ML20245D758
| ML20245D758 | |
| Person / Time | |
|---|---|
| Site: | Arkansas Nuclear  |
| Issue date: | 06/15/1989 |
| From: | Chamberlain D, Haag R, Johnson W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20245D738 | List: |
| References | |
| 50-313-89-18, 50-368-89-18, NUDOCS 8906270222 | |
| Download: ML20245D758 (17) | |
See also: IR 05000313/1989018
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APPENDIX B
-U.S.
NUCLEAR REGULATORY COMMISSION
REGION IV
Inspection Report:
50-313/89-18
Licenses:
50-368/89-18
Dockets:
50-313
50-368
Licensee:
Arkansas Power & Light Company (AP&L)
P.O. Box 551
Little Rock, Arkansas 72203
Facility Name:
Arkansas Nuclear One (ANO), Units 1 and 2
Inspection At:
ANO Site, Russellville, Arkansas
Inspection Conducted:
April 16 through May 31, 1989
[A
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- nspectors:
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W. D(/ Johnson, Senior Resident Inspector
Date
Project Section A, Division of Reactor
Projects
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hlS* $f
R.f. Haag,Residentlispector,Pf oject
Date
Section A, Division of Reactor Frojects
~[h ~ bh
Approved:
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D.~ D. Chamberlain, Chief, Project Section A
Date
Division of Reactor Projects
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8906270222 890616
DR
ADDCK 05000313
PNV
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Inspection Sunnary
Inspection Conducted April 16 through May 31, 1989 (Report 50-313/89-18;
50-368/89-18)
Areas Inspected:
Routine, unannounced inspection including plant status,
followup cn previously identified items, followup of events, operational safety
verification, surveillance, maintenance, and installation and. testing of-
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modifications.
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Results: During followup review of-a previous violation on pump coupling
lubrication, the NRC inspector identified a violation involving the application
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of the wrong grease for a high pressure injection pump coupling. The licensee
has been developing an improved lubrication control program, but this 'recent-
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violation indicates that additional licensee review of this area is needed.
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The NRC inspector identified weaknesses in the program for scheduling and.
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tracking visual inspections of snubbers and in the process for reviewing
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technical manual revisions to determine whether any plant procedure changes are
required.
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DETAILS
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1.
Persons Contacted
- N. Carns, Director Nuclear Operations
C. Anderson, In-House Events Analysis Supervisor
~B. Baker, Plant Modifications Manager
T. Baker, Technical Support Manager
B. Bell, Nuclear Safety Analysis Engineer
D. Bennett, Mechanical Engineer
S. Capehart, I&C Engineer
- K. Coates, Maintenance Technical Assistant
B. Converse, Operations Assessment Supervisor
A. Cox, Unit 1 Operations-Superintendent
M. Durst, Project Engineering Superintendent
J. Gobell, Mechanical Engineer-
B. Greeson, Design Engineering Supervisor
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L. Gulick, Unit 2 Operations Superintendent
- L. Humphrey, General Manager, Nuclear Quality
G. Jones, Engineering General Manager
G. Kendrick, I&C Maintenance Superintendent
- R. Lane, Engineering Manager
D.' Lomax, Plant Licensing Supervisor
R. Lovett, Electrical Engineer
W. McCord, Planning and Scheduling Supervisor
R. McKelvey, Field Engineer
J. McWilliams, Maintenance Manager
B. Michalk, Mechanical Engineer
- P. Michalk, Nuclear Safety and Licensing Specialist
V. Pettus, Mechanical Maintenance Superintendent
F Philpot, Nuclear Engineering Superintendent
S. Quennoz, General Manager Plant Support (acting)
- J. Remer, Engineering Support Supervisor
C. Shively, Plant Engineering Superintendent
M. Stroud, Project Engineering Supervisor
L. Taylor, Nuclear Safety and Licensing Specialist
R. Tucker, Electrical Maintenance Superintendent
J. Vandergrift, Operations Manager-
D. Williams, Nuclear Safety Analysis Supervisor
M. Wood, Engineering Support Technical Specialist
C. Zimmerman, Unit 1 Operations Technical Support Supervisor
- Present at exit interview.
The NRC inspectors also' contacted other plant personnel,. including
operators, technicians, and administrative personnel.
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2.
Plant Status (Units 1 and 2)
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Unit 1 operated at 50 percent power until a reactor trip occurred on
May 1, 1989, when maintenance personnel inadvertently jarred a turbine
control panel.
The unit returned to 50 percent power operations on May 3,
1989.
Then on May 16, 1989, the unit was shut down to investigate an
increase in the unidentified RCS leakage and remained shut down through
the end of the inspection period to repair RCS leaks.
