298-89-1, NUDOCS 8903030414 | |
| Download: ML20235R766 (12) | |
See also: IR 05000298/1989001
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APPENDIX B
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
NRC Inspection Report:
50-298/89-01
Operating License:
Docket: 50-298
Licensee: Nebraska Public Power District (NPPD)
P.O. Box 499
Columbus, Nebraska
68602-0499
Facility Name: Cooper Nuclear Station (CNS)
Inspection At: CNS, Nemaha County, Nebraska
Inspection Conducted:
January 1-February 5,1989
Inspectors:
WMW
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G. A. Pjtf Resident Inspector, Project Section C,
Date '
Divisten
Reactor Projects
A/IJ/h
W. R. Bennett, Senior Resident Inspector, Project
Date
Section C, Division of Reactor Projects
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2/27/8'f
Approved:
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st31iTe, Chief _, Project Section C, Division
Da'te /
o _ Reactor Projects
h3030414990227
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ADOCK 05000298
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Inspection Summary
Inspection Conducted January 1 through February 5,1988 (Re' port 50-298/89-01)
Areas Inspected:
Routine, unannounced inspection of plant status, operational
safety verification, monthly surveillance and maintenance observations, and
safety system walkdown.
Results: The licensee operated the plant in a safe, controlled manner. The
licensee addressed a diesel generator failure in a thorough manner; however,
since a similar failure occurred 3 months previously, a potential weakness
still exists in the licensee's corrective action program. The licensee
demonstrated thoroughness and persistence in identifying the root cause of the
main steam isolation valve failure. The predictive maintenance performed on
diesel generators indicates a conscientious attitude towards safety and
reliability in the maintenance area. ~ As discrepancies related to the as-built
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effort are identified, the licensee is evaluating the problems for safety
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significance and impact in the plant.
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One deviation was identified for failure to lock or seal instrument valves as
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committed to in the USAR (paragraph 4).
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DETAILS
1.
Persons Contacted
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Principal Licensee Employees
- G. R. Horn, Division Manager of Nuclear Operations
- G. S. McClure, Manager, Nuclear Engineering Department
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- J. M. Meacham, Senior Manager, Technical Support
- E. M. Hace, Engineering Manager
- R. Brungardt, Operations Manager
- R. L. Gibson, Audit and Procurement Quality Assurance Supervisor
- G. R. Smith, Licensing Supervisor
- C. R. Moeller, Technical Staff Supervisor
- L. E. Bray, Regulatory Compliance Specialist
J. R. Flaherty, Engineering Supervisor
- Denotes those present during the exit interview conducted on
February 6,1989.
The NRC inspectors also interviewed other licensee employees and
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contractors during the inspection period.
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2.
Plant Status
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From January 1-25, 1989, the plant operated at essentially 100 percent
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power. On January 25,1989, at 6:53 a.m. the reactor scrammed en "APRM
High High Level." The cause of the scram was determined to be a failed
main steam isolation valve (MSIV). The reactor was synchronized to the
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grid and power was being increased as of February 5,1989.
3.
Operational Safety Verification (71707)
The NRC inspectors observed operational activities throughout the
inspection period.
Proper control room staffing was maintained.
Control
room activities and conduct were observed to be well controlled and
professional. The NRC inspectors observed five shift turnover meetings
and verified that information concerning plant status was properly
communicated to the oncoming operators. Discussions with operators
demonstrated that they were cognizant of plant status and understood the
importance of, and reason for, each lit annunciator.
Control board
walkdowns and tours of accessible areas at the facility were conducted to
verify operability of plant equipment. Overall plant cleanliness was
observed to be good throughout the inspection period.
The NRC inspectors observed portions of the receipt, inspection, and
storage of new fuel on January 10 and 11,1989. The operators were
careful not to jar or damage the fuel during unpacking and transport of
the fuel bundles from the transportation crates to the fuel pool.
Unpacking and handling of the fuel bundles was controlled by Nuclear
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Performance Procedure (NPP) 10.22 " Receiving and Handling Unirradiated
Fuel," Revision 2, dated January 5,1989.
The operators cleaned,
inspected, and assembled the fuel bundles, the bundle channels, and the
spring clips in accordance with NPP 10.23, "New Fuel Inspection,
Channeling, and Control Blade Inspection," Revision 2, dated December 29,
1988.
Proper control of the receipt of special nuclear material was
implemented by the refueling floor supervisor. The receipt was conducted
in accordance with NPP 10.21, ."Special Nuclear Materials Control and
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Accountability Instructions," Revision 2, dated November 9, 1988. All
operators involved in the fuel receipt process were knowledgeable and
competent. The new fuel receipt process was performed efficiently. All
personnel involved in the new fuel receipt process had recently attended a
training session on inspecting new fuel conducted by General Electric.
