ML17325A660
| ML17325A660 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 03/08/1988 |
| From: | Darrin Butler, Gardner R, Ulie J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17325A658 | List: |
| References | |
| 50-315-88-03, 50-315-88-3, 50-316-88-04, 50-316-88-4, NUDOCS 8803150375 | |
| Download: ML17325A660 (15) | |
See also: IR 05000315/1988003
Text
U ~ S.
NUCLEAR REGULATORY COMMISSION
REGION III
Reports
No. 50-315/88003(DRS);
50-316/88004(DRS)
Docket Nos.
50-315;
50-316
Licensee:
Company
1 Riverside
Plaza
Columbus,
43216
Licenses
No.
Facility Name:
D.
C.
Cook Nuclear Plant, Units 1 and
2
Inspection At:
AEPSC,
Columbus,
Ohio and
D.
C.
Cook Site,
Bridgman, Michigan
Date
Inspection
Conducted:
January
11-14, 25-28,
and March 2,
1988
Inspectors:
D.
S. Butler
Date
J.
M. Ulie
3
8'pproved
By:
R.
N. Gardner,
Chief
3 9
Plant Systems
Section
Date
Ins ection
Summar
Ins ection on Januar
11-14
25-28
and March 2
l988
Re orts
No. 50-315/88003
.
No. 50-316/88004
Areas Ins ected:
Special
announced
safety inspection of
on previously identified items
and Licensee
Event Report
inspection
was performed in accordance
with IE Procedure
Results:
Of the areas
inspected,
one apparent violation
(Failure to implement adequate
design control measures-
3.a(2),
and 3.b(1)).
licensee
actions
followup.
The
92700
and 92701.
was identified
Paragraphs
3. a(l),
8803150375
880308
ADQCK 05000315
6
DETAILS
1.
Persons
Contacted
and Michi an Electric
Com an
Personnel
"W. Smith, Jr., Plant Manager
"A. Blind, Assistant Plant Manager - Administration
- J. Rutkowski, Assistant Plant Manager
Production
- B. Svensson,
Licensing Activity Coordinator
"T. Bei lman, I 8 C/Planning Superintendent
- T. Postlewait,
Technical
Superintendent
- Engineering
"C. Ross,
Compute'r Science
Superintendent
- J. Droste,
Maintenance
Superintendent
"S. Delong, I 8
C Production Control General
Supervisor
"D. Krause,
I 8
C Production Supervisor
J. Wojoik, Chemical Supervisor
R.
Hennen,
Nuclear Section
Head
- T. Langlois, I & C Production Control
"G. Arent, .Operations
"B. Stoner,
Computer
Science
B. Burgess,
Training
AM. Barfelz, Safety
and Assessment
American Electric
Power
Service
Com an
Personnel
M. Alexich, Vice President,
Nuclear Operations
+B. Auvil, Nuclear Safety
and Licensing
+iP. Barrett,
Manager,
Nuclear Safety
and Licensing
+R. Carruth,
Manager, Electrical Generation
Section-N
R.
Kroeger,
Manager,
equality Assurance
+B.
Lauzau,
Nuclear Safety and Licensing
(NS 8 L)
R. Vassey,
NS
8
L
R. Kraszewski,
NS
8
L
K. Toth,
NS
8
L
R.
Shoberg,
Mechanical
Engineering Division - I 8
C
W. Sotos,
Mechanical
Engineering Division -,I 8
C
J.
Anderson, Electrical Generation
Section -
N
D. Maxwell, Nuclear Operations
Division
C. Erikson, Nuclear Operations Division
G. John,
Nuclear Fuels
and Analysis
"R. Huerter,
Supervisory Auditor - gA
NRC Personnel
"B. Jorgensen,
Senior Resident
Inspector
~J. Heller, Resident Inspector
- Denotes
those attending the exit meeting
on January
28,
1988.
~ Denotes
those attending the telecon meeting
on February 3,
1988.
+ Denotes
those attending the telecon exit meeting
on March 2,
1988.
The inspectors
also contacted
other personnel
during the course of the
inspection.
2.
Licensee Action on Previous
Ins ection Findin
s
92700
and
92701
a.
b.
(Closed) Part
21 Item (315/78001-PP;
316/78001-PP):
Deficiencies
in environmental qualification of Cutler-Hammer
(C-H) terminal
blocks.
