ML17311B130
| ML17311B130 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 08/24/1995 |
| From: | Huey F NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML17311B128 | List: |
| References | |
| 50-528-95-14, 50-529-95-14, 50-530-95-14, NUDOCS 9509010070 | |
| Download: ML17311B130 (42) | |
See also: IR 05000528/1995014
Text
ENCLOSURE 2
U.S.
NUCLEAR REGULATORY COMMISSION
REGION IV
Inspection
Report:
50-528/95-14
50-529/95-14
50-530/95-14
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,
AZ
Inspection
Conducted:
July
2 through August
13,
1995
Inspectors:
K. Johnston,
Senior Resident
Inspector
0. Garcia,
Resident
Inspector
A. MacDougall,
Resident
Inspector
J.
Kramer, Resident
Inspector
Approved:
Huey,
cting
C ie
,
eactor
ProJects
B
0 te
Ins ection
Summar
Areas
Ins ected
Units
1
2
and
3
Routine,
announced
inspection of 'onsite
response
to plant events,
operational
safety,
maintenance
and surveillance
activities, onsite engineering,
plant support activities,
and followup items.
Results
Units
1
2
and
3
~0e rat i one
During the period, operations
performance
weaknesses
of varying significance
were observed.
These
issues,
identified below,
appear contrary to the
improvement noted in operations
performance
since the
end of 1994.
~
Operator
performance
weaknesses
during
an electrical
bus realignment
contributed to
a Unit 2 reactor trip (Section
2. 1).
9509010070
950828
ADOCK 05000528
Operator
performance
weaknesses
resulted
in two Unit
1 auxiliary
system trains being simultaneously
inoperable for over five
hours
(Section 2.5).
Operators failed to properly evaluate
and resolve
an observed
estimated
critical rod position discrepancy prior to continuing with a reactor
startup.
The
NRC inspector later determined that the discrepancy
was
the result of a calculational error (Section 3.4).
~
Operators failed to properly evaluate
and correct the cause of a control
room annunciator until questioned
by the
NRC inspector
(Section
3. 1).
Maintenance
Surveillance
~
Maintenance
personnel
responded
appropriately to
an inspector identified
loose motor operated
valve motor end cap bolt, performing
a thorough
inspection
and evaluation
(Section 4.2).
En ine'erin
and Technical
Su
ort
System engineers
and plant operators
responded
appropriately to
a
containment
spray waterhammer
in Unit 2, performing thorough evaluation
and testing to determine
the cause of the problem (Section 6. I).
lant
Su
ort
~
Licensee
radwaste
personnel
used
undersized
rigging, which had
been
improperly stored
and inspected,
to lift a loaded radioactive resin
container,
resulting in failure of the rigging and dropping of the
container.
The licensee
had identified previous
weaknesses
in the
control
and
use of rigging equipment
by radwaste
workers,
however,
subsequent
corrective actions
were inadequate
(Section 2.2).
Mana ement
Involvement
and Oversi ht
~
Management
Response
Team evaluation of the cause of a feedwater control
system problem, following a Unit 2 reactor trip, was flawed
and too
quickly settled
on
an incorrect failure mechanism
(Section
2. 1).
~
The decision
making process for performing
an equalizing
charge
on newly
installed Unit 2 vital batteries,
in response
to observed specific
gravity variations,
did not appear
to have received
appropriate
management
attention
and review (Section 3.3).
Summar
of Ins ection Findin s:
~
One violation was identified involving the failure to follow rigging
procedures
used in the handling of radioactive
waste
(Section 2.2).
,$
r
I
(
j
One unresolved
item was identified concerning
the removal
from service
of two trains of auxiliary feedwater
(Section 2.5).
~
One
open item was identified concerning vital battery specific gravity
variations
(Section 3.3).
~
Two violations were closed
(Sections
7. 1
and 8. 1),
~
Two Licensee
Event Reports
were closed
(Section 9).
Attachments:
1.
Persons
Contacted
and Exit Meeting
2.
List of Acronyms
(I
l
I
DETAILS
1
PLANT STATUS
1.1
Unit
1
Unit
1 started
and
ended
the inspection period at essentially
100 percent
power with no significant events
1.2
Unit 2
Unit 2 began
the inspection period at
100 percent
power.