On January 17, 1989, Emergency Diesel Generator (EDG) No. I shut down
approximately 21/2 hours into the performance of the monthly operability
surveillance test. The EDG shut down when a circumferential crack
occurred on the stainless steel fitting connecting a pressure gauge to the
overspeed trip valve. The cracked fitting allowed 30 psi control air to
bleed off from the overspeed trip valve. The loss of control air to the
overspeed trip mechanism shut off air to the fuel racks. The fuel racks
closed due to the loss of air, shutting off fuel flow to the cylinders and
stopping the engine.
This problem is similar to the event described in
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NRC Inspection Report 50-298/88-33.
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The licensee determined that the fatigue failures were caused by vibration
causing contact with other metal surfaces inducing stress risers and
subsequent f ailures. The licensee performed a walkdown of the starting
and control air systems on both EDGs.
All problems identified were
corrected. Loose tubing was tied down, and tubing in contact with other
components was buffered by placing rubber gasket material between the
components at the point of contact.
Additional inspections were performed
while the diesels were operating to verify that no contact was made.
Design modifications scheduled for the 1989 refueling outage will move
instruments and air lines from the EDG to instrument racks, significantly
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reducing the vibration. The licensee will inspect the DG piping during
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all planned DG runs prior to the next refueling outage. Another identical
failure of EDG No.1 occurred on February 13, 1989. This later failure
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occurred outside this inspection period and will be discussed in NRC
Inspection Report 50-298/89-09.
On January 25, 1989, at 6:53 a.m., the reactor tripped due to high-high
average power range monitor (APRM) readings. The NRC inspector responded
to the control room following the trip and verified that the control room
operators were taking appropriate actions in response to the reactor trip.
Initial indications were that all APRM channels had tripped on high level
for no apparent reason. The licensee decided to maintain the plant in a
hot standby condition while troubleshooting the cause of the scram.
Further review of recorded instrumentation indicated that a pressure spike
of less than .1 second duration had occurred simultaneously with the APRM
trip signals. This led the licensee to conclude that the pressure spike
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had caused voids to collapse in the reactor core, and this collapsing of
voids had caused a power increase causing the reactor trip. The licensee
then decided to cool the plant down to perform further troubleshooting of
the problem.
The licensee opened both "A" line MSIVs, on January 26, to cool. down the
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plant. With both MSIVs indicating open, the downstream pressure did not
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increase as expected, indicating potential steam line blockage'or MSIV
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failure. The licensee then opened the "B" MSIVs, received the expected
pressure indication increase, and cooled down the plant to a cold shutdown
condition. Testing performed by the licensee indicated that the most
likely failure had occurred in the outboard MSIV (Valve 86A); therefore,
the licensee removed and inspected MSIV 86A. The inspection determined
that no failure had occurred in MSIV 86A. When it was discovered that the
problem was not in MSIV 86A, the licensee reinstalled MSIV 86A and
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commenced disassembly of the inboard MSIV (80A) concurrently with
radiography of the of the "A" main steam line.
Radiography revealed no
obstructions in the steam line. Disassembly of MSIV 80A revealed that the
valve stem had separated from the stem disc.
The pin holding the stem
disc to the valve stem was missing.
This apparently allowed the stem disc
to unthread from the valve stem until the main disc, no longer held by the
stem disc to valve stem arrangement, separated from the stem and fell into
the valve body, blocking the steam line. The licensee repaired and
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reinstalled MSIV 80A.
The NRC inspectors monitored the reactor startup following repair and
testing of MSIV 80A. The startup and power escalation was performed in a
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controlled, professional manner in accordance with operating procedures.
The reactor was declared critical at 1:53 p.m. (CST) on February 4,1989,
and synchronized to the grid at 10:41 a.m. on February 5.
The NRC inspectors verified that selected activities of the licensee's
radiological protection program were implemented in conformance with
facility policies, procedures, and regulatory requirements.
Radiation
and/or contaminated areas were properly posted and controlled.
Radiation
work permits contained appropriate information to ensure that work could
be performed in a safe and controlled manner.
Radiation monitors were
properly utilized to check for contamination.
The NRC inspectors observed security personnel perform their duties of
vehicle, personnel, and package search.
Vehicles were properly authorized
and controlled or escorted within the protected area (PA). Personnel
access was observed to be controlled in accordance with established
procedures. The licensee continued implementation of the security
equipment upgrade during this inspection period. The NRC inspector
conducted site tours to ensure that compensatory measures were properly
implemented as required due to equipment failure or the security upgrade.
