ML17310B398
| ML17310B398 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 06/02/1994 |
| From: | Wong H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML17310B394 | List: |
| References | |
| 50-528-94-13, 50-529-94-13, 50-530-94-13, NUDOCS 9406300028 | |
| Download: ML17310B398 (50) | |
See also: IR 05000528/1994013
Text
APPENDIX C
U. S.
NUCLEAR REGULATORY COHHISSION
REGION IV
Inspection
Report:
50-528/94-13
50-529/94-13
50-530/94-13
Licenses:
NPF-51
Licensee:
Arizona Public Service
Company
P. 0.
Box 53999, Station
9082
Phoenix,
85072-3999
Facility Name:
Palo Verde Nuclear Generating
Station
Units 1,
2,
and
3
t
Inspection At:
Haricopa County, Arizona
Inspection
Conducted:
Harch
29 through
Hay 7,
1994
Inspectors:
K. Johnston,
Senior Resident
Inspector
H. Freeman,
Resident
Inspector
J.
Kramer,
Resident
Inspector
A. HacDougall,
Resident
Inspector
B. Olson, Project Inspector
Accompanying Personnel:
J. Ganiere,
NRR Intern
Approved By:
(
ong,~
Ins ection
Summar
>e,
roJect
rane
~/~/q
ate
Areas
Ins ected
Units
1
2
and
3
Routine,
announced,
resident
inspection
of:
~:
Plant Status
(93702)
On Site Response
to Events
(93702)
Weak Corrective Actions (37551,
40500,
62703
and 71707)
Operational
Safety Verification (71707)
Haintenance
Observations
(62703)
Surveillance Observation
(61726)
Followup
(92901,
92902,
92903,
and 92904)
In Office Review of LERs (90712)
9406300028
940624
ADOCK 05000528
6
'
l
I
Results
Units
1
2
and
3
Strengths:
Operator
response
to
a slipped control element
assembly
(CEA) in Unit
1
was
good (Section 2.1).
Plant
and engineering
management
took conservative
action in response
to
operability concerns
with Emergency Diesel
Generator
(EDG)
8 in Unit 3.
In addition,
management
promptly addressed
a safety concern with
electrical splice connections
(Sections
3.2
and 4.1).
~
Good coordination
and communication
were noted during the core off-load
in Unit 3 (Section 5.1).
~
management
involvement in the planning
and
subsequent
oversight of on-
line maintenance
of the pressurizer
spray valve in Unit
1 contributed to
the successful
performance of the job (Section 5.2).
l
e
A maintenance
training instructor displayed
a questioning attitude
and
discovered
a potential safety concern with raychem electrical
splices
(Section
4. 1).
Weaknesses:
Corrective actions:
During the inspection,
three
problems
were identified
that highlighted the licensee's
apparent failure to ensure that previous
inspector identified problems
were aggressively
pursued
and effective
corrective actions
implemented.
~
The licensee
had not implemented
a comprehensive
instrument out of
calibration program
as committed in response
to
a
1992 violation which
highlighted program weakness
(Section
3. 1).
This resulted
in
a
deviation.
~
The inspectors
identified an uncontrolled security badge,
which was
similar to problems identified in NRC Inspection
Report 50-
528,529,530/94-02
in which the licensee
received
a notice of a violation
(Section 3.2).
~
Operators
failed to correctly rack out
a breaker,
which was identical to
problems
the inspector previously identified to the licensee
and
described
in
NRC Inspection
Report 50-528,529,530/94-09
(Section 3.3).
This resulted
in
a violation.
t
Postmaintenance
testing:
A noncited violation highlighted weaknesses
in
postmaintenance
testing
acceptance
criteria'
'
l
1
~
Although two postmaintenance
tests
provided data which could have led to
the identification of incorrectly installed gears
in a motor-operated
valve,
weak acceptance
criteria
and weak test reviews resulted
in the
condition not being identified (Section 8. 1).
Summar
of Ins ection Findin s:
~
One violation was identified (Section 3.3).
~
One deviation
was identified (Section 3. 1).
I,
~
One noncited violation was identified (Section 8. 1).
~
Deviation 528/9326-02
was left open
(Section 9).
~
Violation 528/9340-06
was left open
(Section 7).
Inspection
Followup Items 529/9409-01
and 528/9402-03'ere
closed
(Section 8).
O.
Licensee
Event Reports
528/94-01,
Revision 0; 529/93-04,
Revision 0;
and
530/94-01,
Revision 0, were closed
(Section
11).
Attachment
1:
Persons
Contacted
and Exit Meeting
'
1
l
I
f
DETAILS
1
PLANT STATUS
1.1
Unit
1
Unit
1 began
the inspection period in Hode
1 at 86 percent.
On April 4,
1994,
power was reduced
to approximately
60 percent
in response
to
a slipped
(see
Section
2. 1).
Power
was raised
back to 86 percent late
on April 4 and
remained
there throughout the inspection period.
The licensee
continued to
monitor
a very small primary-to-secondary
leak in Steam Generator
12,
which
remained
less
than
1 gallon per day.
1.2
Unit
2
Unit 2 began
the inspection period in Hode
1 at 85 percent
power
and
on
Harch 30,
1994,
raised
power to 86 percent.
On April 30, the unit reduced
po ~r to
51 percent for a steam generator
hideout teii.
Power was raised to
86 percent
the
same
day
and remained
there throughout
the inspection period.
1.3
Unit 3
Unit 3 began
the inspection period in Hode
6 and remained
in an outage
conducting refueling operations
throughout the inspection period.
The
licensee
discovered
16 axial crack indications during eddy current inspection
32 tubes.
These indications
were similar to those
previously discovered
in Unit 2 steam generators.
The licensee
had conducted
a midcycle outage
at the
end of 1993 specifically to look for but did not find
these
types of axial indications.
During the current outage
the licensee
identified
16 axial indications after chemically cleaning the
steam
generators.
The licensee
expanded
the
scope of the eddy current inspections
to bound the location of the indications.
The licensee
also identified one
axial indication in steam generator
31.
At the
end of the inspection period,
the licensee
was completing
tube inspections.
2
ONSITE
RESPONSE
TO
EVENTS
(93702)
2. 1
Sli
ed
Unit
1
0
On the morning of April 4,
1994,
CEA 36 slipped to approximately
139 inches
(the all rods out position was
147 inches)
during the performance of monthly
CEA exercise testing.
The licensee
declared
the affected
complied with the appropriate
Technical Specification
(TS) requirements
and
began
reducing
power.
About
1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> after the
CEA slipped,
the other
CEAs in
Shutdown
Group
B were inserted
to within the
TS limit of 6.6 inches of CEA 36.
At this point, the downpower
was stopped
and reactor
power was stabilized at
about
61 percent.
4
']
The licensee
found
a faulted optical isolator that
was only providing
2 out of
3 phases
of current to the upper gripper of CEA 36.
The card
was replaced
and
satisfactorily retested.
CEA 36 was subsequently
aligned to the other
CEAs in
Shutdown
Group
8 and declared
Operators
began
a power ascension
and
reactor
power was restored
to 86 percent late
on the evening of April 4.
The inspector
reviewed the licensee's
actions
and concluded that the
licensee's
overall
response
to the event
was good.
The operators
were alert
to earlier problems with CEA 36, quickly entered
the appropriate
TS action
statements
and reduced
power,
and safely recovered
from the condition.