On July 17, the unit
experienced
a reactor trip on low steam generator
(SG) level
(Section
2. 1).
On July 18, the unit commenced
a startup
and subsequently
increased
power to
100 percent.
The unit operated
throughout the remainder of the inspection
period at essentially
100 percent
power.
1.3
Unit 3
Unit 3 operated
throughout the inspection period at essentially
100 percent
power with no significant events.
2. 1
Reactor Tri
- Unit 2
On July 17, the unit tripped from 100 percent
power due to low SG level,
The
low SG level occurred after power was momentarily lost to the feedwater
control
system
(FWCS)
and the main feedwater
pumps ran back to minimum speed.
Prior to the reactor trip, the licensee
was performing scheduled
maintenance
on the normal
power supply to NAN-S05 (13.8
Kv nonclass
switchgear),
which
required operators
to energize
NAN-S05 from its alternate
source.
The control
room
(CR) operator
attempted
to transfer
NAN-S05 to its alternate
source
using
CR switches
which closed the alternate
supply breaker
and opened
the normal
supply breaker.
Although the transfer properly occurred,
the breaker
indications in the
CR did not change (e.g.,
the normal
supply breaker
indicated closed
and the alternate
breaker indicated
open),
and the operator
concluded that the breakers
had not changed position.
An auxiliary operator
(AO) was dispatched
to investigate
the problem.
Since
the
CR operator believed that the alternate
supply breaker
was
open
and could
close unexpectedly,
creating
a potential safety problem for the responding
AO,
he placed the alternate
supply breaker switch back into the
open position.
This caused
the alternate
supply breaker,
which was closed
and supplying
bus
power, to open, resulting in a loss of power to the
FWCS.
Prior to plant restart,
the reactor trip was reviewed
by
a management
response
team
(MRT).
The
NRT concluded that the loss of power to the
FWCS had resulted
i
I
i'
Il f
'
f
0
from failure of the system to fast transfer to its alternate
power source.
When the problem could not
be reproduced
during troubleshooting,
a
FWCS.
control circuit card
was determined
to be the most likely component to have
failed,
and
was replaced.
Subsequent
to the plant restart,
further licensee
review identified that the
FWCS fast transfer
had actually responded
as
designed,
but apparently
was not fast
enough to preclude the observed
Licensee
management
concluded that the
MRT had
been too quick to
conclude that the
FWCS fast transfer
had not performed
as designed
when, in
fact, the root problem appeared
to involve
a design deficiency.
The licensee initiated
an incident investigation
team to review the unit trip.
The licensee
determined that two plant hardware
issues
contributed to the
event.
They determined that the design of the
FWCS power supply should
be
modified to ensure
a bumpless transfer to
a backup source.
Additionally,
prior to the event,
the plant multiplexer had failed in
a configuration that
froze the switchyard breaker indications without the
CR operator's
knowledge.
The licensee
also identified operator
performance
weaknesses.
When the
operator
noted that the breaker indication did not match the switch position,
there
was other control
board indication available that would have indicated
that the transfer
had taken place.
Additionally, when attempting to restore
the breaker
alignment to its initial configuration,
the operator did not
operate
switches
in the appropriate
sequence
to ensure
a make-before-break
transfer.
The inspector
agreed with licensee
concerns
regarding
equipment
performance,
CR personnel
performance,
and the
MRT evaluation.
The inspector will follow
the licensee
corrective actions
as part of the Licensee
Event Report
(LER)
review.
2.2
Radioactive
Waste Container
Dro
ed
Unit 3
On July 21, while lifting a high integrity container
(HIC) loaded with spent
resin,
the rigging failed, allowing the
HIC to drop approximately
7 feet onto
the ground.
The HIC's highest contact
dose rates
were
70 Rem/hr
on the side
and
100 Rem/hr
on top.
The HIC was designed
and tested to survive
a 30-foot
drop with a full load,
and remained intact
and apparently
undamaged.
The
licensee
took appropriate
actions following the event to complete the
transfer.
Additionally, the licensee initiated
an incident investigation to
review the event.
The licensee
determined that inappropriate rigging practices
were the primary
cause of the event.
