ML17311A245
| ML17311A245 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 08/30/1994 |
| From: | Wong H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML17311A243 | List: |
| References | |
| 50-528-94-22, 50-529-94-22, 50-530-94-22, NUDOCS 9409120063 | |
| Download: ML17311A245 (44) | |
See also: IR 05000528/1994022
Text
PPENDIX B
U.S.
NUCLEAR REGULATORY COMMISSION
REGION IV
Inspection Report:
50-528/94-22
50-529/94-22
50-530/94-22
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:
June
12 through July 23,
1994
Approved:
Inspectors:
K. Johnston,
Senior Resident
Inspector
H. Freeman,
Resident
Inspector
J. Kramer, Resident
Inspector
A. MacDougall, Resident
Inspector
D. Acker, Project Inspector
g,
e
,
eac or
r
c
rane
go PQ
a e
ns ection
S mmar
td:
t ti,
di
p tt
dpi
t tt,
it
response
to events,
operational
safety verification,
and maintenance
and
surveillance observations.
esu ts
Units
1
2
and
3
~
Plant
0 erations
In June,
Unit
1 operators identified that
a routine channel calibration check
of core protection calculator channel
"D" could not be performed
because
a
reactor coolant system temperature
input was fluctuating greater
than the
channel calibration check acceptance criteria.
However, the magnitude of
channel fluctuations
had changed little since early
1993
and
had not been
properly addressed
by operations
(Section 2.1).
t
The
NRC inspectors
noted unauthorized
and inconsistent
operators
aids in the
control
rooms
(Section 3. 1).
9409i20063 940906
ADQCK 05000MB'.
8
'
e
l
I
The
NRC inspectors
noted unauthorized
and inconsistent
operator
aids in the
control
rooms (Section
3. 1).
An alert
and questioning auxiliary operator identified
a leak in the Unit
1
spray
pond piping during
a routine tour (Section 4. 1).
~
Maintenance
The planning
and performance of an emergent repair to a leak in the spray
pond
piping was thorough
and well implemented.
Engineering evaluation of the
failure was thorough
(Section
4. 1).
En ineerin
While engineering's
evaluation of the cause
and safety
impact of fluctuations
in hot leg temperature
was thorough,
they missed
an
>pportunity to identify
that the daily channel calibration check of the
CPC could not be performed
(Section 2.1).
Engineering
appears
to have
made progress
in improving the performance
and
reliability of,the feedwater
and steam
bypass control
systems.
Additionally,
they appear to be pursuing further modifications to further improve
performance
(Section 6).
Engineering
has completed
a review of a cable installation data
base
which had
previously not been well controlled
and
was not reliable.
The. licensee
has
updated
the data
base
and
has
improved controls to assure
future data
base
reliability (Section 7).
Plant
Su
ort
Two portable chemistry monitoring instruments
were found by the inspector to
have
been installed for extended
periods.
The licensee
responded
quickly to
remove the monitors
and evaluate their procedures
for the use of temporary
monitoring equipment
(Section
5. 1)...
The licensee
has
used
temporary shielding in areas of high radiation for
extended
periods without aggressively
pursuing
permanent
solutions
(Section 5.2).
Material condition appeared
to have deteriorated
in some areas.
In Unit 3,
an
excessive
amount of debris
from maintenance
and cleaning activities was noted.
Additionally,
a program to monitor and minimize boric acid leaks in valve
packings
appeared
not to have
been fully implemented
(Section 3.4).
Also in
Unit 3,
pump junction box was not fully secured
(Section 3.3).
I
I
I
/il
I
tI
'I
I
f
~
Mana ement Overview
During the inspection,
several
findings were identified that highlighted
an
apparent
lack of plant management
in the field.
For example,
a month after
a
refueling outage
the inspector
noted material condition weaknesses
in Unit 3
which could
be attributed to outage work.
It was also noted that, during this
period, licensee
management
focused
a substantial
amount of time on the
reorganization
selection
process.
Summar
of Ins ection Findin s:
~
One violation of NRC requirements
was identified (Section
2. 1).
Attachment:
Persons
Contacted
and Exit Meeting
]
t
i~
f,l
I
DETAILS
1
PLANT STATUS
.
1.1
Unit
1
Unit
1 operated
at 86 percent
power from June
12-30 when the licensee
raised
reactor
power to 98 percent
in response
to high electric
demand
on the
southwestern
grid.
Reactor
power was limited to 98 percent for the rest of
the inspection
period due to two inoperable
On July
6, the licensee
implemented
a Technical Specification
(TS) change
which
allowed operation at
a 10'F lower
RCS temperature.
1.2
Unit
2
Unit 2 began
the inspection period in Mode
1 at 86 percent
power.
On
June
30,
1994,
the unit increased
power to 100 percent
due to high electric
demand
on the southwestern
grid.
On July 8, the licensee
decreased
power to
88 percent,
after the electric
demand
had decreased,
and remained there
through the
end of the inspection period.
Power was returned to 88 percent
vice 86 percent
based
on
a revised calculation of steam generator
tube dryout.
Also on July 8,
a management
meeting
was held in the Region
IV office in
Arlington, Texas,
to discuss
the
May 28,
1994, reactor trip.
1.3
Unit 3
Unit 3 began
the inspection period in Mode 5, completing the fourth refueling
outage.
The unit commenced
a normal reactor startup
and entered
Mode
2
operations
on June
18.
On June
24, the unit completed testing
and raised
power to
100 percent.
The unit remained
at essentially
100 percent
through
the
end of the inspection period.
2
ONSITE
RESPONSE
TO
EVENTS (93702)
2. 1
Unit
1
RCS Hot Le
Tem erature
Fluctuations
On June
19,
1994.
a reactor operator
noted that the digital readout of
calculated
thermal
power on
CPC Channel
D was oscillating by more than
6 percent
power.
The shift supervisor
concluded that the
TS surveillance
requirement
to calibrate the calculated
thermal
power to within a 2 percent of
the secondary calorimetric power could not be performed
because
the magnitude
of the oscillations
was greater
than z 2 percent
(4 percent absolute).
