ML17311A674
| ML17311A674 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 02/22/1995 |
| From: | Wong H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML17311A673 | List: |
| References | |
| 50-528-94-37, 50-529-94-37, 50-530-94-37, NUDOCS 9503010293 | |
| Download: ML17311A674 (44) | |
See also: IR 05000528/1994037
Text
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APPENDIX A
U.S.
NUCLEAR REGULATORY COMMISSION
REGION IV
Inspection
Report:
50-528/94-37
50-529/94-37
50-530/94-37
Licenses:
NPF-51
Licensee:
Arizona Public Service
Company
P.O.
Box 53999
Phoenix,
Facility Name:
Palo Verde Nuclear Generating Station,
Units 1,
2,
and
3
Inspection At:
Maricopa County, Arizona
Inspection
Conducted:
December
1,
1994,
through January
14,
1995
Inspectors:
K. Johnston
H.
Freeman
J.
Kramer
A. MacDougall
D. Garcia
Senior Resident
Inspector
Resident
Inspector
Resident
Inspector
Resident
Inspector
Resident
Inspector
South
Texas Project
Approved:
ng,
C
>e
,
eacto
roJects
Branc
~ z~/~s-
ate
Ins ection
Summar
Areas
Ins ected
Units
1
2
and
3
Routine,
announced
inspection of plant
status,
onsite
response
to events,
operational
safety verification,
maintenance
and surveillance
observations,
operations
and engineering
followup, and licensee
event report
(LER) review.
Results
Units
1
2
and
3
0 erations
Inspectors
continued to note
improvements
in the conduct of operations
in all
three units.
For example,
an attentive auxiliary operator identified
a small
crack on
an emergency diesel
generator
(EDG) intake manifold and the licensee
appropriately
performed
an operability evaluation of the manifold leak and
concluded that the diesel
was operable
(Section 2.4)..
Operations
personnel
also responded
promptly,to
a leaking pressurizer
spray valve (Section 2.6).
However,
a minor weakness
was noted in that Unit 3 operators failed to
9503010293
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ADOCK 05000528
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independently verify the position of the essential
chiller disconnects
as
required
by procedure
(Section 2.3).
Maintenance
Overall, inspectors
noted
improvements
in maintenance activities which appear
to reflect management
attention to work in the field and to plant material
condition.
For example:
~
A test of 'the essential
ventilation system,
to develop filter
replacement criteria in support of the licensee's
implementation of the
revised maintenance
rule, identified
a low flow condition that would not
have
been identified otherwise
(Section 2.2).
The good maintenance
practices
and supervision
were observed
during the troubleshooting,
repair,
and testing of an atmospheric
dump valve (Section 3.3
and 4).
The licensee
has noticeably
improved the material condition of the
EDGs, but longstanding deficiencies
in the nonsafety-related
diesel trip system contributed to extended unavailability
(Section 3.2).
Continued minor weaknesses
in the area of work instruction quality and
procedural
adherence
were noted
by the inspectors.
In one instance,
an
unnecessary
instruction to check for hydrogen
gas
when breaching the charging
system
was ignored
by the maintenance
personnel.
This demonstrated
the lack
of a thorough work package
review by both the maintenance
team leader
and
maintenance
worker (Section 3. I).
En ineerin
Engineering followup of some issues
was very thorough,
although
some
NRC
prompting was required to assure
timely resolution.
Examples of thorough
engineering
followup included the review of a misassembled
snubber in Unit 3
to assure this was
an isolated deficiency (Section
6)
and the review of NRC
Information Notice (IN) 94-60 regarding
power limits with inoperable
main
steam safety valves which identified
a weakness
in their accident
analyses
as
well as
a potentially generic issue
(Section
5. 1).
However, the timeliness of
the accident
analyses
review was left as
an unresolved
item, pending further
review.
Engineering troubleshooting
on the Unit 3 turbine-driven auxiliary feedwater
pump
(TDAFWP) was not well controlled.
The success
of the troubleshooting
effort was largely attributed to the direct involvement of senior engineering
management.
While this demonstrated
an appropriate
level of work oversight,
it highlighted
a weakness
in engineering
troubleshooting
processes
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Summar
of Ins ection Findin s:
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One inspection followup item was noted in Section 3.2.
~
One unresolved
item was identified concerning
the licensee's
evaluation
of NRC Information Notice 94-60 addressing
power operation with main
steam safety valves
gagged
(Section
5. 1).
Violation 530/9416-04,
concerning
the bent
EDG connecting rod,
and
Violation 529/9420-05,
concerning
the failure to follow procedures
for a
10 CFR 50.59 evaluation,
wer e closed
(Section 7).
Revision 0,
was closed
(Section 8).
LERs 528/94-08,
Revision 0, 529/94-03,
Revision 0,
and 529/94-04,
Revision 0, were
closed
(Section 9).
Attachments:
~
Attachment
1 - Persons
Contacted
and Exit Meeting
~
Attachment
2 - List of Acronyms
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DETAILS
1
PLANT STATUS
1.1
Unit
1
Unit
1 began the inspection period in Hode
1 at approximately
18 percent
power.
The unit had completed repairs to
a leaking pressurizer
vent valve at
the end of the previous inspection period
and was conducting
power ascension
to full power.
On December
2,
1994,
the unit reached
98 percent.
On December
14, there
was
a major grid disturbance
in central California.
At
approximately
1:30 a.m.,
the grid frequency lowered to around
59 hertz
and
resulted
in load swings of a maximum of 100 megawatts for about
7 minutes.
During the event,
control
systems
responded
as designed,
no equipment
damage
occurred,
and
no other operator actions
were required.
On December
19, the licensee
implemented
a Technical Specification
(TS)
change,
which raised the
maximum allowed power from 98.2 percent to 100
percent with one main steam safety relief valve inoperable
in each generator,
and then raised
power to 100 percent.
The unit remained at essentially
100 percent
power until commencing
on January
14 for steam
generator
(SG) chemistry hideout return.