Additionally, the inspector
noted
examples of procedural
noncompliance,
ineffective oversight
by both radiation protection supervision
and nuclear
assurance,
a lack of awareness
and sensitivity to previous rigging
concerns,
and questions
concerning rigging qualifications
and training.
,
I
0
2.2.1
HIC Transfer
The HIC was initially moved from a high level storage
area to a transfer
shield
on
a trailer in the radwaste truck bay.
After the trailer was
relocated
to the radwaste yard,
the
HIC was to be moved from the transfer
shield
on the trailer into a storage
shield in the radwaste yard.
The first movement
was performed successfully.
A remote grappling device
was
used
as the primary method of rigging.
In preparation for the
second
movement,
the remote grappling device malfunctioned
and
a decision
was
made
by
radiation protection
management
to use
an alternate
rigging method.
The
alternate
rigging method involved use of a nylon sling that
had
been
attached
to the
HIC in 1993.
The nylon sling was inspected
by the rigger and
used to lift the HIC.
During
the transfer,
the nylon sling failed and the
HIC dropped
approximately
7 feet
onto the asphalt
in the upright position.
2.2.2
Rigging Inspection
The licensee
subsequently
determined that the load rating of the nylon sling
was less
than the load of the HIC.
The nylon sling had
been attached
by the
licensee
to wire ropes installed
on the
HIC at the request of the burial site.
The burial site planned to use the nylon sling only to attach
the wire ropes
to
a crane
hook.
The licensee
had not intended or designed
the sling to lift
the HIC.
The licensee
determined that the rigger had not verified the load capacity of
the nylon sling.
In fact,
a cloth tag
on the sling which provided the load
rating of the sling was illegible, apparently
due to age
and exposure.
Plant
Procedure
30DP-9HPII, "Field Use of Rigging," Step 3.5.3.2 required that the
rigging equipment
have
a capacity that exceeded
the weight of the load.
The
nylon sling was rated for 3800 lbs maximum load.
The gross weight of the
was
5615 lbs.
In addition,
the licensee's
rigging program required that rigging equipment
be
inspected yearly and that
a color code tag indicating the year of inspection
be attached
to nylon slings'he
involved nylon sling had not received
an
annual
inspection
nor was it color coded.
However, the rigging program also
allowed field inspection of rigging which had not received
an annual
inspection.
The rigger for the
HIC lift stated that
he
had performed
an
inspection to comply with this requirement prior to the lift.
However,
the
licensee
determined that the rigger had not performed this inspection
properly,
in that
he
had failed to inspect the entire sling.
The inspector
subsequently
determined that the rigger had not received
the training
necessary
to perform the inspection,
and
had not documented
the inspection
prior to using the sling.
'
'
The failure to use
a nylon sling rated for the lift and the failure to perform
an adequate
inspection
were failures to follow procedures
required
by
Technical Specifications
(Violation 530/9514-01).
2.2.3
Previous
Rigging Concerns
The inspector
reviewed
a sample of Nuclear Assurance
Evaluation
Reports
and
condition report/disposition
requests
(CRDR) that were written within the past
year concerning rigging.
The inspector
noted several
examples of rigging
concerns
that were identified, evaluated
and corrected.
As documented
in
ER 95-0556,
Nuclear Assurance
Plant Support identified that
rigging used for a filter change
out in Unit 2 was not in compliance with
Plant Procedure
"Field Use of Rigging."
The annual
inspection
documentation
did not exist nor was the rigging equipment properly color
coded.
Corrective actions
included the performance of an annual
inspection
with documentation for the rigging equipment
used for filter change
outs in
all units.
As documented
in ER-95-0050,
Nuclear Assurance
Plant Support identified that
the annual
inspection of the rigging equipment
used for fuel receipt in Unit 2
had not been properly performed.
One of the corrective actions to
CRDR 920683
included daily and documented
annual
inspection of rigging equipment.
A
decision
was
made to wait until fuel receipt activities were complete prior to
implementing the
new procedure
requirement.
The inspector
found that these
problems
were similar in nature to the problems
that resulted
in the drop of the
HIC and that it would be reasonable
to expect
that corrective actions for these
problems
should
have prevented
the rigging
failure.