The terminal blocks, if used,
were found inside containment
and were
housed in penetration
terminal
boxes.
The licensee
removed all leads
from any
C-H terminal blocks
and spliced the
together with qualified (40 years)
Raychem splices
and
terminations.
Procedure
12
THP 6030
IMP. 071, "Instrument and
Control Environmental gualification of. Safety Related Electrical
Equipment Surveillance/Maintenance
and Replacement
Program,"
recommended
adequate
surveillance
and maintenance activities to
ensure that electrical control,
power and instrumentation
cables
and terminations that were
Eg would retain their environmental
qualification.
(Closed) Part
21 Item (315/81001-PP;
316/81001-PP):
Possible
failure of Volume Control Tank (VCT) level instrumentation.
identified the potential for the
VCT level controller
(gLC-452) to fail high due to a failure of the controllers capillary
reference
leg.
The
VCT low level alarm (5 inches)
was fed from
gLC-452.
Without reactor operator intervention the
VCT could empty
with a loss of suction to any operating centrifugal charging
pump
(potential to damage
the pumps).
A single
random failure in the
level control
system could lead to a loss of redundancy
in the high
head safety injection system.
The licensee
added
an additional
VCT low level alarm (10 inches)
for both units.
Procedures
1-OHP 4024. 109 and
2-OHP 4024.209,
"Annunciator ¹9 Response
Boric Acid," were modified and contained
adequate
instructions
on how to respond to VCT level annunciators.
In addition, operator
lesson plan RO-C-E507,
"Basic Control
Systems,"
was modified to include information on instrument
reference
legs
and the effects of their failure on instrumentation.
(Clos'ed) Part
21 Item (315/81002-PP;
316/81002-PP):
Deficiencies
in Eberline micro-computer
based radiation monitoring equipment.
There was
a potential error in the interrupt structure of the
central processing unit (CPU III) board.
Two interrupts of
increasing priority that occur sequentially
could cause
the
interrupt data to be lost.
The vendor supplied the licensee with vendor manual
procedure
inserts
and modification kits for the following equipment:
~ PT-1
~ CT-1
~ Sping-3/Sping-4
I
Portable
Terminals
Control Terminals
Particulate,
Iodine and Noble Gas Monitors
All the modifications were completed
and tested satisfactorily.
The inspectors verified that all the controlled manuals
had the
insert attached
to the
CPU III manual section at American Electric
Power
(AEP) and at the plant.
Only one manual
(Sping-3/Sping-4)
in the Instrument
and control Satellite Library, at the plant, did
not contain the insert.
The licensee
promptly removed the manual
from circulation and issued
paperwork to have
a controlled copy of
the insert placed in the manual.
The guality Assurance
(gA)
organization
committed to perform a surveillance of all plant
satellite libraries during their current on-going audit.
This item appears
to be an isolated
case
and the inspectors
have
no further concerns
in this area.
d.
(Closed) Part
21 Item (315/82001-PP;
316/82001-PP):
Brown-Boveri
Electric/ITE low voltage circuit breaker solid state trip devices
have
an electrolytic capacitor which could potentially fail and
prevent the trip unit from opening the breaker.
Subsequent
licensee
investigation determined that the capacitor
had
a low failure rate
and that immediate
change
out of all the trip units did not
constitute
a significant safety hazard.
The licensee
has
changed
out some of the trip units, modified an
existing Type 504 breaker test set
and purchased
a new 504 test
set.
The .504 test set
can detect
a failing capacitor.
The
inspector
reviewed Procedure
12
MHP 5021.082.010,
"Maintenance
Calibration Procedure
For Trip Devices,
Types
SS-13
and SS-14
used
on 480V and
600V Power Circuit Breakers,"
and determined that there
were adequate
procedure
steps
and acceptance
criteria to detect
a
failing capacitor.
e.
(Closed) Part
21 Item (315/83002-PP;
316/83002-PP):
Static
.calibration drift of zero suppressed
Model 763 Barton pressure
transmitters.
These transmitters
were supplied
by Westinghouse
to
measure
pressurizer
(PZR) pressure.
The potential
magnitude of the
drift between in-plant calibrations
(18 months)
was established
as
4.2 percent
and always in the negative direction.