The unit ended the inspection period
at
70 percent.
Power was increased
to 100 percent the following day.
1.2
Unit 2
Unit 2 operated
throughout the inspection period at essentially
100 percent
power.
On December
10,
a partial loss of control
room annunciators
occurred
when
a power supply to the annunciator
system failed.
The annunciators
were
restored within 15 minutes
(Section 2.1).
The California grid disturbance
affected Unit 2 as in Unit 1.
1.3
Unit 3
Unit 3 began the inspection period in Hode
5 for a
SG tube inspection.
On
December
17, the unit entered
Hode 2,
and
began
power ascension
to 100 percent
power.
The unit remained
at essentially
100 percent
power through the
remainder of this inspection period.
2
OPERATIONAL SAFETY VERIFICATION
(71707)
2. 1
Partial
Loss of Control
Room Annunciators
Unit 2
On December
10,
1994, at about 9:46 a.m., technicians
were performing
corrective maintenance
in one of the power supply cabinets for the control
room annunciator
system in Unit 2.
While removing
a circuit card,
one of the
technicians
dropped
a flat washer into
a power supply inverter.
This caused
the failure of the inverter
and blew the fuse for the inverter backup
power
supply.
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When the fault occurred,
control
room operators
received
an annunciator
power
supply trouble alarm and several
alarm conditions:
emergency
safeguards
features
(ESF) equipment
and chemical
and volume control
system
equipment
alarm windows;
systems
alarm windows were in fast flash;
and
turbine generator,
auxiliary systems,
and the turbine trip first out had all
alarm windows out.
These
alarms
would not respond to any control
board
push
buttons
and were considered
About one-half of the control
room alarm panels
were available to the
operators;
and the plant monitoring system,
safety equipment status
system,
emergency
response
data acquisition
system,
and quality safety parameter
display system were operable.
The operators
implemented the "Loss of
abnormal
procedure
and reviewed the plant TS, event reporting
manual,
and emergency
plan
and determined that
no event classification
was
required.
At about
10:08 a.m., technicians
replaced
the blown fuse
and
restored
the control
room annunciator
system.
The inspector
reviewed applicable
procedures
and determined that the operators
"appropriately followed plant procedures
and that safety-related
equipment
remained
The inspector also met with the maintenance
engineer
and
determined that the system
responded
as expected
when the inverter
and backup
power supply fuse failed.
The maintenance
engineer initiated
a condition
report/disposition
request
(CRDR) which included
a corrective action to
install
a guard
around the inverters to minimize the potential for similar
events.
The inspector
concluded that these
actions
were appropriate.
2.2
ESF Switch ear
Room Essential
Ventilation Air Handlin
Unit Testin
Unit
1
On January
6,
1994, during testing,
the licensee
found that the
ESF switchgear
room essential
Air Handling Unit (AHU), HJA-Z03,
was not supplying the design
air flow of 4100 standard
cubic feet per minute to the 4160 volt safety-
related switchgear
rooms.
The system engineer
had developed
a special test to
determine
the differential pressure
across
the intake filter that would
prevent the
AHU (HJA-Z03) from supplying the design basis air flow.
This
information would then
be used
as the basis for periodically replacing the
filters.
When the engineers
started
the test the indicated flow was only 2900
standard
cubic feet per minute without any obstruction
across
the intake
filter.
The shift supervisor
immediately declared
the
'Although the
AHU is not specifically included in the plant TSs, it was required to be
operable to support operability of the Train A 4160 volt safety-related
load
center.
The licensee's
administrative controls required the
AHU to be
returned to an operable
status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or the affected
4160 volt load
center
be declared
The inspector
reviewed the licensee's
procedures
and
TSs
and concluded that the licensee
appropriately controlled
operability of the
AHU.
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The licensee
conducted
a detailed
walkdown of the ventilation lineup and found
the return supply damper for the
AHU only 10 percent
open
(normal position is
100 percent
open).
Technicians
found that
a nut had
come loose
and allowed
the damper to close to the
10 percent
open position.
The damper
was
repositioned,
the air flow retested,
and the
AHU was declared
The
site shift manager verified that the supply damper for the Unit
1 Train
8
switchgear
room essential
AHU and both trains of the Unit 2 and
3
switchgear
room essential
AHUs were in the
100 percent
open position.
The licensee initiated
a root cause of failure CRDR.
The inspector
concluded
that the licensee
appropriately restored operability of the
ESF switchgear
room essential
AHUs and corrected
the immediate safety concern.
The inspector
will review the licensee's
investigation of this event during
a future
inspection.
2.3
Inde endent Verification Unit 3
During
a review of the essential
chill water system
on January
13,
1995, the
inspector
noted that the licensee failed to perform the independent
verification of the essential
chiller disconnects
as required
by procedure.
The inspector notified the shift supervisor of the problem.
The shift
supervisor dispatched
an operator to verify that the disconnects
were closed.
Subsequent
review identified that
an open disconnect situation would have
been
alarmed in the control
room.
There were
no such alarms at the time.
The licensee
performed sections of Procedure
430P-3ECOl/2,
"Essential
Chilled
Water Train A/B," for the chemistry department
to draw
a weekly sample of the
The procedure,
in part, required the operators
to
open the disconnects,
start the circulating water
pump, close the disconnects,
and independently verify the disconnects
were closed.
The inspector
noted in
a review of procedure
records that
on two occasions,
Unit 3 operators
had
failed to perform the independent verification.
The licensee
performed several
corrective actions.
The shift supervisor
directed
an operator
to check the disconnect positions.
They were in the
appropriate positions.
The licensee
issued
a night order to the operations
personnel
emphasizing
the requirement to perform independent verifications.
In addition, the licensee initiated
a
CRDR to evaluate
the problem.
The inspector
concluded that the licensee
performed
adequate
corrective
actions.
The inspector
noted that the operators
would receive several
control
room alarms if the disconnects
were left open.
The lack of alarms
provided
the operators
an indication that the disconnects
were closed although
an
independent verification was not performed.