However, it appeared
that the corrective actions did not adequately
communicate
the significance of the use of deficient rigging material,
particularly nylon slings which had not been properly stored or inspected.
2.2.4
Management
Oversight
A prejob briefing was performed for the
HIC transfer with representatives
from
operations,
radiation protection,
security
and Nuclear Assurance
present.
In
addition,
both the radiation protection supervisor
and
a member of Nuclear
Assurance
were present
at the work site prior to the lift, yet neither
questioned
the adequacy
of the inspection of the nylon sling.
The inspector
noted that this did not meet licensee
management
expectations.
2.2.5
qualifications
and Training
The inspector
reviewed the training records for the rigger and the crane
operator
and found that both were qualified.
The HIC transfer
was considered
a "High Hazard Lift" by the rigging procedure.
As corrective action for
previous rigging issues,
the licensee developed'raining
for "Heavy and High
Hazard Rigging" with the expectation that, after September
1995, all high
hazard liFts would be performed
by riggers
who had received
the training.
ii
Although the rigger was qualified for all lifts in 1990,
he had not received
the
new enhanced
"Heavy and High Hazard Rigging" training.
2.2.6
Corrective Actions
The inspector
reviewed the findings of the incident investigation
and found
the review to be thorough
and self critical.
The investigation indicated
significant management
concern
and involvement.
The incident investigation
team initiated the following immediate corrective actions:
~
A news flash was issued to all site personnel
describing
the event
and subsequent
interim corrective actions.
In addition,
the'essons
learned
from the event
were discussed
in safety meetings
with employees.
~
Only personnel
who had completed
the classroom portion of the
"Heavy and High Hazard Rigging" training were allowed to perform
lifts greater
than
6000 pounds or "High Hazard Lifts".
Riggers
were required to read
and fully understand;
Procedures
30DP-9MPll, Revision
1, "Field Use of Rigging";
and
30AC-OMP13, Revision 4,
"PVNGS Rigging Control."
The inspector
found these
actions to be appropriate.
However,
the inspector
observed
that
some riggers did not appear to have
'a clear understanding
of
rigging requirements.
On August
1, the inspector
observed
a radiation
protection technician
challenge
the qualifications of mechanical
maintenance
technicians
who were proceeding
to the location of a lift they had
been 'tasked
to perform.
The technicians
were unsure if they were qualified to perform the
task
and were
asked to verify their qualification.
After discussions
with
their supervisor, it was determined that they were qualified to perform the
task.
The inspector
concluded that the radiation protection technician's
questioning
was
a positive step for ensuring
proper rigging.
However, the inspecto'r
concluded that the riggers
should
have
been
knowledgeable
of their
qualifications before preceding
to the job site, especially
in light of recent
rigging issues.
In response
to this concern,
maintenance
management
took
further action to communicate
expectations
to riggers.
2.3
Offsite Volta e Dro
to Less
Than
524
Kv
On July 29, the offsite power grid dropped
below 524
Kv for approximately
10
seconds
when
a 30 MVar capacitor
bank north of Phoenix shorted to ground.
Voltage
on site,
normally controlled at approximately
530 Kv, dropped to
a low
of 523.6
Kv.
The licensee
considers
that both offsite sources
are inoperable
if switchyard voltage is below 524 Kv.
The three
Palo Verde units experienced
load swings in response
to the transient.
After the initial voltage drop, the
l
grid voltage raised
to
a high of 537.7
Kv and stabilized within 6 minutes at
532 Kv.
The system dispatcher for Arizona Public Service did not identify that system
voltage
had dropped
below the minimum of 524
Kv until
a review of alarms
was
performed several
hours after the system
had recovered stability.
The system
dispatcher notified the Unit
1
CR.
The Unit
1 shift supervisor
(SS) declared
that Technical Specification (TS) 3.0.3
was entered for the brief period
when
grid voltage
was below 524 Kv.
The licensee
planned to submit
an
LER on the
issue.
The inspector will review the
LER in a future report.