3
WEAK CORRECTIVE ACTIONS
(71707,
62703,
40500)
The following section discusses
three
examples of issues
that
had
been
brought
to th~ licensee's
attention
'he inspectors
in previous inspections.
In the
first example,
the inspector
found that the licensee
had not implemented
a
comprehensive
instrument Out-of-Calibration
(OOC) program despite
a
1992
violation which highlighted program weakness.
In the second
example,
the
in pectors identified
an uncontrolled security
badge,
which was similar in
nature
to
an event identified in
NRC Inspection
Report 50-528,529,530/94-02
in
which the licensee
received
a violation.
The third example
involved the
failure of operators
to correctly rack out
a breaker,
which was identical to
events
described
in
NRC Inspection
Report 50-528,529,530/94-09.
These
events highlighted
a concern regarding the licensee's
apparent failures
to ensure that inspector identified problems
are aggressively
pursued
and
effective corrective actions
implemented.
At the exit meeting,
licensee
senior
management
assured
the inspectors
that they shared
the
same
concern
and
would take action to ensure that these,
and
any subsequent
problems identified
by the inspectors,
would be carefully considered
and fully addressed.
3.1
Review of OOC Pro ram
The inspector
reviewed the
adequacy of the licensee's
OOC program for
instruments that are important to safety to determine
whether adverse
conditions or trends
were identified and corrected.
The primary focus of this
inspection
involved the low lube oil pressure
switches
(LLOPS)
on the
EDGs.
The inspector previously determined that the preventive
maintenance
(PH) tasks
used to calibrate
the
LLOPS did not have guidance
as to when
an
OOC condition
required identification and evaluation
(see
NRC Inspection
Report 50-
528,529,530/94-09
for details).
The inspector
found that the licensee's
OOC review program
was not
comprehensive
for all safety-related
instruments.
In addition,
the inspector
found that:
~
The licensee
had not taken action to ensure that
OOC conditions in the
LLOPS received
reviews,
despite
the fact that repeated
OOC conditions
for these
switches
were the basis of a
1992 Notice of Violations
0
l
~
Similar repeated
OOC conditions in the essential
chiller (EC)
instrumentation
had not received
formal review.
~
The response
to the
1992 violation did not accurately reflect the
licensee's
intended interim corrective actions for OOC reviews.
~
The licensee
was slow to address
the inspector's
concerns,
despite
discussion
with senior
management
in
a previous exit meeting.
3. l. 1
LLOPS
OOC Reviews
In
NRC Inspection
Report 50-528,529,530/94-09,
the inspector
observed
the
calibration of Unit
1
LLOPS.
The technicians
performing the test noted
that the switches
were acting erratically
and subsequently
replaced
the
switches.
The inspector
noted that there were
no instri ctions provided to t4;
technicians
to indicate
whethe~
an
OOC review was required.
The inspector
noted that the licensee
was
issued
a Notice of Violation in
NRC
Insp
tion Report 50-528,529,530/92-14
due to
a failu e to trend
OOC
conditions with the
LLOPS.
The licensee's
response
to the violation indicated
to the inspector that the licensee
would develop criteria for evaluating
instruments
which exceed
the as-found
acceptance
criteria.
The response
indicated that
a
CRDR would be initiated when instruments
exceeded
the
screening criteria threshold.
At the exit meeting for NRC Inspection
Report 50-528,529,530/94-09,
the
inspector questioned
whether there
had
been
OOC conditions identified on the
LLOPS since
the response
to the violation and whether these conditions
had
received
an engineering
review.
The licensee
conducted
a review and determined that,
from August
1992 until
March 30,
1994,
there
had
been
a total of 33 calibrations of the
LLOPS.
Of
the total, only eight as-found setpoints fell within the
band specified in the
PH instructions
(+0.38 pounds
per square
inch (psi) of the 30 psi decreasing
setpoint).
The percentage
of OOC incidents in this period correlates
well
with the results
reviewed in
NRC Inspection
Report 50-528,529,530/92-14.
The
inspector
found that
no screening criteria
had
been established
for the review
of OOC conditions with the
LLOPS and that
no
CRDRs
had
been initiated.
The inspector also questioned
the licensee
as to whether their failure data
trending
(FDT) program
had identified and documented
any of the
LLOPS
OOC
conditions.
The licensee
conducted
a review and determined that
a majority of
the
OOC conditions
were identified and inputed for trending.
The inspector
concluded that the
OOC conditions with the
LLOPS were identified in the
system
and were available to the system engineer to identify potentially
adverse
trends.
The inspector
reviewed the significance of the
25
OOC conditions.
Twenty-two
as-found setpoints fell within a band of +3 psi of the setpoint.
This band
'
was determined
to be acceptable
by the licensee
in their review performed
following the violation in
NRC Inspection
Report 50-528,529,530/92-14.
However,
the
LLOPS
PM work orders
(WOs) were not updated to include the H psi
as the acceptance
criteria
and the
22
OOC as-found setpoints
were not checked
to see if an additional
review was necessary.
Three instruments
had as-found setpoints that were outside the z3 psi
band
and
were not evaluated.
On March 30,
1994,
the licensee
issued
a setpoint
basis
document for the
LLOPS and established
a +3.26/-4.61
psi band.
Two of the
three pressure
switches
were inside this band.
The other pressure
switch had
an as-found setpoint of 36.89 psi, which was more than twice the acceptance
criteria.
The inspector
asked
the licensee
to evaluate
the significance of the
one
pressure
switch whose setpoint
was outside
the calculated
band.
The licensee
determined
that this one
OOC was not signiricant
based
on
a statistical
analysis of the expected drift of these particular pressure
switches
and the
narticular function of the switch.
The inspector
reviewed 'the licensee's
setpoint calrulatior
and the previous
CRDR desc~ibing
the function of the
LLOPS and concluded that the
one switch being
OOC was not safety significant.
3. 1.2
Condition of
EC Instruments
Based
on the
above review and several
discussions
with the licensee,
the
inspector determined that the licensee's
OOC program did not include the
quality class
instruments that were not directly related to TS and were
calibrated
using
a routine
PM work order.
The inspector discussed
this
concern
to the licensee.
The licensee's initial response
was that the issue
did not represent
a programmatic
weakness
and that they had met their
commitments
as expressed
in the
1992 response
to the violation.
Additionally,
they placed confidence
in the system engineer's
review of the
FDT reports for
their systems.
The inspector questioned this response.
The inspector
concurred that the
OOC conditions
on the
LLOPS had not been safety
significant.
However,
the review performed to demonstrate
the lack of safety
significance
was largely in response
to the violation in
NRC Inspection
Report 50-528,529,530/92-14.
The inspector questioned
whether there
were
other safety-related
instruments
which were not receiving
OOC reviews
and were
also not included in the
FDT program.
To substantiate
the potential
programmatic
weakness,
the inspector
reviewed
the
PM tasks to calibrate
several
instruments
important to the operation of
the
EC.
The
ECs provide
room cooling
or safety-related
equipment
and ensure
control
room habitability during accident conditions.
The inspector
reviewed
the last work order for each of the six
ECs
(two per unit)
and noted that the
as-found setpoints of three out of 12 low lube oil pressure differential
pressure
switches
(LLOPDPS) were outside the acceptance
band.
Additionally,
the inspector
noted that the compressor
bearing
high oil temperature
switch
could not
be calibrated
and the switch was replaced.