Therefore,
the inspector
concluded that the failure to follow procedure
was of minor significance.
The inspector
noted that
a recent trend analysis
performed
by Nuclear
Assurance identified that instances
of equipment
and valve misalignments
were
substantially greater
in Unit 3 than the other two units.
In response
to
these findings, Unit 3 operations
management
was taking action to improve
performance.
The example
noted in this section
would tend to support the
performance
trend identified by Nuclear Assurance.
2.4
Unit I
While performing
a routine surveillance test
(ST)
on
27,
1994,
an auxiliary operator
noted what appeared
to be
a cracked weld on the
number four right cylinder intake manifold.
The hairline crack was
approximately 3/4 inches
long that ran across
The
crack was apparently
"through-wall" which caused
a barely detectable air leak
while the
EDG was operating.
The licensee
conducted
an operability evaluation
and concluded that the crack did not affect the operability of the
EDG.
On December
28, the inspector
observed
the cracked weld.
The inspector noted
that the crack was across
the weld.
This weld joined the cylinder head
bolting flange to
a square
section of pipe (approximately
6 x 6 inches)
which
provided forced air from the intake plenum.
The inspector
noted that the weld
appeared
to be old,
due to some oxidation indications in and around the weld.
The inspector concluded that the crack did not appear to be propagating
and
did not appear to affect the structural integrity of the manifold.
The inspector
reviewed the licensee's
The
inspector
noted that the licensee's
inspection of the crack included
a
certified level III visual weld inspector.
The level III inspector,
and
engineering
and maintenance
personnel
concluded that the crack was
insignificant.
The licensee
also concluded that if the weld failed
circumferentially 360 degrees
around the pipe (unlikely due to crack
orientation),
the other nine intake flange welds were sufficient to support
the intake plenum and that the
The inspector
concluded that the licensee
took the appropriate
steps to ensure
that the deficiency did not affect the operability of the
EDG.
The inspector
agreed with the licensee's
conclusion that the crack was insignificant and did
not affect the operability of the
EDG.
Finally, the inspector concluded that
the auxiliary operator
had done
an excellent job in identifying and notifying
manag'ement
of the presence
of the crack.
2.5
EDG Material Condition - Units I
2 and
3
Throughout the inspection period, the inspectors
noted improving material
conditions of the
EDGs in all three units.
The inspectors
noted that, in some
cases,
all of the standing oil and the oil absorbent
devices
had
been
removed.
In previous inspections,
inspectors
had noted
numerous oil leaks
and
30 or
more different oil absorbent
devices
saturated
with oil on one diesel
alone.
At the exit meeting,
the Director of Maintenance
mentioned that they had
targeted
the deficiencies of the diesels
and that they would continue to
improve the material conditions.
The inspectors
concluded that the licensee
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was making good progress
in correcting minor deficiencies,
such
as oil and
cooling water leaks,
in an effort to improve the material conditions of the
EDGs.
2,6
Pressurizer
S ra
Valve Leaka
e - Unit 2
On December
21,
1994, operations
determined that
one of two pressurizer
spray
valves in Unit 2 had developed
a
6 gallon per minute packing leak.
Operators
entered
the containment
and isolated the spray valve which stopped
the leak.
Repairs
were planned for the Unit 2 refueling outage
scheduled
to begin
February 4,
1995.
Operations
demonstrated
prompt response
to the leakage
indication.
3
MAINTENANCE OBSERVATIONS
(62703)
3, 1
Char in
Pum
Packin
Re lacement - Unit 2
On January
5,
1995,
the inspector
observed
mechanical
maintenance
technicians
install
new packing
on the plungers of charging
Pump
A in Unit 2.
The work
was being performed using model work Procedure
"Charging
Pump
Disassembly
and Assembly."
The inspector
observed
good radiological
protection work practices
by the mechanics
and good oversight of the activity
by an
RP technician.
The inspector
noted that the model work instructions
were detailed
and technically accurate.
The inspector
noted that the procedure
had
a step to perform
a hydrogen
gas
check when the system
was breached if directed
by the team leader.
The
inspector determined'hat
the lead mechanic
had not received instructions
from
the team leader concerning the hydrogen
check
and subsequently
did not perform
the check when the system
was breached.
In discussions,
the team leader
stated that
he reviewed the work order,
but did not notice the step to perform
the hydrogen
gas check.
The inspector
noted that the licensee
did not historically have
any problems
with excessive
gas in the charging
system
and that the failure to
perform the step
had low safety significance.
However, the inspector
was
concerned
that the team leader
and the lead mechanic did not thoroughly review
the work procedure.
The inspector discussed
the problem with the mechanical
maintenance
department
leader
who agreed that the prejob briefing did not meet management's
expectations.
The licensee's
corrective actions
included reinforcing the need
to conduct thorough prejob briefings especially
when the team members
had not
recently worked
on
a particular system.
The licensee
also decided that the
step to perform the leak check was not necessary
and
removed the step from the
procedure.
The inspector
concluded that the licensee's
response
was
appropriate.
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3.2
Multi le
EDG Tri
s
Unit 2
On December
14,
1994, the Unit 2
B was started
in the emergency
mode
and
satisfactorily loaded for a monthly ST.
After the
EDG was unloaded for the
engine
cooldown,
the surveillance
procedure
required that the emergency
mode
interlock defeat
switch
be placed in the off position which enabled
the test
mode trip circuitry.
When the operator
moved the switch to the off position,
the incomplete
sequence
alarm momentarily
came in and the
EDG tripped.
Operators
declared
the
and the maintenance
engineers
developed
a troubleshooting
plan.
The inspector
observed electrical
maintenance
engineering
troubleshoot
the
test
mode circuitry.
The engineers
suspected
that
some relays must have
opened
long enough to cause
the trip solenoid to deenergize.
The technicians
removed the most probable relays
and found two normally energized
relays with
open contacts that would not pick up.