As
a
result,
the shift supervisor declared
CPC Channel
and placed the
affected reactor protection functions in bypass.
The licensee
determined
that the large fluctuation in c lculated thermal
power
was caused
by
a known fluctuation in the
CPC Channel
D Loop
2 hot leg
temperature
(T,.) instrument
used to calculate
thermal
power.
The fluctuation
appears
to be actual
loop temperature
fluctuations
and not an instrument
e
l
issue.
The licensee
developed
(THOD) to upgrade
a
nonsafety-related
T.. resistance
temperature
detector
(RTD) that displayed
less fluctuations
and to use it as the input to the
CPC.
On July 2, the
licensee
installed the
TMOD and returned
CPC Channel
D to service.
The inspector
reviewed the
10
CFR 50.59 evaluation for installation of the
THOD, the
TS limiting conditions for operation
(LCO) and surveillance test
requirements,
the engineering
evaluation of the cause of the Channel
D hot leg
temperature
fluctuations,
and the plant review board's
response
to an
engineering
presentation
of the hot leg temperature
fluctuations.
The
inspector
conducted
a field verification of the
THOD installation.
The
inspector
concluded that:
Engineering
had identified oscillations of up to 5'F in the Unit
1
Channel
0 hot leg temperature
input to the
on February
18,
1993.
They identified that the temperature
fluctuations were due to hot leg
temperature stratification.
~
Engineering
subsequently
concluded that the fluctuations did not create
a situation adverse
to safety,
and the
CPC was able to perform its
design fgnction.
Their evaluation of the cause
and safety impact of the
fluctuations in hot leg temperature
was thorough.
Operators
were performing routine channel calibration checks of CPC
Channel
0 and did not conclude that the check
was out of calibration due
to the magnitude of the temperature
fluctuations until June
1994,
even
though the magnitude of the fluctuations
had
changed little since early
1993.
As
a result,
the
TS requirement to perform
a channel calibration
was not performed.
~
Licensee
management
missed opportunities to identify the impact of the
temperature
fluctuations
on the channel calibration check.
~
The development
and implementation of the
THOD was appropriate.
2, 1. 1
Engineering
Evaluation
On February
18,
1993,
the nuclear fuel engineering
analysis
group first
identified that the Unit
1
Loop
2 hot leg Channel
0 temperature
instrument
exhibited oscillations of up to 5'F.
Engineering
noted that the magnitude of
the oscillations
were substantially larger than
any similar instrument
on
site.
The licensee initiated
an engineering
evaluation
(EER 93-RC-017)
to'etermine
the cause of the fluctuation.
Engineering
gathered
data
from the instrument
and the
RTD.
The data
was
analyzed for any sharp
jumps or discontinuities,
which could indicate
component failure, but none were found.
The plotted data
appeared
to have
an
exponential
shape,
which was the expected
shape for an
RTD responding to an
actual
temperature
fluctuation.
Next, the licensee
analyzed
the data using
l
I>I
l,
t
t
f
fast Fourier transform analysis
to determine if there were any periodic
events,
such
as electrical
noise,
which could be the source of the
fluctuations.
The analysis
revealed that the fluctuations
appeared
to be
random
and were not the result of a periodic driving event.
Engineering
concluded
in the evaluation that the observed fluctuations in temperature
appeared
to be the result of the
RTD responding
to actual
changes
in the
temperatures
The
licensee
had previously replaced
another
RTD that
had
exhibited similar fluctuations.
The
new
RTD continued to exhibit the
same
fluctuations.
0
In January
1994,
the licensee
completed
a study
and concluded that the
fluctuations were due to
RCS hot leg stratification effects.
The study
included
a review of the impact of the temperature
variation
on the
CPC.
The
licensee
concluded that the only effect of the fluctuation on the safety-
related functions for the
CPC calculated
thermal
power was for protection
against
a 12-finger control element
assembly
(CEA) drop event.
The licensee
concluded that for a 12-finger
CEA dropped in the center of the core,
the
neutron detectors
may not detect
a flux tilt or power shift; however,
because
a 26 percent penalty factor would be automatically inserted for any 12-finger
CEA drop,
the reactor
would trip and the core would be protected.
The
inspector
reviewed the study
and agreed with the conclusions.
Engineering
noted to the inspector that the vendor,
Combustion
Engineering
(CE),
had conducted
a study of temperature stratification effects
on
CE reactors
which included data from Unit 1.
In a letter to the licensee
dated
February
22,
1991,
CE explained that the temperature stratification in
CE reactors
usually appears
to have
a static component,
the upper half of the
hot leg pipe is hotter than the lower half; phase rotation, the hottest
and
coldest point in the pipe is not necessarily
at the top and bottom of the
pipe,
but rotated
by an angle;
and
a dynamic component,
where
a semi-stable
vortex shifts from one portion of the pipe to another semi-stable
position.
CE had identified these conditions in other
CE plants.
At the time,
however,
Unit
1 did not exhibit the dynamic component.
Finally,
CE explained that the
characteristics
of the stratification depended
on numerous factors including
fuel loading,
rod position,
and core
age
and that the. characteristics
would
change
over time.
The inspector
concluded that the licensee
conducted
a thorough review of the
cause
and effects of the hot leg temperature stratification issue.
The
inspector
agreed with the licensee's
conclusion that the
CPC had
enough
margin
to account for the fluctuations
and that the core
was not in an unreviewed
condition.
The inspector
noted that this review had
been concluded
in early
1994.
As discussed
below, the inspector
was concerned that the effects of the
temperature
fluctuations
on the routine performance of CPC channel calibration
check were not fully evaluated.
2. 1.2
TS Verification
Facility TS require that
a channel calibration check
be performed every
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to verify that the linear power level, the
CPC thermal
power,
and the
l
l
(
.l'(
I
i
,
I
CPC nuclear
power signals
are within M percent of the calorimetric power.
This verification is conducted
as part of the "Routine Surveillance Daily
Hidnight Logs," Procedure
The procedure directs the operators
to
record
CPC total thermal
power,
CPC nuclear
power,
and secondary calorimetric
power.