The licensee
replaced
the
PZR pressure
transmitters with new Eg Foxboro Units in
1985 for Unit One and
1986 for Unit Two.
The inspector
reviewed the past two Barton calibrations, prior to
their change out,
and determined that the maximum drift experienced
was within each units safety analysis.
In addition, transmitters
that were exhibiting a larger drift were calibrated
more frequently
and analyses
were performed to address
channel operability.
None of
the transmitters
experienced
a 4.2 percent drift.
(Closed) Part
21 Item (315/84001-PP;
316/84001-PP):
Undetectable
test switch failure in the Westinghouse
Solid State Protection
System
(SSPS).
A momentary pushbutton
(PB) test switch was
used to
test the continuity path through the safeguards
slave relay.
The
PB
would energize
the master relay and open contacts that were shorting
out the logic test
lamp.
Failure of the
PB contacts
to close
and
short out the test
lamp would place the test
lamp in series with the
slave relay coil.
On a safeguard activation, failure of the
lamp
would prevent the slave relay from actuating
safeguard
equipment.
The licensee
has adequately
modified the test circuitry and
procedures
1 THP 4030 STP.410,
1 THP 4030 STP.411,
2 THP 4030 STP.510,
and
2 THP 4030
STP! 511 (Reactor Trip SSPS
Logic and Reactor Trip
Breaker Train A(B) Surveillance Test (Monthly)) to detect
a test
switch failure.
(Closed) Part
21 Item (315/84002-PP;
316/84002-PP):
Brown-Boveri
Electric/ITE low voltage circuit breaker solid state trip devices
have silicon controlled rectifiers
(SCR) that could exhibit high
leakage current.
The excessive
leakage current
may cause'mproper
operation of the trip device.
The vendor
recommended
a special
stress
test
be used to detect
bad
SCRs.
The licensee
has incorporated
the vendors
recommended
testing in
procedure
12
MHP 5021.082.010.
The procedure
steps
and acceptance
criteria were adequate.
(Closed) Part
21 Item (315/84005-PP;
316/84005-PP):
Deficiency in
the
DETECTOR computer
code that is used to calculate
the Technical
specification
(TS) limits for enthalpy rise peaking factors.
The
DETECTOR code
was previously reviewed in NRC inspection report 87028.
The report closed out
LER 84007 and
Open Item 84014-01
on licensee
implemented corrective actions to ensure
the adequacy of the
DETECTOR code.
The inspector further reviewed the application of the process
computer
(P250) for providing acceptable
plant data to support
TS
calculations.
The
DETECTOR code
uses real-time plant data that is
processed
by the
P250 computer.
The licensee calibrates
the process
parameter
voltage to frequency (V/F) converters that input to the
P250
on an 18 month interval.
The
P250 verifies the adequacy of,
the information it receives
by using internal diagnostic
programs.
A diagnostic error is generated
when
a V/F converter is out of
specification.
The
DETECTOR code
uses its own diagnostic
programs
to determine
the adequacy of the data received
from the P250.
The inspector
has
no further concerns
in this area.
(Closed) Part
21 Item (315/86001-PP;
316/86001-PP):
Instrumentation
error in the analog version of Reactor Vessel
Level Instrumentation
System
(RVLIS) used at non-upper
head injection plants.
The
supplied
RVLIS system is used to provide accurate
level
measurement
over
a wide range of steam density (temperature-pressure
compensation, for steam density).
identified
inconsistencies
in the guidelines supplied to determine scaling
constants
used to steam density compensate
full-range, upper-range,
and dynamic
head
spans.
At pressures
approaching
2500 psi, the
reactor level indication may be off as
much as
20 percent.
Changes
were
made to the scaling procedure
and plant specific gains
and biases
were determined during system testing.
The inspector
reviewed procedures
1 THP 6030 IMP.315,
1 THP 6030 IMP.316,
2 THP 6030 IMP.415,
and
2 THP 6030 IMP.416, "Reactor Vessel
Level
Indication System
(RVLIS) Train A(B) Calibration (18 Month)," and
determined
the procedures
had incorporated
the correct gain and
bias values
as detailed in RVLIS Scaling
and Calibration Documents
for D.
C.
Cook Units One and
Two (Vendor Information
Control 8P-0986-020-N).
The inspectors verified training was provided to the technicians.
Instrument
and control technicians
were selected
to attend
formal
and on-the-job training (OJT) on RVLIS.