On December
15, after replacing the faulty relays,
operators
started
the
in the test
mode to perform
a maintenance
run.
During the test run, the
tripped during the cooldown cycle
on
an indicated high jacket water
temperature
alarm.
The technicians
suspected
the problem was in the
nonsafety-related
pneumatic trip circuitry.
The technicians
found air leaks
in the check valve associated
with the high jacket water temperature
alarm
and
the temperature trip valve.
These
components
were replaced
and the
EDG was
again started
in the test
mode
and immediately tripped
on incomplete
sequence
since it did not reach rated
speed.
The technicians
found
some minor air
leaks
and
a leaking check valve that was replaced.
On December
16, the
EDG was successfully started
in the test
mode.
During the
cooldown cycle, the
EDG tripped
on
an indicated
low turbocharger
pressure
alarm.
The technicians
found
a piece of debris in the check valve
associated
with the low turbocharger
lube oil pressure
alarm.
The debris
damaged
the seat of the check valve
and caused it to leak.
The technicians
replaced
the check valve and successfully
started
the
EDG in the test
mode.
The
EDG would not stop after completion of the cooldown cycle
and would not
shutdown
when the emergency
pushbutton
was depressed.
The
EDG was stopped
by
manually tripping the fuel racks.
The licensee
suspected
the problem with the
EDG not stopping
was caused
by
sluggish operation of the pneumatic control valves.
Two control valves were
replaced
and the
EDG was successfully started
and shutdown in the test
mode.
During the evening of December
16, the
ST was satisfactorily completed
and the
EDG was restored
to an operable
status.
The inspector reviewed the troubleshooting
work orders,
the
EDG logs,
the
control
room logs,
and discussed
with the system engineer
the root cause of
failure analysis.
Based
on this review, the inspector
had the following
observations:
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All five of the problems
would not have prevented
the
EDG from starting
and
running in the emergency
mode.
However, the
EDG was unavailable
(would not
start
on
an emergency signal) for a total of 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> during the
troubleshooting activities.
The inspector
was concerned that having the
EDG unavailable for this period of time increased
the vulnerability of the
plant.
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Engineering
had previously developed
an action plan to reduce the number of
EDG test
mode trips.
The corrective actions
included replacing
continuously energized
Agastat relays every
10 years
and replacing the
check valves with an improved check valve that had better seating
characteristics
and
an internal filter.
These
improvements
were scheduled
for installation during the Unit 2 refueling outage in February
1995.
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The licensee's
performance. during the troubleshooting efforts may have
been
inconsistent.
The inspector
observed
good troubleshooting
and work
practices
during the first problem with the relays.
However,
one of the
leaking checks
valves
may have
been
caused
by debris introduced into the
air system during replacement
of an earlier check valve.
Additionally, the
cause of one event
was not fully corrected
and
may have subsequently
caused
the problem with not being able to stop the
EDG.
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The performance of the 8-hour surveillance
requirement to check the offsite
power sources
with an inoperable
EOG were not consistently
documented
in
the unit log.
However, the procedure
used to perform the
ST was correctly
completed
every
8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />
as required
by the plant TS.
The licensee
issued
a
night order emphasizing
management's
expectation that compliance with TS
action statements
be documented
in the unit log.
The inspector
concluded
that these
actions
were appropriate.
At the
same time the inspector
was raising questions
regarding the cool-down
cycle trips, the licensee
was also reviewing these
events.
The licensee
initiated
a root cause of failure
CRDR for the multiple failures.
The
Director of Engineering
also raised the priority of the effort to reduce the
number of test
mode
EOG trips to level
1 action plan (highest priority) to
include the experience
of the
EDGs in all three units.
The inspector will
review the licensee's
formal root cause
evaluation
and corrective actions
during
a future inspection
(Followup Item 529/9437-01).
3.3
Atmos heric
Dum
Valve
ADV
Maintenance
Unit 3
During routine
ST of the ADV-185 in Unit 3, technicians
noticed that the valve
was making
a "popping" noise in the closed direction.
The licensee
suspected
that the noise
was coming from the valve actuator
and rebuilt the valve
operator.
During the retest,
the valve continued to make the popping noise
'and its stroke time placed it in the enhanced
monitoring range.
The licensee
then suspected
a problem internal to the valve and disassembled
the valve on
t
December
15.
On December
19, the valve was reassembled
and successfully
retested.
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The inspector
reviewed the vendor technical
manual
(VTH) and model work
Procedure
"ADV Disassembly
and Assembly."
The inspector
noted
that all the critical acceptance
criteria in the
VTH were included in the
procedure.
The inspector
noted that the model
procedure
used
a different type
and arrangement
of packing rings than described
in the
VTH.
The system
engineer
stated that engineering
had done
an evaluation to include the
ADVs in
the licensee's
valve packing program.
The inspector
noted that the work order
had
a step to repack the valve per the valve .packing installation procedure
and referenced
the engineering
evaluation.
The inspector
concluded that
engineering
had
a good basis for using
a different packing arrangement
and
that the model work instructions
were thorough
and technically accurate.
The inspector
observed
mechanical
maintenance
personnel
disassemble
the valve
on December
15.
The inspector noted
good supervision
in the field and good
work practices
by the mechanics.
The maintenance
engineer
conducted
a
detailed review of the parts
and thought that the valve piston
may have
been
periodically hanging
up on the piston rings.
The piston rings were slightly
worn at the split which caused
increased friction at the location of the ring
split.
The engineer
suspected
that the piston ring wear resulted
when the
valve was stroked several
times during the testing in November
1994.
Testing
is typically performed with an upstream isolation valve closed,
isolating
steam which acts to lubricate the ri,ngs.
The mechanical
maintenance
engineer initiated
a
CRDR to document the root
cause of failure.
As
a corrective action, the engineers
were considering
putting
a caution in the procedure for adjusting the valve positioner that
would require water to be injected into the valve bonnet in cases
of multiple
strokes without steam.
The inspector
concluded that the licensee's initial
corrective actions
were appropriate.