Unit 2 operated at 100 percent power until April 18, 1989, when a reptured
extraction steam line initiated a turbine. trip and a reactor trip.
On
MayL7, 1989, the unit'was returned to critical operation.
The unit
reached 100 percent power operation on May 10, 1989, and remained at that
power through the end of the inspection period.
3.
Followup on Previously identified Items (Units 1 and 2) (92702)
(Closed) Open Item 313/8418-01; 368/8418-01: The site evacuation
alarm and the public address system were not audible in all areas of
the plant.
Following extensive testing to locate the areas where audibility of
these systems was deficient, the licensee installed three design
change packages to expand and upgrade the systems (DCPs 84-2001,
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85-2116, and 86-2132).
The last of these DCPs was completed in early
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1989. This item is closed.
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(Closed) Unresolved Item 368/8504-02:
Service water differential
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pressure alarms on high pressure safety injection, low pressure
safety injection, and containment spray pump coolers.
The licensee has revised annunciator response procedures to specify
proper operator actions in response to these alarms when performing
surveillance tests or when an engineered safeguards actuation has
occurred.
The licensee was performing an engineering evaluation to
determine whether these alarms may be eliminated or have their
setpoints modified (Engineering Action Request 87-909, Design-Change
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Package 88-2110).
This item is closed.
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(Closed) Deviation 313/8527-02; 368/8528-05: ~ Control room isolation.
The licensee has maintained the doors from the control rooms to the
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shift supervisors' offices closed.
This has been verified by the
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resident inspectors on numerous occasions.
The licensee established
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a review group to study control room habitability.
At the time of
this inspection, this group had completed its review and was
preparing a report to management, recommending various improvements.
This item is closed.
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-(Closed) Open Item 368/8528-03:
Radiation Monitoring Panel 2C25:
operability.
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ThelicenseehasmaEesteadyprogressinimprovingtheoperability
status of the process and area radiation monitoring instruments on
this panel ~. .This. item is' closed.
(Closed) Open Item 368/8528-04:
ContainmentLpurge control.
The licensee has issued Procedure'1104.21 to provide' instructions to
operato'rs for operation of the Eberline radiation monitoring system.
Recorder 2RR-0645 has been replaced, and its _ recorder charts have'
improved legibility.
The licensee plans to obtain a Xenon-133 source
.to'use for calibration of Radiation Detector 2RE-8233. This item is
closed.
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(Closed) Violation 368/8627-03. L Seismic support discrepancies.
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The licensee completed Calculations 86E-00062-01 and 86E-00064-01 and
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concluded that the seismic supports were operable in the "as-found"
condition. The NRC inspectors have not recently-identified any
similar discrepancies.
The licensee's room inspection effort and'
isometric walkdown project have identified seismic support
discrepancies.
These have been evaluated and resolved'in accordance
with station procedures. This item is closed.
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(Closed) Open'I' tem 313/8713-03:
Further inspection'of ANO-1
emergency operating procedures-(E0Ps) following NRR approval of the
procedure generation package.
-This item is closed administratively.
Further review of ANO, Unit 1
E0Ps will be tracked by the open items assigned-in NRC Inspection
Report 50-313/88-17.
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(ClostJ) Unresolved Item 313/8718-03:
Operability of penetration.
room ventilation systems.
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Problems identified during licensee- testing of the ANO-1 penetration
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room ventilation systems in November 1988.were documented in NRC
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Inspection Report 50-313/88-38. 'Following modifications to door
seals,, preventive maintenance on ventilation duct check valves,:and
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preventiveLmaintenance and reinstallation of. floor drain nonreturn
valves, the systems were retested.
The retests demonstrated system
operability.
This item'is closed.
(Closed) Open Item 313/8732-03:
Natural circulation cooldown on ANO,
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Unit 1 simulator.'
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Appropriate changes t'o the program for the Unit 1 simulator ~have been
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completed. The capability of the simulator to perform.a' natural
circulation cooldown has been demonstrated.' This item.is closed.
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(Closed) Open Item 313/8806-01; 368/8806-03:
Shift administrative
assistant (SAA) recording station parameters on log sheets.
Procedure 1015.01 has been. revised to specify that log keeping is one
of the responsibilities of the SAA.
The NRC inspector was satisfied
that the SAAs were ter'-ically competent to record process and area
radiation monitor readings and to recognize when limits were
exceeded.
This item is closed.
(Closed) Violation 368/8815-01:
Failure to plug emergency. diesel
generator jacket cooling system drain lines as required by procedure.
Procedure 2104.36 has been revised to include separate checks on
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drain line plugs installed and drain valve handles removed.
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item is closed.
(Closed) Unresolved Item 368/8525-01:
Process radiation monitor
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calibration.