The procedure
required that the
CPC channel
be calibrated if either
thermal
power or nuclear
power was more than
2 percent
above or below the
actual
(secondary
calorimetric) reading.
On June
19,
1994, operators
noted during the channel calibration check that
CPC Channel
D thermal
power was fluctuating by more than
6 percent.
Reactor
engineering
was contacted
when
CPC Channel
D was declared
and
determined
that
known fluctuations in the Channel
D T., instrument
were
causing
the Fluctuations
in
CPC thermal
power.
The inspector determined
in
a review of engineering
data
and operator
interviews that there
had not been significant change
in the fluctuations of
CPC Channel
D from February
1993 to June
1994.
Since
1 degree of change of
temperature
across
the reactor
core represents
a change of about 1.5 percent
power,
the fluctuations of 4 to 5 degrees,
measured
in February
1993,
would
have
caused
the calculated
thermal
power to consistently deviate greater
than
the H percent,TS limit.
The inspector concluded that,
since February
1993,
the licensee
could not have acceptably
performed the required
channel
calibration.
This is
a violation of TS 4.3. 1. 1 (Notice of Violation 528/9422-
Ol).
The inspector recognized that the fluctuations in thermal
power did not create
a situation
adverse
to safety
(See Section
2. 1. 1)
and that
CPC Channel
D was
able to perform its design function.
However, this violation
was being cited
because
operators
had not recognized for over
a year that the calibration
check could not be adequately
performed.
Additionally, plant management
missed opportunities to identify the effects of the temperature
fluctuations
on the channel
calibration checks
(Section
2. 1.3).
The inspector
questioned
why operators
had not recognized earlier that the
channel calibration check could not be adequately
performed
on
CPC Channel
D.
The inspector
found from discussions
with operators
that they'ypically'ook
an informal
mean value of the fluctuating instrument reading.
The inspector
found that the licensee
did not have formal guidance for operators
to evaluate
oscillating or fluctuating i'nstrument readings.
The inspector
questioned
whether there
were other routine measurements
or readings
taken from
fluctuating instruments
which required further evaluation.
The inspector
discussed
these
concerns
with licensee
management
who indicated that the
reading of fluctuating instruments will be evaluated.
The inspector will
review this issue further in conjunction with the licensee's
response
to the
violation.
2.1.3
Plant
Review Board
(PRB) Review
The inspector
noted that in April 1994 representatives
from plant engineering
made
a presentation
to the
PRB concerning
the Unit
1 T fluctuations.
The
I
'l
J
I 'f
l
ill
'If
(, I
l
l
inspector
reviewed the
PRB minutes
and noted that engineering
had questioned
how the
TS verification was performed.
In the presentation,
engineering
stated that "the temperature
reading variability has
added
some difficulty for
the
CPC thermal
power calibration in that it was difficult to decide
what
temperature
value
(an average,
the lowest,
the highest?)
to select for use in
the thermal
power calculation."
Engineering
also stated that "there
was not
any definite operations
guidance
on how to select the appropriate
reading."
Based
on the engineering
presentation,
the
PRB board concluded that there
was
not an unreviewed safety question or safety concern with the T., fluctuations.
However,
the licensee
did not conduct
any followup to investigate the
questions
posed
by engineering
concerning
the thermal
power calibration.
The
inspector
concluded that licensee
management
had missed
an opportunity to
identify the problem in April 1994.
Additionally, the inspector
concluded
that the licensee
had missed
a similar opportunity to identify the effects of
the temperature
fluctuations
when they were first identified in February
1993.
2. 1.4
THOD Development
and Implementation
The licensee
developed
a
THOD to swap
an installed nonsafety-related
T RTD,
used for input:to the core operating limit supervisory
system, for the safety-
related
RTD used
as
an input to
CPC Channel
D.
The inspector reviewed the
10
CFR 50.59 evaluation for the
THOD and agreed with the licensee's
conclusion
that the
THDD did not create
an unreviewed safety question
and was acceptable
for a short period.
The inspector
conducted
a walkdown of the affected electrical penetrations
and
cable
raceways.
The inspector
noted that
one of the covers
had
a missing
and
stripped fastener.
The inspector
was concerned
that the electrical
cover was not water tight due to the missing fastener.
The
licensee initiated
a work request to correctly install the fastener.
The
inspector
concluded that the licensee's
corrective actions
wet e appropriate.
2. 1.5
Licensee Actions
Based
on the inspector's
concerns,
the licensee
formed
a team to evaluate
the
effect of the T, fluctuations
on performance of the
CPC calibrations.
The
licensee
also
was issuing
a licensee
event report describing the problem with
CPC Channel
0 and concluded that
CPC Channel
D was inoperable for the last
2
operating cycles.
The licensee
event report will be reviewed in
a future
inspection.
3
OPERATIONAL SAFETY VERIFICATION
(71707)
3.1
Units 1.
2.
and 3.
Use of 0 erator Aids and Control
Room Labelin
On June
28,
1994,
the inspector
observed
red grease
)en marks
on the control
room
(CR) operating
switches for CR heating, ventilation
and air
conditioning
(HVAC) in Unit 2.
The inspector
was informed that the marks were
placed
on the switches to aid the operators
in the identification of valves
I
f
Ij
,i'I
11
l~
required to be open during power operations.
Further inspection
revealed
the
same
marks present
in Unit 1.
The inspector
noted that the marks were not
controlled under the licensee's
operator
aid program
and notified operations
management
of the unauthorized
markings
on the
CR boards.
The licensee
removed the markings.
The inspector
checked
the consistency of the
CR labels,
placards,
and operator
aids.
The inspector
noted several
minor discrepancies
and brought them to the
attention of operations
management.
These
aids included
a plexiglass
cover
over
a Unit 2 reactor coolant
pump hand switch, apparently
used to prevent
operators
from inadvertently turning the
pump off, which was not used in
either Units
1 or 3.
Additionally, small placards
in Unit 3 cautioned that
synchronization
key switches
should not be inserted into more than
one
selector
switch at
a time.
Similar placards
were not used in Units
1 and 2.