The inspector
found that
no
CRDRs
had
been initiated to review these conditions.
'
The inspector
asked
the licensee
to determine
the significance of these
OOC
conditions.
The licensee
determined that the most significant
OOC condition
was the
LLOPDPS
as found setpoint of 19 pounds
per square
inch
differential (psid) vice
13 psid.
The licensee
determined that the normal
differential pressure
was 24-28 psid.
Therefore,
the lube oil differential
pressure
would have to change
about
5 psid before the chiller would
potentially trip with a
19 psid setpoint.
The licensee
concluded that this
particular
00C condition was not safety significant.
The inspector
agreed
with the licensee's
conclusion.
The inspector
asked
the licensee
to determine if the
OOC conditions were
identified by the
FDT program.
The licensee
determined that the
OOC
conditions were not inputed in the
FDT data
base.
The inspector
reviewed the
licensee's
procedure for inputing data into the
FDT program
and determined
that the program did not consider
OOC condition.
as failures.
As
a result,
OGC conditions identified by routine
PM tasks
were riot generally entered
into
the
FDT data
base.
In December of 1993, the licensee
provided guidance to the
work planners
to input any
OOC conditions that are greater
than two times the
acceptance
criteria.
The inspector
noted thai th:
OOC conditions with the
EC
instruments
occurred prior to this time.
The inspector
concluded that the
licensee
did not have
any programmatic
requirements
to screen
PM tasks for OOC
conditions for entry into the
FDT program.
The inspector considered this to
be significant because
the overall
OOC program relied
on the
FDT program to
identify any potentially adverse
trends.
3. 1.3
Licensee's
Response
to Violation 9214-02
Based
on the inspectors
findings, the licensee
took
a broader look at the
setpoint basis
program
and identified approximately
240 safety-related
instruments that were included in the setpoint basis
program
and were not
calibrated
as part of a
TS requirement
or to support
a
TS required test.
The
licensee
committed to review these particular instruments
and to ensure that
the
FDT program
was capturing all the
OOC data for identification and possible
evaluation.
The licensee initiated
CRDR 9-4-0287 to perform the
investigation.
The inspector
noted that,
in response
to the violation in
NRC Inspection
Report 50-528,529,530/92-14,
dated
August 7,
1992,
the licensee
stated that
~
the following.corrective actions
would be taken to ensure failed instrument
loop components
were properly identified, evaluated,
and dispositioned:
~
.
Screening criteria
and threshold
would be developed for use
by the work
group supervisors
to identify which instrument loop components
that
exceed
the specified
as-found test
acceptance
criteria required further
evaluation
by the engineering
organization.
Preventive
maintenance
and surveillance testing
procedures
would be
revised to require the initiation of a condition report/disposition
request
(CRDR) when instruments
exceed
the screening criteria threshold
limits.
The inspector
questioned
the licensee
on
how they met the above
commitment for
the approximately
240 safety-related
instruments
described
above.
The
licensee
responded
that it had not been their intent that the response
to the
violation apply to these
instruments.
Their intent was that the commitments
would apply only to those
instruments
which were required to be tested
in the
TS or were
used to support
TS required testing.
The inspector
reviewed the
licensee's
documentation
used to develop the corrective actions
in response
to
the violation and found that the licensee's
intqnt was not well established.
Upon further review, the inspector
considered
that none of the licensee
personnel
involved had
a clear understanding
of the overall
.00C program
and
that there
was substantial
confusion regarding
the nature of the corrective
actions.
It was apparent
to the inspector that this confusion resulted
in the
differences
between
the licensee's
letter
and the actions that were taken.
The inspector
found that the licensee's
letter was clear in'ts commitment to
apply the
OOC review screening criteria threshold 1'mits to the
PH tasks
performed
on the
LLOPSs.
This conclusion
was
based
on the fact that the
letter responded
to
a violation concerning
these
same
instruments
and that the
letter did not exclude these
instruments
or any category of safety-related
instrumentation.
Based
on this, the inspector determined that the licensee's
failure to apply the screening criteria to the
LLOPS
PH tasks
was
a deviation
from their commitment in the letter (Deviation 528/9413-01).
F 1.4
Licensee
Response
to Inspector's
Findings
At the exit meeting for this inspection report,
the licensee
committed that
they would perform
an in-depth evaluation of the
OOC review program to
determine
the extent of instruments
not presently
covered
and committed to
evaluate
the calibration history of safety-related
instruments
which had not
received
previous review.
The inspector
noted that these
steps
were
appropriate.
However,
the inspector
found that the licensee
had
been
slow to
take
a broader look at the overall
OOC program after the inspector raised
the
specific concerns
with the
LLOPS.
For example,
on Harch 8,
1994,
the inspector noticed that there
was not any
guidance
in the field as to when
an engineering
review of OOC conditions
was
required.
The inspector notified Unit
1 management
of the concern
on
approximately
Harch
11.
On Harch
14, the inspector discussed
the problem with
the
EDG system engineer
and the Instrumentatio
and Control supervisor
responsible
for the procedure
to calibrate
the
LLOPS.
By Harch
18, the
inspector
brought the issue to
a representative
from licensing
and the
Instrumentation
and Control supervisor responsible
for the
OOC program.
Finally, during the exit meeting for the previous inspection period at the end
of Harch,
the inspector
communicated
the concerns
about the adequacy
of the
OOC program
and the specific concerns
about the condition of the
LLOPS to
senior
management.
,
I
-10-
In early April, the licensee
conducted
a review of the condition of the
LLOPS
but had not initiated any corrective actions to review the adequacy of the
overall
OOC program.
At that time, the inspector
was again forced to discuss
with senior
management
the potential
programmatic
weaknesses
with the
OOC
program.
By the
end of April, after the inspector
had additional
meetings
with the supervisors
responsible
for the
00C program,
the licensee finally
initiated
an evaluation of the overall
00C program.
3.2
Em lo ee Control of Automatic Controlled Access
Device
and Dosimetr
Units
1
2
and
3
On May 3,
1994,
the inspector
observed
an unattended
automatic controlled
access
device
(ACAD) and dosimetry near the Unit 2 radiological controlled
area
(RCA) exit.
The inspector contacted
plant security,
who subsequently
took control of the
ACAD.
Further investigation revealed that the items were
inadvertently left there
by
a contract
employee.
The licensee initiated
a
CRDR to evaluate
the event.
The inspector
had identified recurring events
where the licensee
employees
had failed to properly control
ACADs and
dcsimetry.
On January
25,
a contract
employee
removed his
ACAD and dosimetry while
working within the radiologically controlled area.
The licensee
received
a
violation for this event (Violation 529/9402-01).
The licensee's
corrective
actions
included suspending
all work by the contractor
and conducting
crew
briefings to emphasize
the responsibility of personnel
to wear
and control
their ACADs and dosimetry at all times.
The inspector
concluded that, unlike
the January
25 event,
where
an employee consciously
removed the
ACAD and
dosimetry to perform work, the employee
who removed his
ACAD and dosimetry
on
Nay 3 unintentionally left the items near the radiologically controlled area
exit.
On February
7, the inspector
noted several
instances
where personnel
were
wearing their dosimetry in the incorrect location
(see
NRC Inspection
Report 50-528,529,530/94-02
for details).
The licensee
acknowledged
the
problem.
The licensee
committed to have all managers
and supervisors
review
with their employees
the proper location for the dosimetry
and
ACAD and
committed to review employee training/retraining to determine if the location
was properly defined.