The NRC inspector reviewed the records.of the most recent performance
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of Procedure 2304.06, " Gaseous Process Radiation Monitoring System."
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This was performed under Job Order 776549 on April 5, 1989, in
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accordance with Revision 2 of the procedure.
No technical problems
were identified during this review.
This item is closed.
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(0 pen) Open Item' 313/8713-02:
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applications.
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Solenoid Valve SV-2663 was replaced with a different model Target.
Rock solenoid valve in February 1988.
Design Change Packages 87-1081
and 87-2100 were under development by the licensee to determine
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suitable replacements for Target Rock solenoid valves in the Unit 1
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emergency feedwater system and the Unit 2 reactor coolant system high
point vent system.
This item remains open.
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(Closed) Violation 313/8815-01:
Failure to follow procedures
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involving control of components.
The NRC inspector reviewed the licensee's corrective' actions for this
violation and considered them to be appropriate.
The licensee has
issued Revision 23 to Procedure 1015.03B, " Unit Two Operations Logs."
This procedure revision. included a daily check (when in cold
shutdown) on the position of critical manual valves associated with
Revision 8 of Procedure 1015.02,." Decay Heat
Removal and LTOP System Control," included a similar status check for
selected Unit 1 valves. While reviewing this procedure, the NRC
inspecto'r noted that Note 4 on Piping and Instrumentation
Drawing (P&ID) M-232 provided erroneous operating instructions
concerning the locked status and position of Manual Valves BW-8A and
BW-88.
This note conflicted with the requirements of
Procedure 1015.02.
Though P&ID notes are not used at ANO as system
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operating instructions, a licensee representative initiated Condition
Report-CR-1-89-309.
In addition, the.NRC inspector pointed out to a
licensee representative an error in the verbal description of
Valve BW-8B on Attachment F to the procedure. The licensee .
representative agreed to correct this error. This item is closed.-
(0 pen) Violation 313/8730-01; 368/8730-01:
Inadequate preventive
maintenance program for lubrication of pump couplings.
Following failure of a pump coupling'on'a Unit 1 makeup pump in
September 1987, the licensee inspected and lubricated couplings for
safety-related and other important pumps. The NRC inspector reviewed
the completed job orders for the inspection and lubrication of
safety-related pumps of both units performed in September 1987.
No
other couplings were found to_be damaged due to lack of lubrication.
To check the implementation of;the preventive maintenance program for
pump coupling lubrication, the NRC inspector reviewed job orders
documenting coupling lubrication since' September 1987 for a sample of
pumps. The pumps selected were:
P7A. Unit I turbine driven emergency feedwater pump ,
P34B, Unit i decay heat removal pump
P35B, Unit I reactor building spray pump-
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P36A, Unit I high pressure injection pump
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2 PIA, Unit 2 main feedwater pump
2P40A, Unit 2 spent fuel cooling pump
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The couplings on these pumps had been lubricated'at the scheduled
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interval with the exception of the nonsafety-related main feedwater
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pump.
Its coupling was not lubricated as scheduled in April 1989.
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licensee representative stated that a job order had been prepared and;
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that it was planned to be performed during the next outage. ~
The gear case to pump coupling on High Pressure Injection Pump P36A-
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was lubricated in November 1988 under Job Order 741600.- This job-
order was issued for corrective maintenance which required disassembly
of the gear case to pump coupling.
Portions of Procedure 1402.010,
" Unit 1 Primary Makeup Pumps (P36 A, B & C) Inspection / Repair," were
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used to perform the maintenance. Attachment I to this procedure
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provided instructions for coupling and uncoupling. Step'4.4 of this
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attachment required that the gear case to pump coupling be packed
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with Kop-Flex KHP grease. The licensee's preventive maintenance
engineering evaluation (PMEE) for this pump specifies' the use of
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Kop-Flex KHP grease in the gear to pump case coupling and the.use of
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Kop-Flex KSG grease in the lower speed coupling between the motor and
the gear case. During the NRC inspector's review of this job order,
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it was noted that only the gear' case to pump coupling was uncoupled,
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lubricated, and recoupled. The material ticket used to requisition
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grease for this job was reviewed.
Only Kop-Flex KSG grease was
issued for this job.
The use of the wrong grease in the gear case to
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pump coupling of P36A is an apparent violation (313/8918-01). Upon
notification the licensee wrote a condition report and evaluated the
operability of P36A with its gear case to pump coupling lubricated
with Kop-Flex KSG instead of the specified Kop-Flex KHP grease. The
licensee's operability evaluation concluded that P36A was operable.
It was concluded that although Kop-Flex KHP grease was considered
superiot and was preferred,in the P36 gear case to pump coupling,
Kop-Flex KSG grease was compatible with KHP and was acceptable for
use in the coupling. The licensee was evaluating a proposed change
in the specified grease such that both couplings on the P36 pumps-
would be lubricated with the same grease (KHP).