3.4
Other Haintenance
Observed
~
Haintenance
of medium voltage circuit breakers
Type AH-4.16-250
Unit
1
~
Electrical design
change
on the 4. 16
kV bus breakers - Unit
1
~
New fuel receipt - Unit 2
~
Installation of new
AC input supply circuit breaker for the "D" battery
charger - Unit 2
4
SURVEILLANCE OBSERVATIONS
(61726)
ADV Testin
Unit 3
On December
19,
1994, the inspector
observed
a 100 percent stroke test of an
ADV from the control
room.
The licensee
performed
"Testing
ADV's in Node 1," Section 8.7.
The inspector
observed
good
command
and
control of the evolution by the control
room staff.
The inspector
noted
good
f
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f
-12-
communications
between
the control
room operators
and the operators
at the
ADV.
The inspector
noted the coordination
between
the control
room operators
minimized plant perturbations
during the stroke test.
The test
was conducted
successfully.
The inspector
concluded operations
exhibited
a strong
performance
throughout the test.
5
ONSITE ENGINEERING
(37551)
5.1
NRC IN 94-60:
Power
0 eration with Main Steam Safet
Valves
HSSV
~Ga
ed
The inspector
conducted
a review to determine if the licensee
had evaluated
NRC IN 94-60, "Potential Overpressurization
of Main Steam System,"
issued
on
August 22,
1994.
IN 94-60 discussed
a potential for overpressurizing
the main
steam
system during previously evaluated
accident
scenarios
when
one or more
HSSV was inoperable.
The inspector selected this IN to review because
Unit
1
was operating at 98 percent
power in compliance with TS due to having two
HSSVs.
The
IN discussed
that most plant
TS allow power operation with inoperable
MSSVs at
a power level that was equivalent to the capacity of the remaining
HSSVs.
The basis of this
TS assumes
that the maximum allowable initial power
level is
a linear function of HSSV capacity.
However,
determined
that the linear assumption for reducing
power levels with inoperable
HSSVs
was
nonconservative
and
may result in overpressurizing
the secondary
system during
accident
scenarios
with inoperable
The licensee's
operational
experience
review
(OER) group screened
the
IN as
applicable
in September
1994 since the basis for the
TS for power operation
with inoperable
HSSVs also
assumed
a linear reduction of power with HSSV
capacity.
The inspector
noted that the licensee
conducted
a preliminary
review of the condition addressed
in the
IN in October
1994.
The licensee
noted that the original safety evaluations of the loss of condenser
vacuum
(LOCV) accident concurrent with a total loss of feedwater
were performed with
all the
HSSVs operable
and did consider the potential of overpressurizing
the
secondary
system
when operating at the reduced
power levels with inoperable
The safety analysis
engineers
used the previously licensed
Combustion
Engineering
(CE) simulation of the
LOCV accident
and ran the program with up
to two inoperable
MSSVs in each
SG and determined that there
was
no
significant increase
in main steam pressures
with inoperable
HSSVs.
The
licensee
believed the condition in Unit
1 with two inoperable
HSSVs
was
acceptable
based
on this initial review.
The
OER group scheduled
a detailed
review of the
IN to be completed
by March 31,
1995.
The inspector
noted that the licensee
had submitted
a TS amendment
to allow
Unit
1 to operate
at
100 percent
power with the two inoperable
HSSVs.
The
inspector questioned
the licensee's
decision to not complete
a detailed,
formal evaluation of the concerns
in the
IN prior to completing the
TS
0
)
)
,
-13-
amendment.
Based
on the inspector's
concerns,
the
OER group moved
up the
review date for the
IN to December
31,
1994.
On December
14, the
TS amendment
for raising power to
100 percent
was issued
by the Nuclear Reactor Regulation
and Unit
1 returned to 100 percent.
In December
1994, after Unit
1 had increased
power to 100 percent,
safety
analysis
engineers
determined that although the previous
LOCV analysis
assumed
initial plant conditions
and parameters
that would generate
the most limiting
primary pressure,
these conditions did not assure
maximum secondary
pressure.
Additionally, the engineers
determined that
CE had not previously formally
evaluated
the'secondary
overpressurization
condition discussed
in the IN.
As a result,
the safety analysis
group changed
the initial plant conditions
and parameters
used in the
LOCV accident to increase
the heat transfer to the
and
make the secondary
side pressure
more limiting.
The analysis
was
performed for the condition in Unit
1 with two inoperable
and
was found
to be acceptable.
However, preliminary runs were performed for additional
HSSVs
and the potential for overpressurizing
the main steam
system
may occur at lower power levels with the maximum of four HSSVs in each
(as allowed by TS).
The inspector
reviewed the
IN and
had numerous
discussion
with the safety
analysis
engineers,
licensing engineers,
and the
OER group.
Based
on these
discussions
the inspector concluded that the licensee
had conducted
an
appropriate initial review of the concerns
addressed
in the IN.
Additionally,
the inspector
agreed with the licensee that operation in Unit
1 at
100 percent
power with two inoperable
HSSVs was not
a safety concern.
However, the
inspector
was concerned that the licensee
had not identified the incorrect
assumptions
with the
LOCV accident during the development of the
TS submittal
for returning to 100 percent
power with two inoperable
HSSVs.
The licensee initiated
a
CRDR to perform the detailed analysis of the
condition
and determine if any changes
to the
TS for inoperable
HSSVs
was
required.
The inspector will review the
CRDR during
a future inspection to
determine if the licensee
should
have discovered
the incorrect assumptions
in
the
LOCV accident simulation during the development of the
TS amendment
submittal
and confirm whether
a generic safety concern exists for secondary
overpressurization
events
(Unresolved
Item 528/9437-02).
5.2
TDAFWP Failure
Unit 3
On December
20,
1994, the inspector
observed
licensee
personnel
perform
portions of the work activity associated
with the investigation of an
overspeed trip of the Unit 3 TDAFWP.