At the exit meeting,
the inspector
expressed
concern that licensee
employees
appeared
to have
a lack of sensitivity towards their responsibility to
properly wear
and maintain
ACADs and dosimetry.
The licensee
was performing
a
CRDR evaluation for the
Hay
3 event.
3.3
Load Center Breaker - Unit 3
On April 6,
1994,
the inspector
observed
a safety-related
480V breaker
in
Unit 3 racked out with its closing springs not discharged.
The inspector
notified the shift supervisor
who immediately
had the breaker correctly racked
out.
I
0
-11-
Procedure
Revision 3,
"480V Class
IE Switchgear,"
Appendix J,
required that the closing springs
be discharge
as indicated
by the "springs
charged" indicator on the face of the breaker
when
a breaker is racked out.
The inspector
concluded that the operator failed to follow Procedure
430P-
3PGOI, which is
a violation of TS 6.8. 1 (Violation 530/9413-02).
The inspector
had noted several
previous
instances
where the licensee failed
to follow procedures
and incorrectly racked out load center breakers.
On
February
24, the inspector
observed
a charging
pump breaker in Unit 3 not
correctly racked out (closing springs
not discharged)
with a clearance
tag
attached
to the breaker.
On February
28, the inspector
checked that vital
load center breakers
in all three units
and discovered that
18 of 39 breakers
were incorrectly racked out.
The licensee initiated two
CRDRs to address
the
incorrectly racked out breakers.
The licensee
performed
an inspection of the
load center breakers
to ensure
they were all correctly racked out.
Operations
management
made
an entry into the night order book indicating management
expectations
for operators
to correctly rack out breakers.
The inspector
considered
these
instances
where the licensee failed to
correctly rack out breakers
to be
a noncited violation (see
NRC Inspection
Report 50-528,529,530/94-09).
The problem was not cited based
on the low
safety significance of the events
and
on the licensee's
indicated corrective
actions.
The April 6 event
was considered
a cited violation because it was
determined to be
an event which should
have
been
prevented
by previous
corrective actions.
The inspector
reviewed the corrective actions for the April event.
The
licensee
again performed
an inspection of the load center breakers
to ensure
they were all correctly racked out and
made another entry into the night order
book indicating management
expectations
for operators
to correctly rack out
breakers.
The licensee
then closed the
CRDR to "trend."
The
CRDR did not
address
why the operators
had not properly racked out the breaker.
It was not
apparent
in the
CRDR discussion
whether this event
had ever
been discussed
with the operators.
At the exit meeting,
the inspector questioned
whether
a
thorough review had
been
performed.
The inspector
noted that guality Assurance
(gA) had reviewed the
CRDR written
for the February
28 events
and
had identified that the time allowed to
complete the corrective actions
was excessive.
The changes
to the electrical
PHs were not scheduled until August
31
and the training for nuclear operators
and maintenance
personnel
was not scheduled until October 30.
In addition,
gA
requested
that engineering
address
the implications of having the load center
breakers
in the drawout (fully racked out) position since the vendor technical
manual
indicates that the breakers
are not designed
to be left in the drawout
position.
The inspector
agreed with the
gA assessment
that the planned
corrective actions for the, February
events
were not timely and noted
gA
performed
a thorough review of the issue.
'
J,,
I
-12-
4
OPERATIONAL SAFETY VERIFICATION
(71707)
The inspectors
performed this inspection to ensure that the licensee
operated
the facility safely
and in conformance with license
and regulatory
requirements
and that the licensee's
management
control
systems effectively
discharged
the licensee's
responsibilities for safe operation.
The methods
used to perform this inspection
included direct observation of
activities
and equipment,
observation of control
room operations,
tours of the
facility, interviews
and discussions
with licensee
personnel,
independent
verification of safety
system status
and
TS limiting conditions for operation,
verification of corrective actions,
and review of facility records.
4. 1
Environmental
ualification of Electrical
S lice Connections
- Units
1
2
and
3
On April 22,
1994,
the licensee
identified
a potential
generic
problem with
the environmental qualification of electrical
splices
manufactured
by Raychem
u :d to seal
4160
V electrical
connections.
During site training in which
electrical
maintenance
personnel
were being trained
on vendor
and site
instructions
on the installation of Raychem splices,
an instructor opened
a
completed
connection
and discovered
that the
2 inch wide adhesive strip
applied over
a joint had not fused to the outer casing.
The licensee
tested
additional splices
and discovered that in some instances,
even
when the
vendor's instructions
were strictly adhered to, the splices
may not completely
seal.
The inspector
noted that the instructor's
questioning attitude
was
a
strength.
The licensee
conducted
a plant review board
(PRB) meeting to discuss
the
safety significance of the issue.
The licensee
determined that the splices
were
needed
to ensure that safety-related
motors were not adversely affected
by
(HELB) which would result in a
100 percent
humidity environment.
The licensee
determined that the only safety-related
components
that would be vulnerable to
a
HELB and also
needed for safe
shutdown of the plant were the two low pressure
safety injection (LPSI) pumps,
the two containment
spray
(CS)
pumps,
and the motor driven auxiliary feedwater
pump.
The licensee
concluded that they had
a reasonable
assurance
that these
pumps were operable,
This conclusion
was
based
on the fact that these
pumps
were not subjected
to
a
100 percent
humidity environment
and,
based
on the
testing they conducted,
that they had
a reasonable
assurance
that the splices
were at least partially bonded,
The
PRB members
concluded that although they believed the affected
pumps were
they had
a potential
concern that needed
to be quickly resolved.
As
a result,
by April 23, the licensee
completed
inspections
of the motor
connections
for the
10 affected
pumps in the operating units.
Since Unit 3
was in an outage,
the inspections
were scheduled
prior to entering
mode 4.
The inspector
attended
the
PRB meeting
and concluded that the licensee's
and initial inspection
plan were appropriate.
e
)
I
-13-
On May 5, the licensee
completed all the inspections
of the motor connections.
Six of the connections
were determined
to be satisfactory
and nine were
determined
to questionable.
The licensee
conducted
additional testing that
demonstrated
that
a complete
seal
would occur if the outer casing
was heated
until the surface
developed
a glossy appearance.
The vendor determined that
reheating
the surface of the splice
and using
a glossy
appearance
as the
acceptance
criteria was acceptable.
The nine questionable
connections
were
subsequently
reheated
and the affected
pumps
were returned to service.
The
licensee
could not conclusively determine if the splices that were reheated
were degraded
and if they would have prevented
moisture intrusion in
a
100 percent
humidity environment.
The licensee initiated
CRDR 9-4-0254 to
evaluate
the significance of the conditions
and
any potential
generic safety
issues.
The licensee
also sent
a Nuclear Network note to the industry
on the
issue.
The inspector
concluded that the licensee's initial resulution of this
potential
problem was good.
The licensee
scheduled
a meeting with Raychem to
determine
the extent of changes
to the installation procedure.
The inspector
planned
to attend
the meeting to ensure that any generic
concerns
were
adequately
resolved.
At the exit meeting,
the licensee
indicated their
intention to submit
a voluntary licensee
event report
(LER) describing
the
potential
safety concern with these particular
Raychem splices.
4.2
B 0 erabilit
Determination
Unit 3
On May 6,
1994,
the licensee
declared
due to
a engineering
concern with five rocker
arms that were hardness
tested
and determined
to have
less
than
an acceptable
yield strength.