The NRC inspector found that the licensee has in place a program to
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schedule and perform pump coupling lubrication. Followup on that
aspect of Violation 313/368/8730-01 is complete. The licensee has
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been working on an improved lubricant control program.
Completion of
this program ar.d inspection of its adequacy and proper implementation
will be necessary in followup to the current apparent violation
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involving the wrong grease being used in a P36A coupling. The NRC
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inspector discussed the status of the preventive maintenance
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improvement project (PMIP) with licensee personnel. Of the 179 PMEEs
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identified, 168 have been approved. Of the 850 PM procedures
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identified, 750 have been drafted and 550 have been approved. Of the
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7250 PM tasks identified, 6600 have been planned and 3500 have been
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scheduled. Station Administrative Procedure 1000.115 was being
developed to provide overall control of 'the preventive maintenance
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program. Violation 8730-01 remains open pending further licensee
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progress on the PMIP and NRC inspection of its implementation.
(Closed) Violation 368/8825-01:
Failure to properly calibrate a
torque adapter.
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The licensee has attributed this violation to personnel' error and the
failure to follow the applicable torquing procedure when using an
adapter with a torque wrench. After discussions with the valve
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vendor, the licensee loosened the valve bonnet bolts then retorqued
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the fasteners. This item is closed.
(Closed) Violation 368/8823-01:
Failure to properly position a gage
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isolation valve.
This violation involved the failure to close the isolation valve for
a high pressure injection pump discharge pressure gage following a
surveillance test. The licensee. reviewed Units 1 and 2 surveillance
procedures and made appropriate revisions such that detailed
instructions are included in the procedures to close gage . isolation
valve (s) at the completion of the surveillance. The NRC inspector
reviewed a sample of the surveillance procedures and determined
sufficient instructions were included in the procedures. This item
is closed.
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4.
Followup of Events (Unit's 1 and 2)
(93702)
a.
-Unit 2 Rea'ctor Trip Caused by Steam Line Ru'ture
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On April'18,1989) Unit l 2 experienced a' reactor trip from 100 percent
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power. 'The trip resulted from a turbine trip caused by a rupture in
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an= extraction steam line from the high pressure turbine.
The cause
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of the rupture was erosion of the pipe to'a wall thickness of less
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than 1/32' inch. ENRC Inspection Report 50-368/89-17 contains the
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inspection results from an NRC inspection of the ruptured steam line.
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Followingthereactor.thip,anemergency:feedwater'actuationoccurred'
'due to low steam generator . levels. ' Both the turbine driven and motor.
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driven pumps' started, however; the turbine driven emergency feedwater
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pump (2P-7A) tripped on.overspeed. The pump was restarted-
approximately 35 minutes later and performed' satisfactorily.
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troubleshooting and' calibrating the turbine' governor control system,
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the licensee replaced two components, the speed ramp generator and-
- the electronic' governor module', . that were identified'as defective.-
In addition, the licensee made a major revision to-
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Procedure 2304.128, "2P-7A Speed Control Calibration," prior.to
calibrating the governor controls.
The change to the procedure was
based on' a recent revision to the turbine: technical manual (TM) that
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provided a more detailed method of' performing a dynamic calibration
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of the control system.
The revision.to the TM was received by the~-
' licensee in June 1987, but the applicable ANO procedure (2304.128)
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During the review, the NRC-inspector found that.no
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technical review was performed to determine if Procedure 2304'128
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needed to be changed to reflect the TM revision.
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have a system that notifies applicable personnel that a TM revision'
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has been received but this system does nottreview procedural
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adequacy.
The NRC inspector was concerned that relevant information
from TM revisions is not being promptly reviewed to determine if
plant procedures require an update.
The current system ~ requires a TM
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applicability review during each procedure biennial review. . The
licensee informed the NRC inspector that a study is being' performed-
to determine a method for performing a technical procedural
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applicability review when TM revisions are received.
This study and
program implementation will be tracked by inspection. followup
(Item 313/8918-02i 368/8918-P2).
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b.
Unit Shutdown Due to RCS Leakage
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On May 16' 1989, Unit I was shut down to investig, ate the source of
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increased reactor coolant system-(RCS) leakage.
Previously
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unidentified RCS leakage had been slowly trending upward, however, on
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May 16, the leakage was increasing more rapidly and the unit was shut
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down prior.to exceeding the one GPM Technical Specification. limit.for
Leaks were found at a weld on a'RCS drain
valve and at the reactor., vessel level detector probe.
The drain
valve and the defective weld were cut out to allow a destructive
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examination of the weld.