Technicians that were not
trained
on the system did not calibrate
the system
unless
, accompanied
by a qualified technician.
j.
(Closed)
Part
21 Item (315/87001-PP;
316/87001-PP):
Transformer
terminal corrosion that was caused
by acid flux residue left on the.
transformer
leads during the manufacturing process.
The licensee
replaced six (6)
PCB transformers
with qualified dry type transformers
on the 4160V safety related
busses
for each unit.
Unit Two
transformers
were installed
upon receipt from the manufacturer
(Brown Boveri Electric).
No corrosion
was observed.
Unit One
transformers
were placed in a qualified storage'rea'for
approximately
15 months.
During Unit One transformer installation, pitting was
observed
on the plated aluminum terminals.
The licensee notified
the vendor.
The vendor cleaned the transformer leads,
polished the
terminal to remove the pitting, and coated the terminals with
NO-OXIDE grease.
Unit Two transformer terminals were inspected
and
were not pitted.
The vendor indicated that heat from the installed
transformers
caused
the acid flux to subliminate
(change into a gas
and dissipate).
Ten of the transformer terminals
were inspected
by observation
through the louvered panels.
All of the transformers
were in use
at the time.
The terminals
showed
no signs of corrosion
and were
coated with NO-OXIDE grease.
k.
(Closed) Violation (315/85030-01;
316/85030-01):
Failure of the
licensee to take timely corrective action to correct deficiencies
identified in 10 CFR Part 21 reports.
Four items (2.b,d,f,
and
g
of this report) were considered
as
examples for this violation.
AEP procedure
GP 15. 1, "Corrective Action," contained
adequate
steps to prevent the recurrence
of this violation. If the
Corrective/Preventive'actions
cannot
be completed
by the assigned
due date,
extensions
were granted in accordance
with increasing
level of management
approval.
All changes
in report status
or
due dates
were reported to the Trend Coordinator for tracking.
The gA organization
has included
a Part
21 surveillance
in audit
C13-86-31
8 31.1 (Electrical Generation Section)
and in audit
C13-86-21-21.6,
21.8 (Instrument
and Control Section).
No
deficienci es were identi fied.
1.
(Closed) Violation (315/86027-01):
Failure of the licensee
to
adequately
response
time test the Unit One steam generator water
high-high level turbine trip reactor trip.
The licensee
has
adequately
modified procedures
12 THP 4030 STP.205A and 205B,
"Engineered
Safeguards
Features
Time Response
Train A(B)," to
satisfy Unit One
TS 3.3.2. 1 and
TS Table 3.3-5.
m.
(Cl osed)
Open Item (315/86027-02;
316/86027-02):
Change
procedures
1 THP 4030
STP. 100A and
2 THP 4030
STP. 100, "Reactor
Protection
and Engineered
Safeguards
System
Time Response,"
to
measure
the neutron flux signal
time response
from the input of
the first electronic
component in the channel.
The licensee
has
adequately
modified these
procedures
to response
time test the
neutron instrumentation
from the first electronic
component.
Licensee
Event
Re ort (LER
Followu
92700
a.
(Open)
LER (315/87023):
Failure to provide electrical isolation
between
Local Shutdown
and Indication (LSI) panels for Unit One
and Unit Two.
(1)
On November 9, 1987, during an investigation into the
feasibility of using existing Reactor Coolant System
Wide
Range T-Hot and T-Cold indications
(EIIS/AB-TI). for
Regulatory'uide
1.97 compliance,
the licensee
determined that the fuses
(EIIS/FU) required for isolation between the various
LSI panels
(EIIS/PL) were improperly located
on Unit Two and were not
included in the existing design
on Unit One.
Therefore,
a
condition existed that, in 'the event of a fire local to an LSI
panel,
power (both normal
and alternate)
to some or all of the
same unit's remaining
LSI panels
could be lost. 'f power was
lost to all panels,
those indications available locally would
be lost.
In addition, all Wide Range T-Hot and T-Cold
indications,
1 of 4 channels of pressurizer
level indication
(EIIS/AB-LI), and both trains of the Reactor Vessel
Level
Indication System (EIIS/AB-LI) would be lost in the control
room.