In April the licensee
conducted
hardness
tests of the rocker arms
on
B and
found that
12 rocker
arms
had
a yield strength
less
than
25 thousand
pounds
per square
inch (ksi).
The vendor
recommended
value
was greater
than
32 ksi
and the licensee
had performed
an analysis that concluded that greater
than
25 ksi would be acceptable.
The licensee
only had nine rocker
arms in the
warehouse
and there
were
no more available
from the vendor.
As
a result,
the
licensee
replaced
seven of the rocker arms,
kept two rocker arms for spares,
and conducted
an analysis
to accept
the five other rocker arms
as is.
B
was retested
and declared
on April 21.
Engineering
management
decided to perform an independent
assessment
of the
conditional release
and
10 CFR 50.59 evaluation to validate the decision to
declare
B operable.
The review team did not identify any specific issues
that would invalidate the acceptance
of the five rocker arms.
However,
they
did raise
issues
concerning
the rigor of the engineering justification for
determining the acceptably of the condition.
Based
on these
concerns
and
a
recommendation
from engineering
management,
the Unit 3 plant manager
conservatively
declared
on May 6.
At that time,
EDG A was
also inoperable
to repair
a leak in the
6L cylinder jacket water line.
'
j
I
0
-14-
The licensee
appropriately
entered
the
TS action statement
for two inoperable
EDGs in Mode 6.
The action statement
required
suspension
of any core
alterations
and to ensure that at least
23 feet of water over the reactor
vessel
was available.
At the time,
B was declared
the
licensee
had drained
the refueling water level to the reactor flange
(114
feet)
and
was beginning to install the reactor vessel
head.
The licensee
stopped
the
head installation
and flooded the refueling cavity back
up to 137
feet.
The inspector
concluded that the licensee's
actions to declare
B
and reflood the refueling cavity were conservative.
The inspector
will review the licensee's
basis for initially declaring the
the five marginal
rocker arms
and the licensee's
final resolution of the
operability concern during ongoing inspection of the
EDGs.
0
5
MAINTENANCE OBSERVATIONS
(62703)
During the inspection period,
the inspectors
observed
and reviewed the
sel <<ted maintenance
activities listed below to veri "y conpliance
vith
regulatory requirements
and licensee
procedures,
required quality control
department
involvement,
proper
use of safety tags,
proper equipment
alignment
and
use of jumpers,
personnel
qualifications,
appropriate radiation worker
practices,
calibrated test instruments,
and proper post-maintenance
testing.
Specifically, the inspectors
witnessed
portions of the following maintenance
activities:
5. 1
Outa
e Activities - Unit 3
On March 30,
1994,
the inspector
observed
core off-loading.
The inspector
reviewed the core reloading
procedure
and witnessed
the off-load of
approximately eight fuel assemblies.
The inspector
noted
good coordination
and communication
between
the refueling senior reactor operator
and the
control
room.
The inspector
also observed
the installation of main steam safety valves,
the
disassembly
and inspection of a reactor coolant
pump thrust bearing,
and the
installation of the
B connecting
rod.
The inspector
concluded that these
activities were appropriately
conducted.
5.2
Pressurizer
S ra
Valve Maintenance
Unit
1
On April 5,
1994,
the licensee
made
a containment
entry to repack pressurizer
spray valve
100E which had
been isolated
due to excessive
packing
leakages
The licensee
had
made several
attempts
to tighten the valve packing but was
unable to reduce
the leakage
into the reactor drain tank (see
NRC Inspection
Report 50-528,529,530/93-55
for details).
The inspector
reviewed the
licensee's
plan for conducting the maintenance
and the methods
used to
determine that the single valve isolating the spray valve was not leaking.
The inspector
noted that the licensee
had good controls to verify the
condition of the isolation valve.
'
t
'
-15-
The licensee
completed
maintenance
and testing of the spray valve
and returned
it to service
on April 6.
The inspector
concluded that the maintenance
activity was well coordinated
between
the maintenance,
engineering,
and
operations
departments.
Additionally, the inspector
observed
a high level of
management
involvement in the activity.
On April 9, the licensee
began to see
a rise in the leakage
into the reactor
drain tank.
Another containment entry was
made
and
a leak of about
10 gallons
an hour was identified from the bypass
valve for Spray Valve 100E.
The spray
valve was subsequently
isolated.
The inspector discussed
this problem with
the licensee
and determined that the leak on the. bypass
valve was previously
being hidden
by the large
amount of leakage
from Spray Valve 100E.
As
a
result,
the licensee
had not planned to repack the bypass
valve when they
repacked
Spray Valve 100E.
The inspector
concluded that the licensee's
actions to detect
the leakage
and again i"olate Spray Valve 100E were
appropriate.
.3
~EO
L
lid <<h
d
On April 6,
1994, during monthly testing of the Unit
2
EDG B, the licensee
noted
an unusual
noise in the diesel's
Cylinder 4L.
The licensee
removed
the
cylinder head
and found that the cylinder's intake crosshead
roller, which
transfers
the
cam lobe profile to the push rod,
had seized.
The licensee
replaced
the crosshead
assembly
and performed
several
inspections
to determine
the scope of the damage.
On April 8, during post maintenance
testing,
the licensee
discovered
that
Cylinder 4L was not firing.
During subsequent
inspection,
the licensee
found
that the exhaust
valve crosshead
was stuck in the inserted position, holding
the exhaust
valves
opens
The licensee
removed the
4L cylinder head
and
replaced it with an identical
assembly
from the Unit 3
EDG B.
The original
Cylinder 4L was quarantined
for a root cause
evaluation.
At 5:46 a.m.
on April 9,
B tripped
as
a result of a spurious
signal during the postmaintenance
testing.
At 8 a.m.
the licensee initiated
enforcement discretion discussions
with NRC management
since the 72-hour
action statement
was
due to expire in 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.
With the
the
plant
TS would require
a plant shutdown.
The licensee
requested
an 18-hour
extension of the 72-hour action statement
to troubleshoot
and correct the
overspeed trip system
problems,
to perform final inspections
of the
EDG,
and
to test the
EDG.
At 12: 15 p.m. the
NRC granted
a notice of enforcement
discretion,
agreeing
to an 18-hour extension of the action statement.
The inspector
observed
the installation of the
new crosshead
assembly,
observed
the troubleshooting
of the overspeed trip, attended
the licensee's
Plant
Review Board,
and revie.jed the licensee's
basis for requesting
an
extension of the action statement.
The inspector
concluded that the licensee
took
a deliberate
and safe
approach
to restoring the operability of the
EDG.
Additionally, the inspector
reviewed the licensee's
inspection criteria
and
e
-16-
concluded that they provided
a sufficient level of confidence that the problem
was isolated to Cylinder 4L.
The licensee
determined that the overspeed trip was caused
by
a loose bracket
on
a limit switch in the
EDG's overspeed trip system.
The licensee
readjusted
and successfully
tested
the bracket.
The trip input was part of the
EDG's
maintenance
testing trip system
and would not have resulted
in an
EOG trip had
it been started
in the emergency
mode
The licensee
subsequently
completed
EDG testing
and declared
the
EOG operable.
The licensee
and
a vendor representative
conducted
an inspection of
Cylinder 4L after the engine
was declared
The licensee
and vendor
concluded that there
was
no abnormal
wear
on the crosshead
or cam follower.