This partic'ular field weld.was made in
February 1989 during repair of a leak at a weld upstream of the drain
valve.
The NRC inspector will review the licensee's root cause
determination of the defective weld and future corrective actions.'
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The licensee repaired the leaking joints associated with the reactor -
vessel level detector probe. Additional leaks were identified by
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subsequent RCS pressure tests which required depressurization and
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repai r.
Several iterations of repairs followed by RCS pressurization
were performed prior to the successful elevated RCS pressure test on
June 2, 1989.
5.
Operational Safety Verification (Units 1 and 2) (71707)
The NRC inspectors observed control room operations, reviewed applicable
logs, and conducted discussions with control room operators.
The NRC
inspectors verified the operability of selected emergency systems,
reviewed tag-out records and verified proper return to service of affected
components, and ensured that maintenance requests-had been initiated for
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equipment in need of maintenance.
The NRC inspectors made spot checks to
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verify that the physical security plan was being implemented in accordance
with the station security plan.
The NRC inspectors verified
implementation of radiation protection controls during observation of
plant activities.
The NRC inspectors toured accessible areas of units to observe plant
equipment conditions, including potential fire hazards, fluid leaks, and
excessive vibration.
The NRC inspectors also observed plant housekeeping
.and cleanliness conditions during the tours.
During a tour of the Unit 2 auxiliary building, a' radiologically
controlled area, the NRC inspector noticed the door to the radiological
waste drumming room was open.
This door is normally closed.
The posting
for the room required a respirator for entry. With the door open, the NRC
inspector noted a large air flow existing from the drumming room into a
portion of the auxiliary building that did not require the use of
respirators.
The health physics supervisor informed the NRC inspector
that the door was open to create a negative pressure in the~ drumming room
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because a hatch to the train bay was open for equipment movement.
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train bay is a nonradiologically controlled area.
The NRC inspector
suggested to the licensee that an alternate method of providing negative
pressure to the drumming room be considered in the future.
This was based
on the poor radiological practice of allowing air flow:from an area
requiring respirators to an area with no respirator requirements.
The
licensee indicated that they would review this for future action.
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These reviews and observations were conducted to verify that facility
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operations were~in conformance with the requirements established under
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Technical Specifications, 10 CFR, and administrative procedures.
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No violations or deviation; were identified.
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6.
Monthly Surveillance Observation (Unitis 1 and 2)
(61726)
The NRC inspector observed the Technical Specification required
surveillance testing on the various components listed below and verified
testing was performed in accordance with adequate procedures, test
instrumentation was calibrated, limiting conditions-for; operation were
met, removal and restoration of the affected components were accomplished,
test results conformed with Technical Specifications and procedure
requirements, test results were reviewed by personnel other than the
individual directing the test, and any deficiencies identified during'the
testing were properly reviewed and resolved by appropriate management
personnel.
The NRC inspector tvitnessed portions of the following test activities:
In-place leak test and flow test of Unit 1 Control Room Emergency Air
Filtering Unit VSF-9 (Procedure 1092.81, Job Order 779740)
Quarterly stroke test of Unit 2 high pressure safety injection-(HPSI)
valves (Procedure 2104.39, Supplement 4)
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Monthly surveillance test of Unit 2 plant protection system Channel B'
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(Procedure 2304.38 and Job Order 784306). The NRC inspector observed
portions of the test involving the engineered safety features logic
matrices and trip circuit breakers.
Monthly performance test of Service Water Pump 2P-4C
(Procedure 2104.29, Supplement 1C)
Quarterly test of Unit 1 main steam and main feedwater isolation
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valves (Procedure 1105.005,' Supplement 1)
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Quarterly stroke test of Unit 2 emergency feedwater valves
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(Procedure 2106.06, Supplement 3)
Verification of Battery and Switchgear Room Cooler VCH-4A actuation
by temperature switches (Procedure 1104.27, Attachment 4)
Stroke testing of Unit 1 emergency feedwater valves
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(Procedure 1106.06, Supplement 3)
Monthly calibration of EFIC Channel A (Procedure 1304.45)
Emergency diesel generator monthly ' test (Procedure 2104.36,
Supplement 2). This test of Unit 2 emergency diesel generator (EDG)
No. 2 was observed twice during this inspection period. The problem
of exhaust system leakage and occasional flames, as leaking
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combustible material is heated by.the exhaust system piping
continues.
Following a suggestion from an NRC inspector from NRC.
headquarters, the licensee collected samples of the material leaking
from exhaust system joints.
Subsequent analysis indictted that no-
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diesel fuel oil was present. The licensee has developed Plant
Change 89-0490, "2K-4A and B Air Roll System." This change is
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intended to be installed during the next refueling outage. Use of-
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the modified system is expected to more effectively remove lube oil
from the upper cylinders following engine shutdown. The resident
inspector will continue to monitor licensee actions on this problem.