The inspector
noted that the licensee
had
a detailed
procedure
governing the
use of operator aids.
The procedure
had
been developed
in response
to
weaknesses
identified in 1989.
The inspector
expressed
concern that the
program
was not being fully implemented.
In response
to the inspector's
concerns,
the licensee
assigned
the Unit
1 operations
department
leader to
review the use,of operator
aids
and the process
of labeling control
room
equipment.
On July 25, the inspector
observed that the
CR HVAC switch markings were once
again present
on the switches
in Unit 1.
The inspector notified operations
management
of the unauthorized
markings
on the
CR boards,
and once again the
licensee
removed the markings.
The licensee initiated
a night order to inform
operators
of management's
expectations
for marking
and labeling plant
equipment.
At the exit meeting,
the inspector
expressed
concern that
management
had not fully communicated
the expectation that the markings not be
used after the first incident,
nor had they identified the markings
themselves.
3.2
Unit
1 - Walkdown of En ineered
Safet
Features
E ui ment
Room
Ventilation
S stem
The inspector
reviewed the Updated Final Safety Analysis Report,
conducted
a
field walkdown,
and reviewed the design
heat loading calculation for the
equipment
room ventilation system.
The
ESF equipment
room ventilation system provides
room cooling for four
safety-related
125-Vdc and
120-Vac distribution systems.
Each system is
located
in
a separate
room that is cooled
by the normal control building
ventilation system.
The
ESF equipment
room ventilation system provides
cooling to the equipment
rooms
on
a loss of normal ventilation and
on
a loss
of offsite power or safety actuation signal.
The inspector
concluded that the
ESF equipment
room ventilation system would
provide sufficient cooling flow to ensure that the safety-related
120-Vac
and
125-Vdc electrical distribution systems
remained
The inspector
I
'I
!h
1
,J,l
,
I
-10-
noted
a minor material deficiency involving a missing nut on
a ventilation
damper support plate that
was promptly corrected.
The inspector
noted that the alarm response
procedure for a high temperature
alarm in the
ESF equipment
room did not indicate at what point TS
LCOs should
be entered.
The licensee
stated that the surveillance test procedure for
inoperable essential
chilled water
and ventilation systems
directed the
equipment
room to be declared
inoperable if both the normal
and essential
ventilation systems
were inoperable.
This would put the plant in a 72-hour
TS
shutdown
LCO.
The licensee
agreed that the alarm response
procedure
should
reference
the surveillance test procedure
and initiated an update to the alarm
response
procedure.
The inspector
concluded that the licensee
actions
were
appropriate.
3.3
Auxiliar
Pum
Junction
Box Unit 3
On July 5,
1994,
the inspector
noted that the cover to
a junction box on the
Unit 3, turbine-driven auxiliary feedwater
pump was not fully secured.
The
inspector contacted
the shift supervisor
and raised
concerns
about the
potential
impact of a high steam
environment
on the internal
components.
When informed by the inspector of the junction box cover,
the supervisor
immediately sent
an electrician to open
and inspect the components
in the
junction box.
The electrician
inspected
the junction box and did not find any
degraded
components.
Following the inspection,
the electrician fully secured
the junction box cover.
The licensee initiated
on the effect that the
condition had
on the pump's operability.
The junction box, which housed
power
and control cables to the turbine's trip and throttle valve motor operator
(AFA-HV-54), was approximately
14"x16"x6" and contained
a hinged cover.
The
junction box had four mechanisms
to secure
the cover but only one
had
been
engaged.
The licensee
conducted
a seismic review and concluded that one
mechanism
was adequate
to keep the cover in position during
a seismic event.
Additionally, the licensee
concluded that the junction box was not in a harsh
environment
and that the humidity during
pump operation
would not have
caused
electrical
problems to the trip and throttle valve motor operator.
The
inspector
agreed with the licensee's
conclusions.
Finally, the licensee
initiated
an investigation
on
how the junction box cover
became
not fully
secured.
The inspector
concluded that the licensee
took prompt corrective actions
and
that the impact of the condition did not affect the operability of the
pump.
3.4
Material Conditions - Unit 3
On July 14,
1994. during
a routine tour of the
77 foot level of the east
piping penetration
room in Unit 3, the inspector
noted that the material
conditions
had degraded
over the past
few months.
For example,
the inspector
1
I
-ll-
found several
valves which had boric acid accumulation
in the yoke area.
The
inspector
noted
a safety injection vent valve with a continuous
stream
discharging
into
a drain through
a tygon tube
and contacted
the operations
crew to secure
the leak.
The inspector also noted
a shutdown cooling system
valve that
had
a large
amount of dried boric acid crystals
on the valve body
and
on the floor.
Finally, the inspector
noted debris
(a cut mechanical
lock,
a bag of parts,
a roll of electrical
tape,
and other residual
trash)
from the
recent refueling outage that
had not been
removed
from the area.
The
inspector
concluded that the material condition
and housekeeping
in the space
did not represent
safety hazards,
but were indicative of an overall declining
trend.
The inspector
reviewed the licensee's
program for maintaining valve material
conditions
and minimizing valve packing leaks.
The inspector
noted that the
licensee
has
a zone inspection
program where
each operations
crew was
responsible
for
a specific area.
Each crew was expected
to perform an area
inspection
once
each
work cycle (every
6 weeks)
and
was to submit work
requests
when needed.
The inspector
reviewed the previous inspection for the
area
and noted that it had
been
completed
on July
13 but had not identified
the leaking vent valve or the boric acid
on the shutdown cooling system valve.
The inspector
also noted that the program
was more effectively used
by some
crews than others.
For example,
one previous inspection of three
zones
conducted
on February
8 (several
hundred valves) did not identify any
discrepancies
where other area
inspections typically identified 20 to
30 discrepancies.
The inspector discussed
the zone inspection
program
and general
plant
conditions with the licensee.
The inspector noted that the program was not
formally controlled
and
was not consistently
implemented.
Licensee
management
concurred that the program
has not been fully effective.
They anticipated
that the system responsibilities
assigned
to maintenance
crews in the
re-engineering
process
would promote material condition improvements.