Interviews with security pesonnel demonstrated that they were cognizant
of their responsibilities. The PA barrier had adequate illumination and
the isolation zones were free of transient materials.
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The licensee operated the plant in a safe, controlled manner during this
inspection period and took prompt action in response to NRC concerns.
The
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failure of the EDG was addressed by the licensee however, since a similar
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failure occurred 3 months previously, a potential weakness may still exist
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in the licensee's corrective action program. The licensee demonstrated
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thoroughness and persistence in identifying the MSIV failure which resulted
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in an almost undetectable pressure spike that caused the scram.
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No violations or deviations were identified in this area.
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4.
Monthly Surveillance Observations
(61726)
The NRC inspectors observed and/or reviewed the performance of the
following surveillance procedures (SP):
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SP 6.3.4.1, "CS Test Mode Surveillance Operation," Revision 25, dated
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October 17, 1988:
This surveillance test was performed on
January 11, 1989, to meet the TS operability requirements and to
obtain quarterly inservice test (IST) data. The IST engineer took
vibration measurements from additional locations on the "B" Core
Spray (CS) pump motor to provide extra data. The additional data was
taken to enable a more thorough evaluation of the motor's lower
bearing performance to be conducted by General Electric. The CS pump
is located in a contaminated area. The NRC inspector observed both
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the station operator and the engineer utilizing good radiological
practices.
The test equipment was verified to be within calibration.
Good cooperation and communication was exhibited between the engineer
and the station operator. The NRC inspector reviewed the procedure
and determined that all reviews had been conducted and data was
within the required limits.
SP 6.3.12.1, " Diesel Generator Operability Test," Revision 26, dated
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January 5,1989: This test was conducted on January 17, 1989, to
determine that EDG No. I was operable as required by Technical
Specifications (TS). The diesel generator ran for approximately
21/2 hours when it shut down on a loss of control air. The diesel
was restarted at 7:25 p.m. and declared operable at 1:05 a.m. on
January 18, 1989. The NRC inspector reviewed the completed procedure
and determined that all reviews and approvals had been performed.
All data was within specifications. The problem identified
regarding loss of control air to EDG No.1 is discussed in more
detail in paragraph 3.
SP 6.2.2.3.1, "HPCI Steam Line High Flow Calibration and
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Functional / Functional Test," Revision 26, dated April 14, 1988:
This
surveillance was performed as a functional test on January 24, 1989,
to verify that the instruments were operable as required by TS. The
test was performed by qualified individuals who followed the
procedu re. All reviews and approvals were conducted and all data was
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within the required limits. The technicians were knowledgeable about
the function and operation of the test equipment. The NRC inspector
verified that all instruments were within calibration.
SP 6.2.2.3.7, "HPCI Turbine High Exhaust Pressure Calibration and
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Functional / Functional Test," Revision 10, dated December 23, 1987:
This procedure was performed on January 24, 1989, to verify
operability of the pressure switches. The pressure switches activate
to trip the high pressure coolant infection (HPCI) turbine in case of
discharge line blockage. The instrument and control (I&C)
technicians were cognizant of all precautions and limitations in the
procedure.
While observing the above surveillance tests, the NRC inspector noted that
the instrument shutoff valves were not sealed or locked in their normal
operating position.
From plant tours the NRC inspector determined that
there are no instrument isolation valves scaled or locked at CNS.
The NRC
inspector determined that Section VII.2.5 of the Updated Safety Analysis
Report (USAR) required instruments which sense reactor pressure and
reactor water level and input to the reactor protection system (RPS) to be
locked or sealed. The instruments are located on Local Racks 25-5
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and 25-6
The failure to lock or seal the instrument shutoff valves for
the process instruments which input a signal to the RPS is contrary to
USAR commitments. The USAR states, in part, "The test signals can be
applied to the process type sensing instruments through calibration taps
which feed RpS channels. These calibration taps are located on local
panels in the reactor building. These panels, MPL 25-5 and MPL 25-6,
contain instrumentation for reactor pressure and water level.
The test is
conducted as follows:
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An instrument technician following instructions of authorized
personnel unlocks or cuts the seal on the instrument shutoff valves
to a specific instrument and shuts off the instrument line . . .
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The calibration signal is then reduced to zero, the test is removed,
the calibration taps plugged, the sensors valved into service, and
the valves sealed or locked in their operating positions."
The failure to have instrument shutoff valves sealed or locked as
specified in the USAR constitutes a deviation to licensee commitments
(298/8901-01).