Sampling and testing the fuel oil in the Unit 1 and Unit 2 EDG fuel
day tanks (Procedures 1618.028 and 2618.07). The fuel oil from the
4-day tanks was tested on May 25, 1989, in response to an earlier
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sample. On May 24, 1989, following a monthly test of Unit 2 EDG
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No. 2, the fuel oil sample from the day tank had a water
concentration higher than allowed by Technical Specification.
Approximately 100 gallons of fuel oil was drained from the tank. A
subsequent sample had an acceptable water content. The samples taken
on May 25, 1989, were acceptable except for the fuel oil from Unit 2
EDG No. 2 day tank which again had a high water concentration. After
partially draining the day tank and refilling the tank, a sample was
taken which had acceptable water content.
Samples taken on May 26
and 30, 1989, were tested with acceptable water content. The
licensee has not determined the source of the water but is continuing
the investigation.
The licensee has initiated sampling of the Unit 2
EDG No. 2 day tank on a weekly basis. The NRC inspector will
continue to monitor the licensee's actions to determine the water
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source and to prevent recurrence.
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In addition, the NRC inspector observed a surveillance test of Low
Pressure Safety Injection (LPSI) Pump 2P-608 (Procedure 2104.40,
Supplement 2) to verify operability of the pump.
Earlier the pump was run
to flush the LPSI discharge lines, which was required after decay heat
removal operations. However, prior to starting the flushing operation,
the suction supply valve to 2P-60B was not opened and the pump was run for
10 minutes without any flow. Based on the surveillance showing no signs
of degraded pump parameters or damage, the licensee declared 2P-60B
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operable. The licensee attributed this event to an inadequate procedure
and personnel error that failed to recognize the pump suction supply was
not properly lined up.
Procedure 2104.04, "LPSI System Operation," is
being revised to clarify instructions for performing flushes of the LPSI
discharge lines.
No violations or deviations were identified.
7.
Monthly Maintenance Observation (Units 1 and 2)
(62703)
Station maintenance activities for the safety-related systems and
components listed below were observed to ascertain that they were
conducted in accordance with approved procedures, regulatory guides, and
industry codes or standards, and in conformance with the Technical
Specifications.
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The following items were considered during this review:
theflimiting
conditions for operation were met while components or systems were removed
from service, approvals were obtained prior to initiating the work,
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activities were accomplished using approved procedures and were inspected
as applicable, functional testing and/or calibrations were performed prior
to returning components or systems to service, quality control records
were maintained, activities were accomplished by qualified personnel,
parts and materials used were properly certified, radiological controls
were implemented, and fire prevention controls were implemented.
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Work requests were. reviewed to determine the status of outstanding jobs
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and to ensure that priority is assigned to safety-related equipment
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maintenance which may affect system performance,
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The following maintenance activities were observed:
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Replacement of fuel supply crossover lines on Unit 2 emergency diesel
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generators (Plant Change 89-0205, Job Order 781044).
A 10 CFR
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Part 21 report from Calvert Cliffs Nuclear Power Plant identified a
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potential defect involving cavitational erosion causing pinhole leaks
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in the fuel supply lines.
The existing copper lines at ANO were
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replaced with carbon steel lines based on the vendor's recommended
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action to prevent the cavitational erosion in the crossover lines,
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Troubleshooting HPSI Valve 2CV-5016-2 (Job Order 783896).
During a
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surveillance test that verifies the' operability of check valves in
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the HPSI discharge lines, 2CV-5016-2 would not completely close.
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This test required 2CV-5016-2 to be cycled while a HPSI pump was-
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operating.
This provided a differential pressure across the valve
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when it was closed.
Inspections revealed that the packing gland was
cocked, adding to the overall loading of the valve. -The additional
loading of the packing gland caused the valve operator to " torque
out" prior to reaching the fully closed position.
The packing was
adjusted in January 1989, however, this.was the first time the valve
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was operat9d with an HPSI pump running.
The packing gland was
properly adjusted and the valve was retested to verify satisfactory
operation.
Repair of the Unit 2 main feedwater control system (Job
Order 783904).
Following the reactor trip on April 18, 1989, the "A"
main feedwater regulating valve did not remain closed as required by
the design of the system.
The licensee identified two wires -
" shorting out" in the "A" train control cabinet which allowed the
reactor trip override signal to clear after 20 seconds.
The valve
then went to the 50 percent open position and overfed the "A"
steam
generator.
The licensee replaced the damaged wires then performed
several functional tests of each control cabinet to verify proper
operation.