On December
19, operators
noted low
TDAFWP steam supply line temperatures
and started
the
pump to raise the
temperature
in the line.
This action was taken in response
to the licensee's
analysis of previous
TDAFWP trips caused
by condensation
which had formed in
cold steam
supply lines.
In accordance
with operating
procedures,
operators
started
the
TDAFWP by opening valves in one
steam supply.
The
pump started
as
!
I
I
l
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1
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~
designed,
and operators
opened
valves in the second
steam supply line.
The
TDAFWP began to overspeed,
and subsequently
tripped.
Operators
declared
the
TDAFWP inoperable,
the unit entered
a 72-hour
TS action
statement,
and
a
CRDR was initiated.
An investigation
team assembled
to
determine the root cause of the
TDAFWP trip.
The team
was led by system
engineering
personnel.
On December
20, the inspector
observed
the team
members
as they participated in collecting
and verifying data
and facts.
The inspector
observed
good communication techniques
between the different
organizations.
The investigation
team developed
an action plan to recreate
the scenario of
December
19.
The steam piping low points were purged of condensation,
and
initial testing revealed that previous condensation
buildup in the horizontal
section just upstream of a check Valve (SG-V43) upstream of the steam supply
line header
was the cause for the turbine to trip on overspeed.
However, the
performance of the governor valve remained
in question
and the team determined
that further testing in the presence
of a representative
from the governor
valve vendor was warranted.
On December
21, another action plan was developed
to start the
TDAFWP in the
same valve configuration with established
atmospheric
conditions.
Test
instrumentation
and strip chart recorders
were installed to record the turbine
responses.
An initial run of the
TDAFWP was aborted
due to an instrument fitting leak.
The horizontal section
upstream of the check Valve (SG-V43)
had higher steam
line temperatures
and, therefore,
the decision
was to remove
some of the
insulation to allow the piping to cool
down.
The inspector
noted that the Director of System Engineering
and
a system
engineering
team leader
were present
during this testing
and was involved in
ensuring that questions
regarding
personnel
overtime limits, approved
work
orders for removing the insulation,
and action plans for testing the
TDAFWP
were properly addressed.
The system engineering
team leader discussed
his hand written instructions for
resuming the test with the relief test coordinator
who had been involved with
the earlier testing.
A prejob briefing was held in the control
room with all
the personnel
involved in the testing of the
TDAFWP.
The prejob briefing was
presented
by the Director of System Engineering
using the handwritten
instructions to discuss
the evolutions that were going to take place.
While the inspector
found that the involvement of the director of site
engineering
indicated appropriate
management
attention to this testing,
the
inspector
observed that considerable direct involvement appeared
necessary
to
ensure that the troubleshooting effort was conducted properly.
The inspector
noted that the action plan lacked prerequisites,
precautions,
limitations,
and
contingency plans to insure that issues
such
as temperature
changes,
communications
between organizations,
and shift turnover were adequately
I
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f
0
-15-
addressed.
In addition,
the licensee
did not have instructions to provide
documentation of test parameters
or results.
The inspector discussed
these findings with the
Director of System
Engineering
who concurred that the testing
was not conducted
consistent
with
his expectations.
The
Director concluded that
a special test procedure
was
not appropriate for this test.
While the inspector
agreed that this testing
did not require the rigor of a special test procedure,
the testing involved
several disciplines,
extended
through shifts,
and involved configuration
control
issues
which warrant sufficient formality to assure effective
communication of the testing process.
A CRDR was initiated by site
engineering to review guidance for engineering
troubleshooting.
The inspector
will review the guidance
in a future inspection.
6
FOLLOWUP - HAINTENANCE
(92902)
Misassembled
Hechanical
Unit 3
In July 1994,
an
NRC inspector questioned
the performance of a mechanical
snubber installed
on
a Unit 3 auxiliary feedwater
pump steam trap line after
he found the snubber
would not rotate
on its pins.
Although an engineer
initially confirmed that the snubber
would not rotate,
during
a subsequent
inspection,
the snubber
was found to rotate
as expected.
On December
14,
1994, with Unit 3 transitioning from Mode
5 to Mode 4,
a
licensee
engineer
performed
a followup inspection
and noted that the cold
position of the snubber
was the
same
as the hot position
he had previously
observed.
The licensee
subsequently
discovered that the snubber
had
been
inappropriately
reworked
and misassembled.
The snubber,
which was
supposed
to
be
a 1/4 thousand-inch-pound
(kip) snubber,
had
been
assembled
with both 1/4
kip and 1/2 kip snubber parts.
The net result
was that the snubber
had
a
shorter stroke than design.
The licensee
replaced
the snubber.
The licensee
determined,
based
on documentation of testing during the
1992
Unit 3 refueling outage,
that this snubber
had
been intact when it was removed
from the system
and
had
been tested satisfactorily.
However,
a comparison of
the as-found
and as-left pin-to-pin dimensions
indicated that the reinstalled
snubber did not match the snubber
which had
been
removed.
This indicated that
the snubber
had
been modified after testing
and prior to reinstallation.
There
was
no documentation of a modification to the snubber
and the licensee
stated that it was not their practice to rework small
The inspector
determined that the snubber deficiency could not have
been
readily identified with the plant in Mode
1 and that the licensee's initial
review in response
to the July 1994 inspection finding has
been reasonable.
The inspector questioned
whether the licensee
had assurance
that this was
an
isolated
case.
The licensee
performed
walkdowns of a large
sample of 1/4 kip
and performed
a complete review of test documentation.
They
~
~
0
-16-
concluded that this had
been
an isolated
case.
The inspector
reviewed the
licensee's
efforts
and found them to be appropriate.
The licensee
subsequently
interviewed maintenance
personnel
involved in the
removal
and testing of the snubber in the
1992 refueling outage.
However,
personnel
involved in the outage
could not recall
a modification having
been
performed
and reiterated
the practice of discarding
1/4 and 1/2 kip snubbers
with deficiencies.