According to the licensee's
analysis of this issue, with the
exception of Mide Range T-Hot and T-Cold, all of the process
variables
indicated locally at the LSI panels
would not be
required locally due to their availability in the control
room
and the fact that
a fire at any LSI panel location would not
require
remote
shutdown.
The inspectors,
including
NRC
contractors
(Brookhaven National Laboratory),
performed
a
selected
review of this issue
and concluded that the process
variable indications would still be available in the control
room to enable
a safe
shutdown of the plant.
Each of the units
we'e in a power operation condition
(Mode 1) at the time of
discovery of this issue.
As a result of the identified deficiencies,
the licensee,
on
December
22,
1987,
implemented roving fire watch patrols to tour
the LSI panel
locations within each, unit.
At the request of
Region III personnel,
the licensee,
on December
24, 1987,
upgraded
the roving fire watches to continuous fire watches.
These interim compensatory
measures
were maintained until the
necessary
design
changes
were implemented.
These
changes
were
implemented for Unit Two on December
30,
1987 and for Unit One
on December
29,
1987.
The cause of the electrical isolation deficiencies
was
attributed to an oversight (cognitive personnel
error) by
design engineers
in the design
and engineering
process
associated
with the initial Appendix-R modifications.
The
failure to perform adequate
design
reviews regarding electrical
isolation between
LSI panels is considered
an example of a
potential violation'f 10 CFR 50; Appendix B, Criterion III.
During this inspection,
the inspector
reviewed the
licensee's
implementations of the design
changes
discussed
above.
During this review the inspector determined:
The LSI panels
were located in the following fire zones:
Zone
5
5
33
33
12
12
5
5
34
27
22
24
Power
Feed (Breaker)
20a(Unit 1)
20a(Unit 2)
20a(Unit 2)
20a(Unit 1)
Panel
LSI-3
LSI "4
LSI-1
LSI-5
LSI-2
LSI"6
LSI-3
LSI"4
LSI-1
LSI-5xx
LSI"2
LSI"6xx
Fuse
Addition (Amperes) Unit
10a
5a
5a
10a
10a
sa
5a
10a
The licensee
implemented modification RFC-12-2992 to install
fuses in the LSI panels to provide electrical isolation between
fire zones.
The fuse installation and power feeds to the
panels
are similar for both units.
The LSI panels
located
in Unit l(2) receive their normal
power from Unit l(2).
The
alternate
power source
comes
from Unit 2(l).
Procedure
12
OHP 4023.100.001,
"Emergency
Remote Shutdown," provided
the operator with steps
necessary
to switch from normal to
alternate
power sources.
Power transfer switches
were located
in panels
LSI-4 (supplied power to LSI-3), LSI-5 (supplied
power to LSI-l), and LSI-6 (supplied power to LSI-2).
The
fuses installed were lE qualified.
The design maintained
an
adequate
fuse to fuse amperage
coordination
(2 to 1).
The
inspectors
requested
the coordinating curves for the 10a fuse
to the 20a feeder breaker
on 1/25/88.
The licensee
had not
verified the adequacy of the fuse-breaker
coordination.
The
licensee
informed the inspector
on 1/27/88 that the
10a fuse
to breaker coordination
was not adequate:
This effectively
placed the LSI panels in a similar configuration as initially
identified on ll/9/87.
Failure to apply adequate
design
control measures
for verifying the adequacy of the design
(fuse to breaker coordination) is considered
an example of a
potential Violation of 10 CFR 50, Appendix
B Criterion III.
The licensee
has
conducted training for the Electrical
Generation
Section - Nuclear
(EGS-N)
on properly addressing
Appendix
R requirements
during design reviews.
The operators
were notified of the previously discussed
electrical deficiencies
in Information Review Package
IN-R-0188.
The information adequately
described
the finding, discussed
how
a fire could result in the loss of redundant control
room
indication and described
the corrective actions
(fuse addition).
(4)
The inspectors
evaluated
LER 87023 for meeting the time limit
for reporting as required
by 10 CFR 50.73(d).
The event date
was
November 9,
1987 as stated in the
LER.
The licensee
performed several
evaluations
of this event prior to
determining the event
was reportable
on December
22,
1987.
The report date
was determined to be January
21,
1988.
Supplement
No. 1, (Licensee
Event Report System)
recommends
that the
LER text include
a discussion
on the reason
for having
a significant length of time (>30 days)
between
the event
and reportability date.