Replacement of the Geiger Mueller tube-in the Unit 2 control
room (CR) Radiation Monitor 2RITS-8750-1 (Procedure 2304.006, Job
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Order 784442).
Following the large number of recent actuations of
the CR emergency ventilation system caused by spiking of
2RITS-8750-1, the Geiger Mueller was replaced due to a concern of..
potential shorting within the tube.
During the tube replacement, the
licensee identified and corrected damaged wires in the tube holder.
Since these repairs, the licensee has experienced only one actuation
of the CR emergency ventilation from May 2-31, 1989.' The licensee is
still pursuing long term corrective action concerning the design
adequacy of the Unit 2 CR radiation monitor.
The NRC inspector will
continue to monitor the licensee's actions.
Installation of rebound spring on Unit 2 K-Line circuit breaker to
ensure proper breaker' operation following a seismic event.
The
licensee had earlier installed the rebound springs on Unit 1 and
selected Unit 2 breakers.
During the unit shutdown following the
reactor trip on April 18, 1989, the rebound springs were installed'on
the remaining Unit 2 breakers.
Six nonsafety related breakers would
not close when they were cycled'during the postmaintenance testing.
The licensee determined the cause of the breakers failing to operate
properly was the accumulation of dust, dirt, and dried lubricant on
the internal surface which restricted movement of the internal
closing mechanism.
This was similar to problems experienced with
several Unit 1 breakers.
The licensee has not completed all the
corrective action items associated with the failures of the Unit 1
breakers.
These action items include reevaluation of the preventive
maintenance program for K-Line circuit breakers and a review to
determine the need for periodic cycling of the circuit breakers.
Open Item 313;368/8905-02 was previously issued to track this matter
and will continue to be used for tracking purposes.
Troubleshooting the failure of Valve 2CV-5657-1 to open (Job
Order 784377).
During a monthly surveillance test of a sodium
hydroxide pump, the sodium hydroxide tank outlet valve would not open
remotely from the control room.
The licensee determined that a latch
in the limit and torque switch would move up unexpectedly when the
valve was moving off the closed seat and would allow actuation of the
open torque switch.
A similar failure occurred on February 1,1989,
when the latch loosened and allowed actuation of the' torque switch.
To prevent recurrence the licensee increased the open. torque switch
setting to the maximum position.
In addition, the licensee is
considering the installation of a more reliable torque switch bypass.
During review of this event, the licensee informed the NRC inspector
that the engineered safety features signal for the valve to open on a
containment spray actuation has a separate torque switch bypass-that
would prevent this type of valve failure.
Repair of Component Cooling' Water Valve 2CV-5236-l'(Job-
Order 783881).
During Surveillance Stroke Time Test 2CV-5236-1, a
containment isolation valve, failed to meet the Technical
Specification stroke time requirement.
Corrective action involved
adjusting the open limit switch so the valve would be' limited to
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80 degrees open (0 degrees being closed and 90 degrees being fully
open). The NRC inspector reviewed the job order that provided'
instructions to complete the work and the engineering memorandum that
provided justification to allow' this: adjustment. The NRC inspector
noted during the review that the mechanical stops in the valve
operator were not adjusted to correspond with the.new 'open limit
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switch. This would allow the valve, if manually operated, to be
opened to the original position. ,After discussions with operations
personnel which identified the remote possibility that the valve
would ever be manually positioned, this issue does not appear to bela
significant concern. However, it is not clear to the NRC inspector
that the licensee has adequately reviewed this issue to ensure that
all safety-related aspects of the job have been addressed. For
example, it is not clear that there.are controls in pifce to assure
that the limit switches will not be adjusted-to full open during some
future maintenance activity. Also, it appears that this should be
considered a temportry condition which will be permanently resolved
later. This matter will remain unresolved pending further review by
the NRC inspector (Unresolved Item 368/8918-02).
Troubleshooting the erratic indication of nuclear instrumentation
channel "C" log power (Job Order 785720)
Disassembly and inspection of Service Water Pump Discharge Check.
Valve SW-1C (Job Order 785661). The valve was disassembled to allow
inspection of carbon steel parts that were_ installed during the last
refueling to detennine if any significant corrosion had occurred.
The NRC inspector noted minor wearing of the parts, but their overall
condition was good.
Reassembly of Service Water Pump P-4C (Procedure 1402.061, Job
Order 784387). The pump was being replaced due to recent
surveillance parameters that indicated pump performance was
degrading.
Inspection of small bore Anchor Darling snubbers located in Unit 2
reactor building. This visual inspection of snubbers was performed
by the licensee per Technical Specification Surveillance
Requirement 4.7.8.