The inspector
found in discussion
with Unit 3 management
that managers
had not
toured the area recently.
This was,of concern
since Unit 3 had recently
restarted
from a refueling outage.
Additionally, the- inspector noted that the
licensee's
response
to the previous Systematic
Assessment
of Licensee
Performance
committed to having management
in the field on
a frequent basis to
identify problems.
The inspector
concluded that the licensee's
program for
material
control
and housekeeping
required
more management
attention.
3.5
Unit 2 Crane
Breaker Closed
and Caution
Ta
ed "0 en"
On July 1,
1994,
the inspector
noted the breaker for an auxiliary building
crane
was closed with a caution tag
on the breaker stating "contact safety
department
before operating crane/energizing
breaker.",
The inspector
contacted
the safety department
and determined that the crane
was not being
used
and that the breaker
should
have
been in the o'en position.
Operations
was informed,
and the breaker
was opened.
I
f
1(
il,(
il,
'I
0
-12-
The licensee
had placed
the caution tag
on the crane breaker
as
an interim
corrective action until the crane's
pendant
could
be modified to comply with
Occupational
Safety
and Health Administration
(OSHA) standards
to have
an
emergency
stop
push button or equivalent.
As
a result of the inspector's
finding, the licensee
placed
an additional caution tag
on the control pendant
on all similar type cranes
in the plant
(11 total) to alert personnel
of the
potential
hazard
in operating this type of crane
and replaced
the caution tag
on the breaker with a danger tag.
The licensee
planned to evaluate
the
11 similar cranes
to determine
which were used frequently
and warranted
the
pendant modification.
They planned to remove
power from cranes that were not
frequently used.
The inspector
noted the quick and thorough response
of the licensee after the
inspector identified and informed the licensee of the problem.
The inspector
concluded that the licensee
actions
were adequate.
4
MAINTENANCE OBSERVATIONS
(62703)
During the inspection period,
the inspector
observed
and reviewed the selected
maintenance
activities listed below to verify compliance with 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 postmaintenance
testing.
Specifically, the inspector witnessed
portions of the following maintenance
activities:
4. 1
Unit
1
S ra
Pond
Pi in
Leak Due to Coatin
De radation
On July 10,
1994,
an auxiliary operator
(AO) noted water under
a portion of
the Train A spray
pond piping during
a routine tour.
The
AO inspected
the
piping and identified
a small pin hole leak in the piping.
The Train A spray
pond system
was declared
The spray
pond system is the ultimate
heat. sink for the essential
cooling water system which provides cooling water
to the essential
chilled water system,
the shutdown heat exchangers,
and the
emergency diesel
generators.
As
a result,
several
72-hour
TS
LCO action
statements
were entered.
The inspector
reviewed the work order to repair the leak,
observed
the
hydrostatic test of the repair,
and discussed
the leak with the licensee's
engineering
staFf.
The inspector
concluded that the licensee's initial
actions to solve the problem were good.
Specifically, the
AO was alert to a
deficient condition,
the planning
and conduct of the maintenance
was good,
and
the initial engineering
evaluation
was thorough.
The inspector
also noted
that the licensee
was evaluating
the scope of the overall underground
piping
inspection
program
based
on this failure.
I
I
/
I
.
4. 1. 1
Corrective Actions
-13-
The licensee
drained
the system,
removed
and installed
a spool
piece in the
piping,
and performed
an inside/outside
weld repair of the defect.
On
July 11, the licensee
reassembled
the pipe
and satisfactorily performed
a
hydrostatic test of the affected portions of the spray
pond system.
The
licensee
determined
that the piping failure was initiated by a defect in the
piping coatings
The licensee
conducted
a visual inspection of the coating
on
the inside of the accessible
portions of the disassembled
spray
pond piping
and did not identify any other defects.
The licensee
subsequently
declared
the spray
pond
system operable
and exited the
TS
LCO action statements.
The inspector
noted that the licensee
had conducted
visual inspections of
selected
portions of the spray
pond piping during the previous refueling
outages
in each unit.
About 450 linear feet of the underground
portions of
the spray
pond supply
and return lines
and
a small portion of piping to the
emergency diesel
generators
were inspected.
The inspector noted that the area
of the defect
was not included in the inspection
because
the piping was not
underground.
Representatives
from the Electric Power Research
Institute
performed the inspections
and concluded that, in general,
the piping was in
good condition .and that
no immediate corrective actions
were needed.
The
inspector
reviewed the reports
and noted there
was
one area in each unit where
there
appeared
to be
an actual
break in the coating that could lead to
accelerated
corrosion.
The inspector
learned that the licensee
had previously evaluated
the defects
and determined that,
based
on the
known corrosion rates
and the limited number
of defects,
the repairs
could
be deferred to the next refueling outage.
The
licensee
planned to perform additional visual inspections
during the upcoming
refueling outages
to determine
the change in the affected
areas
and to conduct
any required repairs.
The inspector
concluded that the licensee's
basis to
defer the repairs
was reasonable
and that the existing spray
pond piping
inspection
program
was adequate.
4.2
Unit 2
CEA Sli
Durin
Testin
On June
18,
1994, during the performance of CEA Operability Checks
(Surveillance
Procedure
CEA 60 slipped
about
2 inches
each time
it was given
a withdrawal
command
and then would withdraw as designed.
Operations
personnel
consulted with engineering
and the operations
manager
and
then placed
CEA 60 at the upper electrical limit (UEL) upon completion of the
surveillance to provid additional positive indication that the
CEA was fully
withdrawn and
had not slipped.
The other
CEAs remained at the program level
of UEL-2 (two steps
below the UEL).
The licensee initiated
a condition
report/disposition
request
to evaluate
the problem.
The inspector questioned
reactor engineering
about the placement of CEA 60.
Reactor engineering
stated
that the
CEA was within the
TS limit for deviation
from other
and that the
CEA position did not violate the core data
book.
i
-14-
In addition, reactor engineering
stated that having one
CEA 1.5 inch (two
steps)
further withdrawn at the top of the core would not adversely affect
core
power distribution or guide tube wear.
The inspector
agreed with the
licensee
conclusions.