The licensee
',nitiated
CRDR 2-4-0148 to perfor!! a root cause of failure
analysis of the crosshead
failures.
The inspector
met with the system
engineers
to discuss
the
scope of the evaluation.
The inspector
asked
the
engineers
whether
a
CRDR was initiated t~ eve> nate the safety significance
and
transportability of ;he overspeed trip.
The
ic .nsee
determined that although
the system engineer
was working on the issue,
a
CRDR was not initiated to
document
the evaluation.
The system engineer initiated
CRDR 2-4-0169 to
document
the evaluation of the over speed trip.
The inspector will review the licensee's
evaluation during ongoing inspection
of the licensee's
corrective actions.
5.4
S ra
Pond
Pum
Bushin
and Sleeve
Oama
e
Unit 3
Early in the Unit 3 refueling outage,
the licensee
discovered
pieces
from
Spray
Pond
Pump
B in the Train
B essential
cooling water
(EW) heat
exchanger
inlet bowl.
The licensee
had scheduled
an inspection of the Train
B
EW heat
exchanger after they had identified
a rattling noise in the heat
exchanger.
Subsequent
to the heat
exchanger
inspection,
the licensee
inspected
Spray
Pond
Pump
B and found that the pieces identified in the heat
exchanger
corresponded
to damage
to
a sleeve for the
bowl bearing
(located
on the pump's shaft
above
the impeller).
The bowl bushing
and the spider bushing
(located
midway on the
pump shaft),
both
made of Buna-N rubber,
were also
damaged.
The inspector
observed
portions of the work and reviewed the licensee's
safety evaluation.
The spray
pond
pumps
are
deep draft
pumps which supply ultimate heat sink
cooling the
EW heat
exchanger
and to diesel
generator
systems.
The
pumps
have
four bearing surfaces.
The inboard bearing
has
a graphite
and the
outboard
bearing
has
a bronze bushing.
Both the
bowl
and spider bearings,
which are approximately
12 inches long, were originally supplied with Buna-N
These
which are held in place
on the
pump housing,
ride
against stainless
steel
which are affixed to the
pump shaft.
The
licensee
has not perFormed
maintenance
on these
bearing
since original
installation.
I
1
-17-
The pieces that
had broken
from the Spray
Pond
Pump
8 bowl bearing
were
from the upper
end of the sleeve
and represented
a
180 degree
section
approximately
2 inches
long.
The cracking
appeared
to start at
a key-way on
the top of the sleeve.
The licensee
found that the
bowl bearing
had
low tensile strength
and low ductility and
was filled with porosities.
The
licensee
surmised that these deficiencies
resulted
from a bad casting.
The inspector
noted to the licensee
that the
pump vendor
had previously
supplied
substandard
components.
In one case,
a subsupplier for the vendor
had supplied
a
pump impeller which had not been properly heat treated.
The
licensee
followed up by asking the vendor to review the traceability of the
damaged
and the sleeves
on all six Palo Verde spray
pond
pumps.
At the
end of the inspection period,
the vendor
had not provided
an
answer
.
The licensee
found the
bowl bushing to be damaged.
The Buna-N surface
appeared
hardened
and substantially tom around in the area
where the sleeve
was
damaged.
The area
below the
damaged
part of the sleeve
was hardened,
but
intact.
The licensee
concluded that the majority of the
damage
was
due to the
damaged
The licensee
found the spider bushing
Buna-N to be severely
damaged.
It. was
found to be hardened
and swollen.
The licensee
discussed
this with the rubber
supplier
who concluded that the
damage
was due to heat.
The licensee
considered
whether the heat
was chemically induced. 'he licensee
reviewed
current spray
pond chemistry
and found it to be comparable with the Buna-N.
However,
the licensee
recognized that past chemistry controls of the spray
ponds
may have not been
comparable.
At the
end of the inspection period,
the
licensee
was assessing
the source of heat to the bushing.
The licensee
replaced
the Buna-N bushing material with bronze material
supplied
and approved
by the vendor
and reinstalled
the
pump.
Subsequently
the licensee
removed
Spray
Pond
Pump
A for inspection.
The bowl bushing
was
found to be hardened
but intact.
The spider bushing
was found to be
significantly degraded,
comparable
to the
Pump
B spider bushing.
Both
were replaced with bronze material.
Both the associated
were
intact.
At the
end of the inspection period,
the licensee
was planning to
examine
the material of the Spray
Pond
Pump
A sleeves
to determine
whether
they were properly cast.
The licensee
reviewed both the operation histories of Spray
Pond
Pumps
A and
B
and found that
pump performance
data provided
no indication of pump
degradation.
In addition,
the licensee
reviewed records of pump starting
currents
and determined that there
had
been
no significant changes.
The
licensee
requested
the vendor to provide
a design review of the spider bearing
and to review the capability of the spray
pond
pumps in the degraded
condition.
Preliminarily, the licensee
determined that the bearing
was to
provide shaft stability dur'ing
pump starts.
In the as-found condition, the
spider bearing
appeared
to provide adequate stability.
The licensee
determined that in the as-found condition,
the
pump was capable of performing
its safety related function.
They requested
the
pump vendor to evaluate
the
l
I
i
l
-18-
ability of the
pumps to operate
continuously for 30 days with the bearings
in
the degraded
condition.
The inspector
found the interim evaluation to be acceptable
and will follow
the licensee's
continued evaluation of the spray
pond
pumps.
6
SURVEILLANCE OBSERVATION
(61726)
The inspector
observed
portions of a Unit 3 7-day surveillance test of station
batteries
procedure
The inspector
concluded that the test
was
conducted
in accordance
with TS and approved
procedures.
7
FOLLOWUP OPERATIONS
(92901)
7. 1
fO en
Violation 528 9340-06:
Overtime Limit Exceeded
This violation occurred
when
one individual exceeded
the work hour limitations
nf TS 6.2.2. I.b.
The occurrence
would have
been
considered
a noncited
!iolation; however, after the issue
was recognized,
the inspector
found that
gA had identified other instances
where the work hour limitations had
been
exceeded.
The licensee's
corrective actions
included issuing
a temporary
Stop
Work
Notice prohibiting affected
Palo Verde departments
from taking exceptions
to
the Overtime Policy until interim corrective actions
were implemented,
issuing
a corrective action report
(CAR) to track
and verify corrective actions,
and
initiation of an investigation.
The inspector
reviewed
CAR 93-0179 which identified five areas for evaluation:
(1) the computer report
used to identify overtime violations,
(2) the accuracy
and timeliness of time tickets/data
entry,
(3) Procedure
02AC-OEHOI, "Overtime
Limitations," (4) the noncompliances
with overtime exceptions,
and
(5) communication
and training.
At the time of the inspection,
the licensee
had not completed all of the evaluations,
and
a recent
gA audit identified
additional
instances
where work hour limitations had
been
exceeded.
The inspector
observed that the licensee
monitors work hours
and that large
numbers of personnel
have not exceeded
work hour limitations.
Therefore,
the
inspector
concluded that
a breakdown of the licensee's
program
has not
occurred.
This item remains
open pending the identification and
implementation of corrective actions
associated
with CAR 93-0179.
8
FOLLOWUP NAINTENANCE
(92902)
8.1
Closed
Ins ection Followu
Item 529 9409-01:
Hi
h Pressure
Safet
In ection Valve Postmaintenance
Testin
PHT
Unit 2
This item involved the failure of a
control/isolation valve to close during design differential pressure
testing
in Unit 2.