2.4
Both Trains of Low Pressure
Safet
In 'ection Briefl
Ino erable
Unit
1
On July,
27, Unit
1 operators
entered
TS 3.0.3 for seven
minutes
when both low
pressure
safety injection (LPSI) trains were declared
The
licensee
had
been in
a Train
8 outage for the emergency diesel
generator.
During the Train
B outage,
operators
elected to perform
a surveillance test
(ST)
on the Train
B high pressure
safety injection (HPSI)
pump.
During the
test,
a closed
HPSI injection valve leaked
and pressurized
the cold leg
1A
safety injection header,
which is also fed by Train
A LPSI.
The licensee
had
determined that the
LPSI injection valves
may become
pressure
bound
and fail
closed if downstream
pressure
exceeds
1635 psig.
This determination
was
reflected
in the annunciator
response
procedures
for the safety injection
pressure
alarms.
The annunciator
response
procedure
required operators
to depressurize
the header
by opening
a drain path to the reactor drain tank.
This was performed
and the train was declared
The licensee
planned to submit
an
LER for the event.
The inspector will
review the licensee's
evaluation of the cause of the event
as well
as
corrective actions during
a future inspection.
2.5
Two Trains of AFW Ino erable - Unit
1
On August 9, Unit
1 operators
inadvertently
removed
two AFW trains from
service without entering
the appropriate
TS action statement.
At 6 a.m.,
night shift operators
removed the Train
A Spray
Pond
(SP)
from service for
scheduled
maintenance.
This required that the Train A essential
chiller (EC),
cooled
by the
SP through the essential
cooling water system,
be declared
The Train A
EC provided
room cooling to several vital systems,
including the Train
A turbine driven
AFW pump.
According to procedures
for
the cascading
of TS requirements,
operators
declared
the Train A AFW pump
and logged entry of action
(a) of TS 3.7. 1.2, which allowed the
pump to be out of service for a maximum of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
At 9: 15 a.m.,
day shift operators
removed the Train
N AFW pump,
a motor driven
pump powered
by the Train
A emergency
diesel
generator,
from service to
perform
a minor modification on the motor breaker.
Operators failed to
recognize that the Train
A AFW pump was inoperable,
and logged that action (a)
of TS 3.7. 1.2 .was entered.
Operators
should
have
been
knowledgeable of the
Train A AFW pump inoperability and recognized that removing the Train
N AFW
li'
-10-
pump placed
the unit into TS 3.7. 1.2, action (b), which required operators
to
restore
one
pump or be in hot standby within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
The licen'see
completed
work on the Train
A SP
and racked the
pump motor
breaker into position
by 3:00 p.m.,
making the Train
A SP available.
However,
a functional test for the Train A SP
pump breaker
was not performed
on Train A
SP until 3:23 p.m.
Operators
did not discover that both trains
were
inoperable until the night shift had returned
and maintenance
personnel
informed them that the Train
N AFW pump could
be returned to service.
The licensee initiated
an event investigation,
which was underway at the
end
of the inspection period.
At the
end of the inspection period,
the licensee
had determined that the out of service time for two trains of AFW was
between
9: 15 a.m.
and
3 p.m.,
a period of 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />,
45 minutes.
The licensee
preliminarily concluded that since the
TS action requirement to shutdown
within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />
had not been
exceeded,
an
LER was not required.
The inspector
did not consider
the Train
A AFW pump to be operable until 3:23 p.m.,
and
considered
this to be
an unresolved
item (URI), pending review of the
licensee's
formal evaluation of the event
(URI 528/9514-02).
2.6
Hissed Surveillance for Emer enc
Core Coolin
S stem
Leaka
e
Unit 2
On July 13, during preparation for an internal audit of TS, the licensee
noted
that emergency
core cooling system
(ECCS)
TS surveillance
requirement
3/4.5.2.e.4
was not performed within the prescribed
18 month periodicity.
The
surveillance
required
an inspection of all
ECCS piping outside of containment
which is in contact with the. recirculation
sump,
and verify that total
measured
leakage is less
than
1 gpm.
The licensee
developed
a temporary
procedure to perform the system leak test in Node one,
performed the
procedure,
and verified acceptable
leakage within the
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> allowed
by
The licensee initiated
a
CRDR and
an investigation
team to evaluate
the cause
of the event.