The ISI data on the "B" CS pump was within specifications.
Adherence to
procedures was evident. All surveillance were performed in accordance
with applicable procedures. One deviation was identified in this area for
failure to seal or lock instrument isolation valves as committed to in the
USAR.
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5.
Monthly Maintenance Observation (62703)
During the EDG No.1 operability surveillance test conducted on January 17,
1989, the maintenance department used a diagnostic electronic engine
analyzer (BETA Analyzer) on the diesel generators as part of a predictive
maintenance program.
This analyzer test is not required by regulations;
however, the licensee uses this diagnostic tool to analyze individual
cylinder data to detennine potential problem areas. By taking measurements
of the peak firing pressures, cylinder exhaust pressures, and of vibration
in the fuel injector and head bolts, the licensee is able to trend and
identify abnormalities in the internals of the engine. Trending of the
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data provides the licensee with information, so that corrective maintenance
is taken for minor problems and not for a failed EDG. The records generated
from the analyzer test consist of Polaroid snapshots of the oscilloscope
screen. The snapshots superimpose the vibration data and the cylinder
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pressure so that analysis of the engine can be conducted.
Use of the
snapshots provides more accurate information than taking a log of the
pertinent data and measurements. The NRC inspector determined that the
technicians operating the analyzer by the vendor had been trained on the
use of the instrument and interpretation of the data located on the
snapshots.
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On January 31, 1989, the NRC inspector observed the conduct of Preventive
Maintenance (PM) Nos. 04712 and 04599.
PM 04712 is performed annually and
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is implemented by Procedure 7.3.37.1, "Meggering Environmentally Qualified
Reliance Motors," Revision 0, dated December 24, 1986. The electrical
technicians implemented PM 04599 in accordance with Procedure 7.3.37,
" Environmentally Qualified Reliance Motor Lubrication," Revision 0, dated
December 24, 1986.
Lubrication of the fan coil motor is required every
3 years. The electrical technicians meggered Fan Coil Unit Motor FC-RF.
The test results were within specifications. The procedures were
followed, peer quality control was implemented, and the equipment was
properly tagged out. The technicians were knowledgeable and utilized
appropriate safety practices.
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The NRC inspector observed on January 31, 1989, the removal of the valve
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internals from the valve body of the "A" inboard MSIV. The maintenance
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was conducted to determine if the HSIV had failed since testing had been
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inconclusive. The maintenance was controlled and conducted in accordance
with Maintenance Procedures 7.2.24 " Main Steam Valve Disassembly, Repair,
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and Reassembly," Revision 10, dated September 17, 1987, and 7.2.24.1,
" Main Steam Isolation Valve Operator Maintenance and Repair," Revision 1,
dated October 15, 1987. The technicians were familiar with the
procedures.
Proper As Low As Reasonably Achievable (ALARA) practices were
implemented and proper safety precautions were followed.
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Maintenance personnel performed their activities in accordance with
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applicable procedures and standard maintenance practices. Use of the
electronic engine analyzer as a tool in a predictive maintenance program
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for the EDGs is commendable in that it provides for safer and more reliable
sources of emergency power.
No violations or deviations were identified in this area.
6.
Safety System Walkdown (71710)
The NRC inspectors began activities related to the walkdown of the plant
air system.
Documents utilized during this review are listed in
Attachment 1 to this report. The drawings were compared to the lineups
contained in System Operating Procedure (SOP) 2.2.59, " Plant Air System,"
Revision 18, dated June 7, 1988. Minor discrepancies concerning valve
positions between the systen lineup sheets and the drawings were
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identified by the NRC inspectors. The NRC inspectors reviewed the Type 4
discrepancies, i.e., those where resolution by NPPD is necessary,
previously identified by Applied Power Associates (APA).
During their
as-built walkdown of the plant air system, APA identified that
approximately 200 valves had been identified as installed in the plant
which were neither on the drawings nor on the lineup sheet. Many of the
valves had been added to the air system by replacing a single hose
connection with an "H" configuration that had four hose connections.
Other examples of the identified problems were: uncapped lines; unlabeled
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and mislabeled valves; lack of drawings for local instrument racks;
inaccurate system configurations; and discrepancies between the lineup,
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the drawing, and the field configuration.
From review of the Type 4
Problem Notification Sheets generated by APA, the hRC inspector concluded
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that the walkdowns were very thorough,
Review of the problem resolution sheets indicate that the licensee had
evaluated the problems for safety significance and had determined
corrective actions.