The inspector
noted in
a conversation
with the Unit 2 reactor engineer that
he
was
unaware that
CEA 60 had
been positioned at the
UEL.
While there
was
'ittle
safety significance,
the inspector
was concerned
that
a week after the
CEA had
been repositioned,
the responsible
engineer
was not cognizant of the
condition.
The licensee
acknowledged
the inspector's
comments
and indicated
that the issue
would be further reviewed.
On July 16, the licensee
repaired
CEA 60.
Two defective
equipment
cards
were
replaced.
The licensee
returned
CEA 60 to program position.'he
licensee
planned to repair the defective cards
in their rework shop.
The inspector
reviewed the licensee's
troubleshooting
proces:; for the defective
cards
and
noted
no discrepancies.
4.3
Other Haintenance
Observations
The inspector
qbserved
portions of the following maintenance activities
and
determined
that they were performed acceptably:
~
Unit
Pump Governor
Power Supply Repairs
~
Unit 2 Control
Room Essential Air Handling Unit Cooling Coil and Bellows
Inspection Preventative
Haintenance
~
Honthly Preventative
Haintenance
on the Security Diesel
5
PLANT SUPPORT
(71750)
The inspector
performed routine tours of the units to verify that
radiological,
physical security,
and fire protection
programs
were implemented
in accordance
with facility policies
and regulatory requirements.
Included in
these tours were verifications of the accessibility to locked high radiation
areas,
posting of radiation areas,
physical security control,
and general
material conditions.
5. 1
Continuous
In-Line Chemistr
Honitors
During routine plant tours.
the inspector identified
a condition in Unit 3
where
a portable
oxygen detector
was installed to
a condensate
storage
tank
test connection to obtain
a continuous on-line reading.
The inspector
also
noted
a similar condition in Unit 2 where
a portable conductivity meter
was
installed to
a sample point on the auxiliary steam
condensate
receiver tank
outlet valve to provide
a continuous on-line reading.
The inspector
noted
that these installations
were not controlled
and
questioned
the licensee
concerning plant configuration control.
I
r'
I
(
'i
-15-
The licensee initiated
a condition report/disposition
request
to review the
control of these particular installations.
The licensee
determined that these
installations
were controlled
by approved
chemistry sampling procedures.
However, the inspector
was concerned that the intent of the procedures
was
primarily for short duration or "grab" type samples
and not for a condition
that
may require
a long-term continuous monitor.
The licensee
acknowledged
the inspector's
concern
and agreed to review the secondary
sampling
instruction procedure
to verify if the procedural
controls for continuous
sampling
were adequate.
The inspector
concluded that the licensee
had valid reasons for installing the
monitors, that they were being periodically reviewed
by chemistry
management,
and that they did not impact equipment operability.
The inspector
also noted
that the licensee
removed the monitors until the review of the procedure
was
completed.
The inspector
concluded that the licensee's
corrective actions
were prompt
and thorough.
5.2
Locked Hi
h Radiation Areas
Unit 3
On July 14,
1994, during
a routine tour of the Unit 3 auxiliary building, the
inspector
noted, that
some of the temporary shielding installed
around high
radiation
sources
had
been installed for extended
periods
up to 5 years.
For example,
the inspector
noted that the licensee
had installed temporary
shielding
and
a sign
on
a section of piping which stated that the radiation
levels
under the shielding met the conditions of a locked high radiation area.
Because
the shielding
was covered
by plastic sheeting,
the inspector
was
unable to view the installation.
The inspector
noted that the installation
had
been in place since
Narch
14,
1994.
The inspector discussed
the use of
temporary shielding with the licensee
and
was informed that temporary
shieldinp
was usually held in place
by plastic tie wraps or some other
nonpermanent
means.
Although the inspector noted that most temporary
shielding
was
removed after
2 weeks,
the inspector also noted
13 installations
which had
been
converted
to long-term use,
including four that were over
a
year old.
The inspector discussed
with radiation protection
management
the NRC's
guidance
on the use of temporary shielding
on areas that meet the requirements
of a locked high radiation area
as discussed
in NUREG/CR 5569,
"Health Physics
Positions
Data Base."
The
NUREG states
"other techniques
to reduce
source
term should
be
used (e.g.,
chemical
decontamination,
permanent shielding);
however,
as long
as reasonable
progress
is made toward the long-term fix (and
an effective system to preclude
unauthorized
removal of temporary shielding
exists),
the judicious
use of temporary shielding could
be justified on
an
interim basis."
The inspector
noted that the licensee
did not appear to be
aggressively
pursuing
the long-term fix.
The licensee
stated that they would
review the
use of temporary installations,
including shielding
and
modifications,
and attempt to limit their use.
The inspector
noted that the
licensee
had conducted
an audit
a few weeks earlier
and
had similar concerns
-16-
regarding
the
use of temporary shielding.
The inspector will follow up on the
licensee's
resolution of temporary installations
as part of a future routine
inspection.
6
FEEDWATER CONTROL SYSTEM (FWCS)/STEAM BYPASS
CONTROL SYSTEM (SBCS)
(71500)
The inspector
reviewed the design
and operation of the
FWCS and the
SBCS
and
discussed
recent
maintenance
problems concerning
these
systems with operators
and the system engineers.
The purpose of the inspection
was to determine
the
scope
and effectiveness
of the licensee's
long-term
FWCS and
SBCS improvement
program.
The inspector
noted that the licensee
has
made significant progress
in
correcting
a majority of problems with the
FWCS and
SBCS.
In 1991, the
licensee
performed major control
system modifications that significantly
reduced
the number of postreactor trip control
system complications.
For
example,
during
a 3-year period from 1989 to 1991 the site
had
19 reactor
trips which resulted
in
19 postreactor trip control
system complications
and
nine postreactor trip safety
system actuations.
After the modifications in
1991,
the site
has
had
a total of 13 reactor trips which resulted in
10 postreactor,trip
control
system complications
and
4 postreactor trip safety
system actuations.
The inspector determined that several
minor control
system problems still need
to be corrected with both the
FWCS and
SBCS.