The licensee
was not able to contact
some contract
maintenance
workers which are
no longer working for the licensee.
The
inspector determined that the licensee
had performed
a reasonable
investigation of this matter.
The inspector questioned
whether
an evaluation
should
be performed to
determine the impact of the as-found condition of this snubber
on system
performance
during
a design
basis
event.
The snubber,
which was in its fully
extended position when installed with the steam line cold, would not have
allowed pipe movement
as the system
heated
up.
The licensee
evaluated
the
configuration
and found that the loading
on the line would not have
exceeded
the design basis.
The inspector
noted that the line was relatively long and
small in diameter,
providing considerable flexibility, which supports
the
licensee's
analysis.
Although the licensee
could not identify how the snubber
was misassembled,
corrective action
was taken to inform craft involved in snubber testing of the
misassembled
and to reiterate
the expectation that snubbers
of this
size are not to be reworked.
The inspector
found this action to be
appropriate.
7
FOLLOWUP - ENGINEERING
(92903)
7. 1
Closed
Violation 530 9416-04:
Bent
EDG Connectin
Rod - Unit 3
This violation was issued for failure to promptly identify and correct
a bent
connecting
rod in Cylinder 6-L of Unit 3
B which occurred during
a rocker
arm failure on July 28,
1993.
The licensee
noted
symptoms of the bent
connecting
rod on October 20,
1993,
but failed to identify the problem until
Harch 23,
1994.
The inspector reviewed the licensee's
investigation
and corrective actions
regarding the violation.
The licensee
concluded that the violation was caused
by failing to promptly validate assumptions
used in analyzing the indications
obtained
on October 20,
1993,
and
compounded
by poor communications
between
and within organizations.
Additionally, the licensee
concluded:
~
Some of management's
expectations
were not clearly communicated (i.e., to
challenge
assumptions
and follow issues to closure),
l
e
-17-
~
Communications
problems existed within and
between organizational
departments
leading to poor interaction or coordination of evaluation
findings,
~
Issues
were not followed to closure in a timely manner,
and
~
A self-critical attitude did not exist at all levels which led to
a less
aggressive
approach
to the problem.
The inspector
noted that the licensee's
findings of the root cause of the
violation were very similar to the
NRC findings related to this event
documented
in
NRC Special
Inspection 50-530/94-16.
The inspector
reviewed the licensee's
corrective actions of which the most
significant action involved the licensee's
reengineered
organization
which was
implemented
in August 1994.
Two of the contributing factors to the violation
were poor communications
and
a lack of management
involvement.
The
reengineer ed organization
now consists of teams for each
system that include
engineering,
maintenance,
and planning personnel.
The closer working
relationship
was intended to foster freer communications,
especially
between
the maintenance
engineers
and the maintenance craft.
NRC Inspection
Report
50-530/94-16
noted that the maintenance craft and planner suggested
to remove
the crank case
inspection
cover in December
1993,
but did not pursue
the
suggestion.
Additionally, the licensee
has
implemented
a daily meeting
between
department
leaders
and other senior managers
to discuss
plant status,
emerging issues,
daily maintenance
plans,
and other issues.
Engineering
issues/concerns
are
specifically addressed
once per week at these
meetings.
Also, important
issues that are identified by the licensee's
condition reporting
system
are
discussed
at the daily meeting.
By effectively using this meeting,
important
issues
can
be identified, prioritized and tracked
by senior management.
The
inspector
noted
improved communications
and more management
involvement since
implementation of the reengineered
organization.
Another change that was not specifically implemented
in response
to the
violation was the operability determination
Procedure
(40DP-90P26).
The
inspector
reviewed the procedure
and noted that it stated that,
"whenever the
ability of a structure,
system or component
(SSC) to perform its specified
function is called into question
by an indication of a potential deficiency
. then the operability of the
SSC shall
be determined
.
.
. Otherwise,
the
SSC should
be declared
In this case,
the licensee
concluded that
the
however,
the system engineer
was concerned
about the
long term reliability caused
by a potential deficiency.
The operability
procedure
would require deliberate
and timely actions to resolve the
engineer's
concern.
Finally,
NRC Inspection
Report 50-530/94-16
noted that the retest,
following
the rocker
arm rework in July 1993, consisted
only of a simple surveillance
I
l
-18-
run and failed to identify the degraded
condition caused
by the bent
connecting
rod.
The licensee
decided that to ensure that pertinent data
are
available for EDG operability determinations
following extensive
rework, that
a leak-down check
and
an engine analysis
would be required.
The inspector
reviewed the licensee's
postmaintenance
retest
development
procedure
and
verified that the procedure
required the inclusion of the specified tests.
The inspector
concluded that the actions
taken
by the licensee
were
appropriate.
7.2
Closed
Violation 50-529 9420-05:
Failure to Follow Procedures
for a
10 CFR 50.59 Evaluation
This violation involved the failure to follow procedures
when
screening
identified that TSs were affected
by
a design
change.
In this
instance,
the design
change
was
implemented
before
a
TS change
was submitted
and approved
by the
NRC.
The design
change
rerouted
the location of the
condenser
vacuum exhaust
and the affected
TS depicted the location of the
condenser
vacuum exhaust.
As corrective action, licensee
management clarified expectations
regarding
changes
to Tss
and the need for timeliness
in processing
change requests.
Also,
on November 2,
1994, the licensee
submitted
a
TS amendment
request
which
depicted the
new location for the condenser
vacuum exhaust.
The inspector concluded that the actions
taken
by the licensee
were
appropriate.
7.3
En ineerin
Res
onse to Overs
eed of Turbine-Driven
Pum
s Caused
b
Governor Valve Stem Bindin
NRC IN 94-66 documented
recent
problems regarding binding of governor valves
for turbine-driven
pumps that have resulted in overspeed trips.
On December
21,
1994, the inspector
reviewed internal licensee
memorandum
addressing
this
issue for all three units.
The inspector interviewed the system engineer
and
determined that the licensee
has taken appropriate
action to address
the
concern.