The licensee
did not
include this discussion
in LER 87023,
Revision 0.'he
licensee
was notified of this, discontinuity by phone
on
February 3, 1988.
The licensee
committed to submit
a
supplement to the
LER by February
17, 1988,
and to address
the reason
for the delay (>30 days)
between the event
and
reportability date.
This
LER will remain
open pending further
review.
b.
(Closed)
LER (315/87020):
Deficient design which could have caused
insufficient breaker interrupting capability between
Balance of
Plant
(BOP) and Essential
Safety System
(ESS)
250
VDC loads for
Unit One and Unit Two.
On September
17, 1987, during a review of an internal Safety System
Functional
Inspection '(SSFI)
on the auxiliary feedwater
system
(EIIS/BA), it was determined that in the event of a fault in certain
BOP cables
(EIIS/CBL), which would involve distribution panels
from
both independent trains,
a loss of control power on both independent
trains of related
ESS distribution panels
could occur.
The following distribution panels
(EIIS/BL) utilize electrical
circuit breakers
(EIIS/BKR) manufactured
by the Heinemann Electric
Company (Series
0441).
Unit 1:
Train A 1-CCV-CD '-SSV-A1, 1-SSV-A2
Train
B 1-CCV-AB
1-SSV-B
Unit 2:
Train A 2-CCV-CD
Train
B 2-CCV-AB
2-SSV-A1,
2-SSV-A2
2-SSV-B
The breakers
are
used for 250
VDC service.
It was discovered that
the interrupting capability of the Heinemann breakers,
as
used for
D.C.
Cook, is not specified
by the manufacturer at 250
VDC.
Furthermore,
with the specified lower voltage
(125 VDC) interrupting
curves (trip current vs. time),
a comparison of the breakers
with
their upstream
fuses
(Gould-Shawmut Trionic, or Bussman
FRN)
(EIIS/FU) indicated
a lack of coordination for fault currents
above
approximately
1500
amps.
Investigation concluded that this
condition has existed since the initial startup of the units.
10
The design of D.C.
Cook plants
complies with the separation
requirements
of Safety Guide 1. 75 as applied to Class lE
equipment
and circuitry.
The design
and installation criteria
was
implemented
by design specification
DCCEE-627-gCN,
"Electrical Design
and Installation Criteria for Reactor
Protection
and Engineered
Safeguards
Cable Systems."
cables
may be run in the
same trough with ESS cables provided
the separation criteria for BOP cables
has
been
met.
In this
case,
BOP loads were added to safety-related
DC busses
with an
assumed
adequate
breaker coordination with the 100
amp feeder
fuse.
It was
assumed
that
a
BOP fault would open the breaker
and not the feeder fuse.
Once breaker-fuse
coordination
had been achieved,
a
BOP cable could then be run in conduit or
cable trough with properly coordinated
BOP cables that were fed
from the redundant
DC bus; provided, the
BOP cables
were
no
longer routed in a safeguard
trough.
The licensee
determined that the Heinemann
breakers
could
interrupt
a fault current
up to approximately
1500 amperes.
It
was determined that this fault current protection would begin
at approximately
50 feet of cable length from the breaker.
The
ESS load feeder fuse could have opened
on a fault, given the
wiring fault had occurred within 50 feet of the breaker.
The
licensee
postulated this type of fault as being nonmechanistic
(unlikely to happen)
because
the inadequate
coordination
involved both safety trains.
ESS loads which may have
been
affected were certain containment isolation valves,
reactor
head vent valves, post-accident
sampling valves,
and steam
generator
stop valve
dump valves.
As corrective action,
the licensee
removed all
BOP cables
from
ESS cabinets
SSV-Al and
SSV-B for both units.
The design
added
a 35a lE fuse to lE cabinet
SCP.
The 35a fuse supplies
the
loads
and the coordination is acceptable
with the 100a
ESS
feeder fuse
(h2 to 1 amperage ratio).
The inspector
found the
installation
was performed adequately
and the correct fuse
.(35a)
was installed.
Even though the licensee identified and corrected this
miscoordination deficiency, this is an additional
example
of failure to apply adequate
design control measures
for
verifying the adequacy of design.
This is considered
an
example
of- a potential violation of 10 CFR 50 Appendix B,
Criterion III.