The licensee
determined that the valve would not close
because
the
'
/
e
-19-
actuator
gears
were incorrectly installed during corrective maintenance
performed
in April 1993.
This item was
opened
to determine
why the
PMT did
not identify this error.
The incorrect installation of the actuator
gears
resulted
in
a valve stroke
time approximately half of the normal stroke time.
Two postmaintenance
tests
performed in 1993,
an
ASME Section
XI stroke test
and
a static diagnostic test
of the motor-operated
valve
(MOV), included data which showed the reduced
However,
the licensee
did not recognize that this data
demonstrated
a degraded
condition in the actuator.
The inspector
reviewed the
PMT to determine
why the licensee
did not identify the reduced
valve stroke
time.
The inspector
noted that the purpose of the
MOV full diagnostic test
was to
verify the capability of the valve to perform its design function.
Therefore,
the primary function of the diagnostic test
was to ensure that the operator
developed
enough thrust to operate
the valve under design basis conditions.
The inspector
found that the diagnostic testing
procedure
i'ncluded
a checklist
used
to determine
the condition of the
MOV.
The cf ecklist included
18 specific inspection criteria (e.g,, thrust/torque
outside target
band) with
acceptance
criteria of either
"Yes" or "No" for both the as-found
and the as-
left diagnostic tests.
The inspector
was informed that the purpose of the
checklist
was to compare
each
one of these
individual acceptance
criteria and
ensure
the as-left condition was satisfactory.
The inspector
concluded that
this approach
would provide
18 separate
"snapshots"
of the valve's
performance.
However,
the diagnostic test
was not used to ensure that the
maintenance
activity was correctly performed
and did not provide
an overall
assessment
of the valve's
performance.
The inspector
noted that there
was not
a requirement
in the retest
section of
the work order or in the diagnostic testing procedure
to compare
the as-left
to the as-found
valve signatures
to identify any differences
in the traces,
Had the signatures
been
compared,
the traces
would have clearly showed that
the as-left stoke time was about one-half the as-found stroke time.
The inspector
also noted that the entire
PMT was not completed
by the
same
organization.
Specifically, the valve services
group
who performed the
maintenance
relied
on the
ASME Section
XI test group to verify proper valve
The valve services
engineers
assumed
the Section
XI test would
identify not only slower but faster valve stroke times.
Additionally, the
planners
appeared
to rely on existing test
procedu> es to develop the retest
requirements.
These existing procedures
may not have all the specific
acceptance
criteria for the maintenance
that
was
performed'ased
on this review, the inspector
concluded that the licensee
did not have
appropriate
acceptance
criteria in the full diagnostic test to identify the
maintenance
error with the gear changeout.
This is
a violation of 10 CFR Part 50, Appendix
B, Criteria V, which states
in part that procedures
shall
include appropriate quantitative or qualitative acceptance
criteria for
determining that important activities
have
been satisfactorily accomplished.
0
'
-20-
The inspector
noted that,
in March 1994,
the licensee's
testing
program
and
subsequent
evaluation of the valve's failure to close identified the problem
with the incorrectly installed gears.
The licensee's initial actions to
correct the maintenance
error
and evaluate
the significance of the condition
were appropriate.
As long-term corrective action,
the licensee
changed
the
MOV diagnostic
procedure
to ensure
the as-left
and as-found valve stroke times
are within ~5 percent of each other.
The inspector
concluded that these
corrective actions
were appropriate
to prevent
a similar problem with
installing the wrong gears
in the
MOV actuator.
At the exit meeting,
the
licensee
stated that the qualitative comparison
between
the as-left
and as-
found valve signatures
was included
as
a corrective action to the diagnostic
procedure.
Additionally, the inspector
noted that the safety significance of the valve
not closing
was low because
the primary safety functi~.. of the valve was to
open.
The basis for this observation
was discussed
in
NRC Inspection
Report 50-528,529,530/94-09.
The inspector also noted that although the
licensee
did not promptly respond to the inspector's
questions
concerning
the
adequacy of the
PMT, the final corrective actions
t'rom the 60-day
CRDR
evaluation of the event
appeared
to address
the problem with the post
maintenance
diagnostic testing.
Based
on these
considerations
the violation
is not being cited because
the criteria specified
in Section VII.B of the
Enforcement
Policy were satisfied.
8.2
Closed
Ins ection Followu
Item 528 9402-03:
Atmos heric
Dum
Valve
This followup item involved
a review of the licensee's
evaluation of the
required retests
for atmospheric
dump valve
(ADV) maintenance.
In January
1994,
the licensee
discovered that they did not perform
a nitrogen drop test
as
a retest after maintenance
on ADV-178.
The purpose of the drop test is to
verify system integrity and ensure
there is enough nitrogen to stroke the
ADYs
on
a loss of the normal air supply.
The licensee initiated condition
report/disposition
request
(CRDR) 1-4-0044 to evaluate
the test requirements
for ADVs.
The inspector
reviewed the
CRDR and discussed
the corrective actions with
Unit
1 management.
The licensee identified three factors that contributed to
not performing the nitrogen drop test after replacing the positioner
on
ADV-178.
First, the planner
used
a copy of a previous
work order
(WO) in the
data
base that did not include the drop test
as
a retest.
Second,
the
PM task
to replace
the positioner did not include the drop test
as
a retest.
Third,
the inspector
noted that the retest
requirements
were determined
by the unit
planners
and that the shift supervisor
must concur prior to releasing
the
to the field.
The shift supervisor
and the shift technical
advisor did not
recognize
the
need for the drop test to ensure operability prior to approving
the work.
Additionally, the back end review of the work did not identify the
problem.
'
J
!
l
-21-
The licensee
determined that the requirement to include the drop test
as
a
retest
was not consistent
between all three units.
The licensee
checked all
twelve
ADVs to ensure
a drop test
was satisfactorily completed.
Based
on this
review, the licensee
determined that all the
ADVs had satisfactorily completed
the drop test
and were operable.
Additionally, the licensee
updated
the
computer
based
copies of work orders to include the requirement for a drop
test.
The licensee
planned to include this event
as part of the industry events
briefing.
Additionally, the licensee initiated
an action to review all the
PH
tasks
associated
with the
ADVs and include the
$rop test for any
PH that
breaches
the nitrogen
system.
The inspector
concluded that the licensee's
corrective actions
were
appr )riate to verify the
operability of the
ADVs and to minimize the
potential for similar testing errors with the ADVs.
Based
on this review,
this specific issue
was closed.
However.
the inspector
noted that there
appeared
to be
a broader
issue
concerning
an over reliance
on the experience
of the work planner to correctly determine
the appropriate retest
requirements.
In this particular
case,
the planner did not factor in previous
history with this type of maintenance
on the
ADVs or the experience of the
other units.
At the exit meeting,
the licensee
stated that they
had
previously recognized this potential
problem
and were beginning to use
standardized
maintenance
instructions that would correct the problem.
The
inspector will continue to observe
the area of retests
to verify that the
appropriate retest
requirements
were identified in the work instructions.
9
FOLLOWUP ENGINEERING
(92903)
9. 1
0 en
Deviation
528 9326-02:
Desi nation of En ineer-In-Char e-
Units
1
2
and
3
This deviation occurred
when the licensee
designated
two managers
as
Engineer-in-Charge,
even though they were not in
a functional position to be
cognizant of complex problems
emerging
from plant operations.