The inspector
was concerned with the recent
overspeed trip of the Unit 3
TDAFWP that occurred
on December
19 (Section 5.2).
The investigation
determined that the overspeed trip did not occur
as
a result of governor valve
stem binding.
As part of the investigation,
the linkage to the governor valve
had
been disconnected
from the servo motor and determined to have full freedom
of motion.
In addition, the vendor representative
inspected
the components
and found no discrepancies.
The governor valve stem
had just been replaced
in
the Unit 3
TDAFWP during the previous outage.
The inspector
noted that the licensee's
investigation to determine
whether
stem binding was occurring
was thorough
and exhaustive.
,~ l
.e
-19-
8
ONSITE REVIEW OF
LER
(92700)
Closed
LER 528 94-07
Revision 0:
Re uirement for
Containment
Pur
e Isolation Valves
This
LER was submitted
when the licensee identified that the thermal
overload
protection circuits had never
been verified to be bypassed
continuously or
under accident conditions per
TS Surveillance
Requirement 4.8.4.2. 1.
Two
containment
purge isolation valves
each isolate the intake
and the exhaust
lines for the containment
purge system.
The licensee
had discovered this
omission
on November
3,
1994, during
a design basis validation review.
The inspector
reviewed the actuation signals to these four isolation valves.
The inspector
noted that the valves receive
a containment isolation actuation
signal
and
a containment
purge isolation actuation
signal
(CPIAS).
The
licensee's
design
basis
review had revealed that the 18-month
ST that
had been
performed for Surveillance
Requirement 4.8.4.2.
1 had ensured that the thermal
overloads
were bypassed for a containment isolation actuation signal,
but had
not ensured this feature for a CPIAS (a different section of the
same
circuit).
The inspector
reviewed the Updated, Final Safety Analysis Report for the
consequences
of the containment
purge isolation valves not being operable.
The containment
purge
system
was designed to operate
only while shutdown,
and
the
CPIAS was intended to terminate the purge which would substantially
reduce
potential offsite radiological
exposures
in the event of a fuel handling
accident
in containment.
However, the radiological
consequences
of a fuel
handling accident
have
been calculated without assuming
CPIAS operation,
and
the offsite doses
are still a small fraction of 10 CFR Part 100 limits.
Therefore,
the inspector
concluded that the licensee's
failure to test the
thermal
overload
bypass feature for the
CPIAS was of low safety significance.
The inspector
reviewed the licensee's
corrective actions.
The inspector
noted
that the licensee
intended to include steps
in an operations
procedure to
ensure that the thermal
overload
was bypassed
during
a CPIAS.
The licensee
concluded that this would meet the once per 18-month requirement.
The
inspector
concluded that the intended corrective actions
were appropriate.
9
IN OFFICE REVIEW OF
LERS
(90712)
The following LER was closed following an in-office review in accordance
with
inspection
module 90712:
~
Revision 0,
TS Required
Shutdown to Repair Leaking
Pressurizer
Vent Path Valves.
4
-20-
~
Revision 0, Missed
TS
LCO Action for Monitoring Reactor
Coolant System
Boron Concentration
~
Revision 0, Class
lE Batteries
in a Degraded
Condition
10 DISPOSITIONED
LAMP COVERS
ON REMOTE SHUTDOWN PANEL
Inspection
Report 528/94-34 identified that the inspector
found lamp covers
mispositioned
on the remote
shutdown
panel
in Unit 2.
As
a corrective action,
the licensee initially considered
installing security card reading
doors at
the entry of the remote
shutdown panels in all units.
Subsequently,
the
licensee
revised their planned preventive actions.
They preliminarily propose
to install plexiglass
covers
over the panels with some type of securing tag.
The inspector
found this planned action to be acceptable.
I
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ATTACHMENT I
I
PERSONS
CONTACTED
1. I
Licensee
Personnel
J. Bailey, Vice President,
Nuclear Engineering
& Projects
P. Crawley, Director, Nuclear
Fuel
J.
Dennis,
Section
Leader,
Operations
Support
A. Fakhar,
Hanager,
Site Hechanical
Engineering
B. Grabo,
Section
Leader Compliance,
Nuclear Regulatory Affairs
A. Krainik, Hanager,
Nuclear Regulatory Affairs
D. Hauldin, Director, Site Haintenance
and Hodifications
J. Scott, Director, Chemistry
H. Sharp,
Instructor, Operations Training
W. Stewart,
Executive Vice President
R. Stroud,
Regulatory Consultant,
1.2
NRC Personnel
K. Johnston,
Senior Resident
Inspector
H. Freeman,
Resident
Inspector
J.
Kramer,
Resident
Inspector
A. HacDougall,
Resident
Inspector
B. Olson, Project Inspector
t
1.3
Others
J. Draper, Site Representative,
Southern California Edison
R. Henry, Site Representative,
Salt River Project
F.
Gowers, Site Representative,
El
Paso Electric
All personnel
listed above attended
the Exit meeting held
on January
18,
1995.
2
EXIT MEETING
An exit meeting
was conducted
on January
18,
1995.
During this meeting,
the
inspectors
reviewed the scope
and findings of the report.
The licensee
did
not express
a position
on the inspection findings documented
in this report.
The licensee
did not identify as proprietary
any information provided to, or
reviewed
by the inspectors.
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ADV
AKU
CFR
CRDR
IN
kip
LER
LOCV
HSSV
.SSC
TDAFWP
TS
VTN
ATTACHNENT 2
ACRONYNS
atmospheric
dump valve
air handling unit
Code of Federal
Regulation
containment
purge isolation actuation
signal
condition report/disposition
request
emergency diesel
generator
emergency
safeguards
features
Information Notice
thousand
inch pound
licensee
event report
loss of condenser
vacuum
Nuclear Reactor Regulation
operating
experience
review
structure,
system or component
surveillance test
turbine-driven auxiliary feedwater
pump
Technical Specification
vendor technical
manual
I
1
~ 4
0
I