Examples of the resd utions included:
capping the
lines found uncapped, hanging temporary valve labels on unlablea valves,
issuing work items to have mislabled valves corrected, issuing drawing
change notices (DCN) to correct inaccurate drawings, issuing DCNs to
document local instrument racks previously undocumented, correcting the
vahe lineups, and updating the equipment data file.
Most discrepancies
had been resolved by the time of this review.
Final resolution of the
problems identified with the plant air system is scheduled to be completed
by the end of 1989 or early 1990.
While the NRC inspectors identified several minor discrepancies between
the operating procedure and the system diagrams, these had previously been
identified during as-built system walkdowns.
APA appeared to have been
very thorough in their as-built walkdown of the plant air system. The
licensee evaluated each Type 4 discrepancy for its impact on plant safety.
This activity will be continued in the next inspection period.
No violations or deviations were identified in this area.
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7.
Exit Interview (30703)
An exit interview was conducted on February 6,1989, with licensee
representatives (identified in paragraph 1). During this interview, the
NRC inspectors reviewed the scope and findings of the inspection. Other
meetings between the NRC inspectors and licensee management were held
periodically during the inspection period to discuss identified concerns.
The licensee did not identify as proprietary any information provided to,
or reviewed by, the NRC inspectors.
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ATTACHMENT
The documents listed below were utilized during the system lineup
comparison to the drawings.
50P 2.2.59, " Plant Air System," Revision 18, dated June 7,1988
Burns and Roe, Inc (B&R) 2010, Sheet 1, " Flow Diagram-Instrument Air,
Control and Turbine BLDG"
B&R 2010, Sheet 2, " Flow Diagram-Instrument Air, Reactor BLDG"
B&R 2010, Sheet 3, " Flow Diagram-Service Air"
B&R 2010, Sheet 4, " Flow Diagram-Instrument Air, Radwaste and Augmented
Radwaste Buildings"
COSMODYNE 6000355, " Solenoid Rack Assy-Charcoal Tank Room, Augmented
Offgas(A0G) Room"
COSMODYNE 6000358, Sheet 1, " Solenoid Rack A Assy-Recombiner Room, A0G
System"
COSM0 DYNE 6001848, Sheet 1, " Solenoid Rack B Assy-Recombiner Room, A0G
System"
B&R IL-E-70-3, Sheet 115, " Reactor Building Local Instrument Rack LR-104"
B&R IL-E-70-3, Sheet 146, " Installation Details-Reactor Bldg. RWCU Sep.
Solenoid Rack LR-115"
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B&R IL-E-70-3, Sheet 46A, " Diagrammatic List of Primary Loading and Air
Supply Lines LR 12-4-130(A)"
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B&R IL-E-70-3, Sheet 46B, " Diagrammatic List of Primary Loading and Air
Supply Lines LR 12-4-130(B)"
B&R IL-E-70-3, Sheet 49, " Diagrammatic List of Primary Loading and Air
Supply Lines LR 12-4-131 A&B"
B&R IL-E-70-3, Sheet 144, " Installation Details-Radwaste Lab Drain
Solenoid Valve Rack LR-144"
B&R IL-E-70-3, Sheet 119, "Radwaste Building-Condensate Demin Local
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Instrument Rack LR-106"
B&R IL-E-70-3, Sheet 134, "Radwaste Building-Fuel Pool Filter Demin Local
Instrument Rack LR-110"
B&R IL-E-70-3, Sheet 142, " Installation Details-Radwaste Demin Solenoid
Valve Rack LR-113"
Delaval FD-3002CL, " Solenoid Valve Rack-Assorted"
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B&R IL-E-70-3, Sheet 48, " Diagrammatic List of Primary Loading and Air
Supply Lines Fuel Pool Cleanup Solenoid Valve Racks"
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B&R IL-E-70-3, Sheet 171B, " Installation Details-Floor Drain Demin
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Solenoid Valve Rack LR-135"
B&R IL-E-70-3, Sheet 123, " Installation Details-High Conductivity Process
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Local Instrument Rack LR-109"
B&R IL-E-70-3, Sheet 172B, " Installation Details-Solenoid Valve
Rack LR-136"
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B&R IL-E-70-3, Sheet 155, " Steam Trap Stations Bypass Valves Control
Panel LR-120"
Honeywell, Inc. 1550-X300, " Piping Schematic IR-1A & IR-1B"
Honeywell, Inc. 1550-X301, " Piping-Instrument Rack IR-1C"
Honeywell, Inc. 1550-X102, " Piping-Instrument Rack IR-ID"
Honeywell, Inc. 1550-X103, " Piping-Local Instrument Rack IR-1E"
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