(2)
Coordination Studies
The licensee
has performed
a Vital AC and
DC bus coordination
study to support Appendix
R requirements.
The inspectors
did
not review these studies.
However, the inspectors
asked the
licensee
to re-examine
the
DC study and determine if the
250
VDC miscoordination
could have
been identified ear lier.
The response
was that the
DC Appendix
R study addressed
fault
currents at the actuated
equipment
end of the cable.
Typical
fault currents
were 149 amperes;
therefore,
the coordination
study appeared
adequate.
The licensee
indicated they were
preparing to re-examine all the vital bus coordination studies.
(3)
Safet
Si nificance
The actual safety significance
appeared
to be small.
For a
safety problem to have existed,
BOP cables
from related panels
would have
had to completely fail and interact simultaneously
with an accident which would have required the affected
ESS
equipment to function.
The
ESS loads that would have
been affected were certain
containment isolation valves,
reactor
head vent valves,
post-accident
sampling valves,
and steam generator
stop valve
(MSIV) dump valves.
All of the valves would have failed to
their safe position (i.e., closed) or would have already
been
closed,
except for the MSIV dump valves.
Each
MSIV has
two redundant
dump valves.
Each valve receives
power from a separate
ESS 250
VDC bus.
The energization
(ESF
Phase
B isolation) of either
dump valve will initiate fast
closure of its associated
MSIV.
The postulated
nonmechanistic
failure of the
DC busses
could prevent the fast closure of the
valves.
However, the MSIVs'ould have
been closed through their
hydraulic closure
mechanism.
Controls for the hydraulic
closures
were located in the control
room and were powered
from the
600
VAC Auxiliary Bus.
The inspector
reviewed the operating procedures
that would be
used to identify and respond to an uncontrolled-depressurization
of all steam generators.
The following procedures
were
reviewed:
1-OHP 4023.001.005
Steam Line Break (1981)
(procedure
superseded
by the following)
1-OHP 4023. E-0
Reactor Trip or Safety Injection (1986)
1-OHP 4023.E-2
Faulted
Steam Generator Isolation (1986)
1-OHP 4023.ECA-2. 1
Uncontrolled Depressurization
of ALL
(1986)
(procedures
are similar for Unit 2)
12
All of the above procedures
provided instructions to the
operator
on how to identify and respond to MSIVs that failed to
automatically close
on
a Phase
B isolation signal.
It appears
that the licensee
had adequate
procedures
in place to mitigate
the consequences
of a steam line break without fast closure of
the MSIVs.
=-
The inspectors
have
no further concerns
in this area.
C.
(Open)
LER (315/87022):
Potential violation of ESF instrumentation
limiting conditions for operation tolerances
due to Foxboro pressure
transmitter calibration shifts.
These transmitters
were installed
in 1985 for Unit One and
1986 for Unit Two.
Preliminary review of
the last calibrations
determined that there were
24 instances
of
calibration shift on Unit One, with four of these possibly
due to a
calibration error.
Also, two transmitters
were replaced.
Unit Two
experienced
25 instances
of calibration shift with one transmitter
being replaced.
Interviews with instrument
and control technicians
indicated that
Foxboro transmitters typically experience
some calibration shifts
during their first calibration interval
due to the mechanical
zero
and span
mechanism.
Once the transmitters
find a mechanical
equilibrium point (from use),
the technicians
indicated the
transmitters
were stable.
Many of the technicians
had previous experience with existing
Foxboro transmitters.
The new transmitters
work in a similar
manner.
The technicians
gained additional
experience
with the
new transmitters prior to their installation by performing bench
calibrations.
The calibration shift does
not appear to be training
related.
The licensee
committed to submit supplemental
information.
This
will include
a complete analysis of the event
and any corrective
actions to be implemented to reduce the calibration shift.
This
LER will remain
open pending further review.
No other violations or deviations
were identified.
Exit Interviews
The inspectors
met with licensee
representatives
(denoted in Paragraph
1)
on January
28,
1988 to discuss
the scope
and preliminary findings of the
inspection.
A followup meeting
was held with licensee
representatives
(denoted in Paragraph
1) via telecon
on February 3, 1988.
A final
exit meeting
was held with licensee
representatives
(denoted in
Paragraph
1) via telecon
on March 2, 1988.
The licensee
stated that
the likely content of the report would contain
no proprietary information.
13
l