As
a result,
the oversight
intended
by ANSI/ANS 3. 1-1978,
regarding determining
when
consultants
are
needed
to support licensee
engineering
in resolving complex
problems,
was not provided.
The licensee's
corrective action
was to designate
the Assistant
Vice President
of Engineering
and Projects
as Engineer-in-Charge
after completing
a
10 CFR 50.59 evaluation of a change to the Updated Final Safety Analysis
Report
(UFSAR) for the commitment to the qualification requirements
of
ANSI/ANS-3. 1.
However,
equality Assurance
(gA) concluded that the change
in
commitment constituted
a reduction in the
gA plan
and that the change
in
commitment required
NRC approval prior to implementation.
At the completion
of the inspection period,
the licensee
had prepared,
but not submitted,
a
change
to the
UFSAR for NRC approval.
l
'
-22-
The inspector
concluded that the deviation still existed.
This item will
remain
open pending
NRC approval of the
USFAR change.
10
FOLLOWUP PLANT SUPPORT
(92904)
10.
1
Status of Actions to
Im rove the Environment for
Em lo ee Identification
and Resolution of Safet
Concerns
0
On July 7,
1993,
the
NRC requested
that the licensee
provide
a written
description of actions to be taken to correct
any potential chilling effect
after
a Department of Labor Administrative
Law Judge
(DOL/ALJ) found that the
licensee
discriminated
against
a contract
employee for engaging
in protected
activity.
At the time, the
DOL action represented
the third DOL/ALJ finding
against
the licensee
in 4 years.
The
NRC previously issued Notices of
Violation and
imposed Civil
P nalties after the first two DOL/ALJ findings.
The licensee
response
to the
NRC request
was provided in a letter dated
August 20,
1993.
Some of the completed or planned actions described
in the
'e.i~r included:
discussi ins of expectations
and
r~ sponsibilitie.
between
the
Executive Vice President,
Nuclear
and Palo Verde supervisors,
managers,
and
directors; training in the area of employment discrimination for managers,
supervisors,
and front-line employees;
an independent
assessment
of the
factors which assist
or impede
Palo Verde employees
in raising safety issues;
meetings with employees
regarding
management's
expectations
for raising safety
concerns;
an evaluation of the Palo Verde Employee
Concerns
Program;
and plans
for additional training to encourage
employees
to report concerns
and to
provide managers
with guidance
in responding to concerns,
Through discussions
with licensee
personnel
and review of documents,
the
inspector confirmed that the licensee
had completed
most of the actions
described
in the August 20,
1993, letter.
The inspector also reviewed
memorandums
to all employees
and publications
which described
expectations
for
fostering
an environment
where concerns
can
be raised
and for resolving
concerns
once they are identified.
In April 1994,
the licensee initiated
a
training course for front-line employees
which was designed
to promote the
communication of issues
to management.
The training course,
"Can
We Talk,"
was scheduled
to continue through July 1994.
A different version of the
course,
with emphasis
on accepting
and resolving concerns,
had previously
been
presented
to management
personnel.
The
NRC held three
management
meetings with the licensee
on January
25,
March 21,
and April 28,
1994.
During these
meetings
the licensee
discussed
actions
they had taken to improve the
Employee
Concerns
Program.
In addition,
the licensee
had recently put
a
new program into effe'ct for management
issues
which are not resolved informally.
The program
was designated
as the
Management
Issues
Tracking Resolution
(MITR) and will be used for nontechnical
concerns.
Technical
concerns will be resolved
through the existing
CRDR
program although
changes
to the program
have
been
made to allow for an appeal
if an individual did not agree with the resolution of an issue.
'
I
'
'0
-23-
Although the overall effectiveness
of the licensee's
actions to foster
an
environment for employee identification and resolution of safety concerns
was
not assessed,
the actions
may be having
an effect.
In particular,
the rate at
which concerns
are being presented
to the
NRC has decreased
which may indicate
that licensee
personnel
feel
more comfortable with allowing management
to
resolve
the concerns.
A followup inspection will be performed to review the
effectiveness
of the licensee's
actions.
1 1
IN OFFICE
REVIEW OF
LERs
(90712)
Unit 1:
Revision 0, Surveillance
Requirement
4.8.4.
1 Not Fully Met
Unit 2:
Revision 0, Reactor Trip and Auxiliary Feedwater
Actuation
Signals
Following Degraded
Voltage
on Non-Class
1E 4160V Bus
Unit 3:
Revision 0, Daily Surveillance
Test for Reactor
Power Channel
Calibration
Checks
Not Satisfactorily Completed
0'
ATTACHMENT 1
1
PERSONS
CONTACTED
Arizona Public Service
Com an
R.
- J
- R.
- S
J.
4'B
W.
- S
J.
- A.
R.
- D
S.D
B.
- W.
- A.
- D
- J
D.
F.
- K.
- B
- M
- J
C.
- B
- E
J.
- F
J,
S.
- J
- p
1.2
e 5 Haintenance
Others
Adney, Plant Manager,
Unit 3
Bailey, Assistant
Vice President,
Nuclear Engineering
Bouquot,
Supervisor,
equality Assurance
Audits
Burns, Supervisor,
Nuclear Engineering
Department
Dennis,
Manager,
Operations
Standards
Cherba,
Manager,
equality Assurance
Chapin,
Manager,
Refueling
and Maintenance
Services
Coppoch,
SupervIsor,
Valve Services
Dennis,
Manager,
Operations
Standards
Fakhar,
Manager,
Mechanical
Group, Site Technical
Suppo
Flood, Plant Manager,
Unit 2
Garchow, Director, Site Technical
Support
Gouge, Director, Plant Support
Grabo,
Supervisor,
Nuclear Regulatory Affairs
Ide, Plant Manager,
Unit
1
Kraini k, Manager,
Nuclear Regulatory Aiba. rs
Larkin, Senior Engineer,
Nuclear Regulatory Affairs
Levine, Vice President,
Nuclear Production
Hauldin, Director, Site Maintenance
and Modifications
Riedel,
Manager,
Operations,
Unit
1
Roberson,
Senior Engineer,
Nuclear Regulatory Affairs
Rosen,
Acting-Manager,
equality Control/equality
Assuranc
Salazar,
Supervisor,
Valve Services
Scott, Assistant
Plant Manager,
Unit 3
Seaman,
Director, equality Assurance
and Control
Simko, Hanager,
Valve Services
Simpson,
Vice-President
Nuclear Support
Steward,
Manager,
Radiation Protection
Swirbul, Manager,
Nuclear Engineering
Department
Terry, General
Manager,
Nuclear Records
Management
Troisi, Manager,
Site Technical
Support
Velotta, Director, Training
Wiley, Manager,
Operations,
Unit 2
- J
- R.
- F
Draper,
Site Representative,
Southern California Edison
Henry, Site Representative,
Salt River Project
Gowers,
Site Representative,
El
Paso Electric
". Denotes
personnel
in attendance
at the Exit meeting held with the
NRC
resident
inspectors
on May 12,
1994.
0
I
0
2
EXIT MEETING
An exit meeting
was conducted
on Hay 12,
1994.
During this meeting,
the
inspectors
summarized
the
scope
and findings of the report.
The licensee
acknowledged
the inspection findings documented
in this report.
The licensee
did not identify as proprietary
any information provided to, or reviewed by,
the inspectors.
1
1
0