During review of the area, the NRC inspector
discussed two areas of concern with.the licensee as described below:
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(1) Six snubbers had cold settings that did not provide adequate
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strokes to accommodate the calculated thermal growth. A
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comparison of the as-built snubber configuration to the
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calculated thermal growth identified these deficiencies, wHle
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installation drawing. The licensee attributed the deficient
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previous inspections compared snubber configuration to the
snubber settings to personnel error during the engineering
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design of the snubber installation and during the engineering
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as-built inspections. Support modifications were made for the
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six snubbers to provide the correct cold settings.
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This inspection dealt with approximately 70 snubbers that were
part of a design change package (DCP) that' replaced approximately
100 snubbers. During the review, the NRC inspector noted that
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for each of the six snubber deficiencies?a comparison'of the
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calculated thermal growth to the as-built snubber installation
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drawing revealed the incorrect cold setting.
At the suggestion
of the NRC inspector, the. licensee reviewed each of the snubber
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as-built drawings ast,0ci "ed with the DCP. This included the
30 snubbers that were not part of this recent inspection.. One
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additional snubber cold setting was ' identified that would not
accommodate the calculated thermal 1 growth. However, a' stress
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analysis on the corresponding section of pipe revealed the
snubber setting was acceptable. The initial ^ engineering response
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to this problem did.not provide a comprehensive evaluation.:
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Based on the NRC inspector review, this problem now appears to be
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resolved for Unit 2.
The licensee has not reviewed a similar. DCP
for the Unit 1 snubbers to determine if similar errors occurred.
The NRC inspector was informed that this , review is currently'
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being planned.
Completion of the licensee's review of Unit 1-
snubbers will be tracked by inspection followup (Item 313/8918-03).
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(2) Snubber 2CCA-15-H34 was found disconnected from a pressurizer
spray isolation valve during the visual inspections. The
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snubber had been removed from the valve on May 12, 1988,.to
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allow repacking the valve. The job order performing the work
required a visual inspection (VT-3) of the reinstalled. snubber
to comply with ASME code requirements. The licensee has been
unable to locate any documentation to support that the visual-
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inspection was performed and is now assuming the inspection was
not performed. A new snubber has been installed.
The failure to reinstall the snubber, as related to the valve
repacking maintenance activity, was attributed to inadequate
work controls. The job order that repacked the valve and
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disconnected the snubber also provided similar instructions for
three other pressurizer spray isolation valves. The work
instructions in the job order were not detailed and provided no
signoffs fo' completion of the work. The licensee stated that
the corrective action from previous cases of inadequate. work
controls is sufficient to address the concerns of the snubber
not being reinstalled. However, the NRC inspector was unable to
find a root cause determination or corrective action associated
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with the missed visual inspection. The licensee nas assigned
additional corrective action items in an attempt to resolve this
issue.
Based on the NRC inspector's initial review of the
program for scheduling and tracking of inspections, improvements
are warranted. NRC review of the licensee's root cause-
evaluation and corrective actions related to the missed visual
inspection will be tracked by inspection followup
(Item 368/8918-01).
No violations or deviations were identified.
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8.
Installation and Testino of Modifications (Units 1 and 2)
(37828)
The NRC inspector reviewed a recent plant change (PC) and a recent design
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change package (DCP) to ascertain whether they were installed and tested
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as required by plant procedures and in conformance with the requirements
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of the Technical Specifications, 10 CFR 50.59, and 10 CFR 50, Appendix B,
Criterion III, " Design Cont'ol."
PC 89-0205 was installed in April 1989.
This change replaced fuel oil
crossover piping on both Unit 2 emergency diesel generators. The NRC
inspector reviewed the PC package and determined that the requirements of
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10 CFR 50.59 were met.
Installation was performed under Job Orders 780693
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and 781044. Postmodification testing included inspection for leaks and
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performance testing of the diesel generators. The NRC inspectors observed
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one of these test runs.
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DCP 87-2105 was installed in April 1989. This change added an instrument
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on 2C80, the Unit 2 remote shutdown panel, to provide indication of
shutdown cooling flow. The NRC inspector _ reviewed the DCP, including the
10 CFR 50.59 evaluation, procurement documents, the installation plan,
installation job order and records, testing job order and records, and
as-built drawings.
Electrical schemes and connection drawings were
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compared to the installed components to verify that the installation had
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been completed properly and that any changes had been properly marked on
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the drawings. Testing included a calibration of the new flow indicator,
calibration of the flow transmitter, and instrument string checks in
accordance with Procedure 2304.010.
No violations or deviations were identified.
9.
Exit Interview
The NRC inspectors met with Mr. N. S. Carns, Director, Nuclear Operations,
and other members of the AP&L staff at the end of the inspection. At this
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meeting, the NRC inspectors summarized the scope of the inspection and the
findings.
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