These
problems include current
to pneumatic (I/P) transducer
and positioner zero drift, low power steam
generator
level oscillations,
and internal binding of the steam
bypass
control
valves
(SBCVs).
The licensee
has identified corrective actions for these
problems
and
has
scheduled
completion of the actions during the
1995 refueling
outages.
The inspector
also observed
a high level of management
involvement
to assure
that these corrective actions
are completed
as scheduled.
6. 1
SBCS Review
The inspector
reviewed the licensee's
corrective actions for SBCV problems
'identified during the Unit 2 load rejection
on May 14,
1994;
and the Unit 2
reactor trip on May 28.
SBCVs
1001
and
1004 were reported
as "jerky" during
the load rejection.
In addition,
valve
1004 did not fully close during the
The licensee
performed diagnostic testing of SBCVs
1001
and
1004 following the
load rejection
and determined that Valve 1001 operated
properly and Valve 1004
had
a positioner zero drift which prevented
the valve from fully closing.
A
work order was written to calibrate the positioner of Valve 1004.
The work
was scheduled
for May 20 but was delayed
due to
a conflict with scheduled
work
in Unit 1.
As
a result,
the positioner
was not recalibrated until after the
reactor trip on May 28.
The licensee attributed
the jerky response
of Valve 1004 to internal clearance
problems that
had
been previously identified.
In Unit 2, the licensee
has
I i
-17-
completed
internal
clearance
modifications
on two of the eight
SBCVs
(1001
and
1003) to improve the smoothness
of the valves stroke with steam.
These
modifications
have
been
completed
on all eight control valves in Units
1
and 3.
The modifications of the remaining six control valves in Unit 2 were
scheduled
during the
1995 refueling outage.
6.2
FWCS Review
During the Unit 2 load rejection
and reactor trip in May 1994, operators
had
to close the
1 economizer isolation valve due to excessive
feedwater flow, resulting in excessive
primary temperature
cooldown.
After
these
events,
the licensee calibrated
the economizer flow control valve and
determined
that the I/P had drifted
4 percent high.
As
a result,
when the
valve received
a signal
to close, it remained
approximately
4 percent
open.
The licensee
recalibrated
the I/P and the valve fully closed
when required.
The I/P drift was
a
common industry problem
and
was typically less
than
5 percent.
The licensee
was developing
a design modification to insert
a
negative
bias in the control circuit to ensure
the valve shuts after
a reactor
trip and during low power operations.
This modification was scheduled for
completion in September
1995.
The inspector
concluded that this improvement
should prevent;operator
intervention after
a reactor trip to prevent
overfeeding of the steam generator
and subsequent
overcooling of the primary
t
plant.
6.3
Meetin
With the Licensee
Re ardin
and
SBCS Problems
On July 8,
1994,
the licensee
met with the
NRC at the Region
IV office in
Arlington, Texas,
to discuss
the
May 28 reactor trip.
During this meeting,
the licensee
discussed
the history of problems with the
flow
control
system
and the
steam
bypas
control
system
and their plans for system
improvements
discussed
above.
7
DESIGN CHANGES AND MODIFICATIONS
(37551)
The licensee
used
a computer
based. system called, the
EE580 system,
to maintain
a data
base for cable installations.
As documented
in Inspection
Report 50-
528/89-12;
50-529/89-12;
50-530/89-12,
previous
problems with the
EE580 system
had
been
found.
The cover letter of Inspection
Report 50-528/89-12;
50-
529/89-12;
50-530/89-12
requested
that the licensee
provide
an action plan
and
commitments
to review and correct deficiencies with the
EE580 system.
Under the
EE580 process.
installation cards
were issued for design
changes
and
the
EE580 data
base
was marked with a "C" to alert personnel
that
a change
had
been
issued for the installation covered
by the card.
When the installation
was complete,
the field verified card
was returned,
verified to match the
design,
and the
"C" removed
from the
EE580 data
base.
However, in 1989 the
licensee
determined
that
many more cards
had
been
issued
than
had
been
returned with field verification so that over 100,000
items in the
EE580 data
base
were marked with a "C." making the design
change
process difficult and
potentially affecting the accuracy of the data
base.
,
-18-
The. licensee
provided their corrective actions for the
EE580 system in letters
to the
NRC dated
October
20,
1989,
and
December
21,
1990,
and committed that
restoration
and documented
confirmation of the
EE580 data
base
would be
completed
by August
15,
1991.
The letters
noted that
6000 of the original
100,000
open
items still remained to be resolved.
NRC Inspection
Report 50-528/91-05,
50-529/91-05,
50-530/91-05 identified that
an internal licensee letter dated January
31,
1991, determined that there were
approximately
2200 open
items remaining to be corrected.
The licensee
documented
that they were unable to retrieve
741 lost
EE580
installation cards
in an internal letter dated August 6,
1991.
The licensee
stated that this action
was acceptable
based
on satisfactory unit operations,
notation in the data
base that these installations
had outstanding
cards,
and
the fact that the loss of the cards
was not technically significant, since the
circuits would be reverified by their current design
process prior to any
changes.
7. 1
Discussion
The inspector
reviewed the
EE580 system to ascertain if recent modifications
had
been correctly entered
into the system
and to ascertain if the existing
data
base
had
been
updated
as committed to correct the previously noted
problems.
The inspector determined that licensee
Procedures
81AC-OCC07, Revision 3,
"Cable
and
Raceway Control
& Tracking System,"
Revision 4, "Plant
Design
Change
Program,"
Revision 5, "Final Engineering,"
and 81DP-
OCC25,
PCN 01,
"Cable
and
Raceway Control
8 Tracking System Activities,"
adequately
controlled changes
to the
EE580 data
base.
In addition, the
inspector
noted that the licensee's
guality Audits and Monitoring Department
Audit Report 92-011,
"Software guality Assurance," verified that the
EE580
program
had
a validation
and verification method that was initiated when
changes
to the
EE580
system
were made.
The inspector
selected
six cable trays,
including two with cables installed in
1993,
and veriFied that the number,
types,
and sizes of cables
in these trays
matched
the
EE580 data
base.
The inspector determined that the installations
matched
the
EE580 data
base,
except for one cable type which had
a slight
difference in the cable diameter;
the installed cables
were approximately
1. 1 inches
in diameter,
whereas
the
EE580 data
base
showed
them to be 1.4
inches in diameter.
The licensee
corrected
the
EE580 data
base.
The inspector
reviewed discrepancy
records
from
determined that guality Deficiency Reports
(and
issued
to request
engineering
resolution of any
EE580 data
base
and field installations.
Based
the inspector
considered
that the problems
were
problem with maintaining the
EE580 data
base.
1990 through
1994
and
other report types)
were being
differences
found between
the
on review of these
records,
not indicative of a systematic
P
'%
e
-19-
The inspector
determined that guality Control verified most aspects
of safety-
related
EE580 data
base related installations.
As noted in NRC Inspection
Report 50-528/89-12;
50-529/89-12;
50-530/89-12,
quality control also verified
initial EE580 installations'uring
the inspection,
the licensee
stated that
the
number of missing cards
had
been
reduced to 612, of which 179 involved
safety-related
equipment.
The inspector
noted that the licensee
had
based
acceptability of the missing data partly on unit operation.
The licensee
stated
that the
714 missing cards
from 1991
had
been
reduced to 612
as the
missing information was reverified by new changes
or missing cards
were found.
The inspector
noted that
10 CFR Part 50, Appendix R, safe
shutdown criteria
depended
on exact
knowledge of cable routing within and between fire areas.
The inspector
questioned
how unit operation
would show that the
EE580 data
base
was correct with respect
to cable routing.
The licensee
reviewed the
equipment
covered
by the 612 missing cards
and determined that
10 involved
cables,
5 of which were
10 CFR Part 50, Appendix R, cables.
The licensee
determined that the missing cards for three of the Appendix
R cables did not
involve any changes
to cable routing,
and that
no design
changes
were issued
which made
changes
to the other two cables
during the time that the missing
cards
were originally issued.
The licensee
concluded that no
10 CFR Part 50, Appendix R, cable routings were involved in the
612 missing cards.
The
licensee
also reviewed the other five cables,
determined that only two were
active,
and sighted the routing of these
cables
where they were accessible.
The licensee
determined that the
EE580 system
matched
the installations.
The licensee
determined that only 179 of the missing cards
were safety-
related.
The licensee
stated that they intended to sight equipment
as
'ecessary
to verify that the missing cards did not affect any installations.
The inspector determined that Procedure
Revision 4,
"System
Turnover," required engineering
signature verification that the
EE580 system
had
been
updated
using field verified installation cards for all design
changes.
The inspector
reviewed completed
EE580 cards
and did not identify any
problems.
The inspector
reviewed
a recent modification for station blackout
and verified
that selected
information from this modification had
been correctly entered
in
the
EE580 data
base.
7.2
Conclusion
The inspector
concluded that licensee
procedures
were acceptable
to properly
enter
new changes
in the
EE580 data
base
and resolve
any differences
between
field conditions
and the
EE580 data
base prior to making any design
modifications.
r
~ >
,I
t
-20-
The inspector
concluded that the licensee's
decision to suspend
actions to
locate the
714 missing
EE580 installation cards did not constitute
a failure
of the licensee
to perform the committed actions
associated
with the
EE580
data
base.
The inspector
concluded that the licensee's
review of cable installations
was
adequate
to ensure
that safety-related
cable routing information was correct
and that the licensee's
stated
action to sight installations involving the
missing
179 safety-related
EE580 cards
was adequate.
1
Persons
Contacted
ATTACHMENT
1. 1
Arizona Public Service
Com an
R. Adney, Plant Manager,
Unit 3
- J. Bailey, Vice President,
Nuclear Engineering
& Projects
L. Clyde, Operations
Manager,
Unit 3
- P. Crawley, Director, Nuclear Fuels
Management
E. Dutton, Supervisor,
guality Control, Unit 2
A. Fakhar,
Manager,
Site Mechanical
Engineering
- R. Flood, Plant Manager,
Unit
2
- D. Garchow, Director, Site Technical
Support
- B. Grabo,
Section
Leader Compliance,
Nuclear Regulatory Affairs
- T. Gray, Supervisor,
Radiation Engineering
- W. Ide, Plant Manager,
Unit
1
H. Kerwin, Maintenance
Manager,
Unit 3
- A. Krainik, Manager,
Nuclear Regulatory Affairs
- D. Larkin, Senior Engineer,
Nuclear Regulatory Affairs
- J. Levine, Vice President,
Nucle'ar Production
- 0, Hauldin, Director, Site Maintenance
and Modifications
- G. Overbeck,
Assistant to Vice President,
Nuclear Projects
F. Riedel, Operations
Manager,
Unit
1
- C, Russo,
Department
Leader,
Nuclear Assurance,
Maintenance
- J. Scott, Assistant
Plant Manager,
Unit 3
C.
Seaman,
Director, Nuclear Assurance
G. Shanker,
Department
Leader,
Nuclear Assurance,
Engineering
- W. Simko, Department
Leader,
Nuclear Assurance,
Strategic Analysis
E. Simpson,
Vice President,
Nuclear
Support
J, Velotta, Director, Training
P. Wiley, Operations
Manager,
Unit 2
1.2
NRC Personnel
- K. Johnston,
Senior Resident
Inspector
- H. Freeman,
Resident
Inspector
- J. Kramer,
Resident
Inspector
- A. HacDougall,
Resident
Inspector
1.3
Others
.
- F. Gowers,
Site Representative,
El
Paso Electric
- Denotes
personnel
in attendance
at the exit meeting held with the
NRC
resident
inspectors
on July 27,
1994.
2
EXIT MEETING
An exit meeting
was conducted
on July 27,
1994.
During this meeting,
the
inspectors
summarized
the
scope
and findings of the report.
The licensee
)
I t
f
'I>
acknowledged
the inspection findings documented
in this report.
The licensee
did not identify as proprietary
any information provided to, or reviewed by,
the inspectors.
'I
I
~ '
(
I
,fi'l