The inspector
noted
a good response
by licensee
personnel
to
verify acceptable
leakage
upon discovery of the missed surveillance.
The
inspector will review the licensee's
corrective actions
as part of the
LER
review.
3 OPERATIONAL SAFETY VERIFICATION
(71707)
3. 1
Fuel Buildin
Hi
h Tem erature
Annunciator - Unit 3
On July 11, while performing
a
CR walkdown, the inspector
noted that the "Fuel
Building HVAC SYS TRBL" annunciator
window was illuminated.
The annunciator
identified that the normal
exhaust
plenum temperature
was high.
The inspector
questioned
the control
room supervisor
(CRS),
who stated that this particular
often
came in as
a result of high outside temperatures.
The
temperature
sensor for this annunciator
was located
under
a sheet
metal duct
on top of the fuel building roof.
The inspector
asked
the
CRS if the actual
room temperature
of the fuel
building had reached
the high alarm setpoint of 99
F.
The
CRS did not know,
but was confident that there were
no further actions required
by operators
in
accordance
with the alarm response
procedure.
Subsequent
to this discussion,
the
CRS directed
a nuclear operator to measure
actual
room temperature
of the fuel building.
The actual
room temperature
was
91'F
and
a work request
was generated
to recalibrate
the temperature
indicator.
After further licensee
followup,
a decision
was
made to cancel
the
work request
and perform
a site modification to change
the location
and type
of temperature
sensor
used for fuel building temperature.
This site
modification had
been previously performed in Units
1
and 2, but had
been
postponed for Unit 3,
as low priority.
The inspector
concluded that
had operators
been appropriately inquisitive
about the spurious
more timely corrective actions
may have
resulted,
without the
need for NRC prompting.
The Unit 3 Operations
Department
Leader agreed,
and noted that operator
response
to the annunciator
had not met management
expectations.
3.2
Containment
S ra
Leaka
e
Unit 3
For the past several
months,
Unit 3 operators
have
been trying to identify the
location of a small leak from the containment
spray header.
Approximately
every
3 weeks,
operators
have
had to refill the containment
spray header with
demineralized
water to clear the containment
spray header
low level alarm.
Several
containment entries .have established
the leak to be approximately
3 to
4 drops per minute.
On July 25, the inspector
noted that the licensee
had not documented
investigation'ctivities
in
a work order or CRDR.
The inspector
concluded
that,
although operators
and engineers
were actively pursuing the problem,
documentation
of the efforts was appropriate.
The inspector discussed
this
concern with the Unit 3 Operations
Department
Leader,
who concurred,
and
a
CRDR was subsequently
initiated.
3.3
Vital Batter
Hi
h Electrol te Levels
Unit 2
On August 2, the inspector
noted that
10 cells in the Channel
D vital battery
had
a level approximately
1/2 inch above the maximum level indication mark.
The inspector determined that the Channel
D battery
had
been placed
on
an
equalizing
charge to counter diverging specific gravities.
The inspector
discussed
the observation of increased
level with the electrical
maintenance
engineer,
who noted that the electrolyte levels
had risen
due to gas
from
electrolysis
being captured
under the battery plates.
The engineer
examined
the battery
and noted that approximately
16 cells
had exceeded
the
TS
surveillance limit of 1/4 inch above the
maximum level indication provided in
TS 4.8.2. l.a, Category
A.
i
I
4
I
~ ~
-12-
The
TS requires that if the Category
A limits are exceeded,
the batteries
must
be verified to be within the Category
B limits within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
The
Category
B limits require that electrolyte levels
do not overflow the battery.
In response
to the inspector's
observation,
the licensee
entered
the
24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />
surveillance
requirement
to verify Category
B limits.
The licensee
developed
work orders
and verified the proper levels for all cells
on site,
and
specifically verified that all Channel
0 cells were within the
TS 4.8.2. I.a
Category
B limits.
The licensee initiated
a
CRDR to evaluate
the elevated
cell levels.
The licensee
determined that,
on August I, the Unit 2
had also noted that
several
cell levels in the Channel
D battery were high.
The
had discussed
the observation
with electrical technicians,
who had informed the
SS that the
level
increase
was
due to the equalizing charge.
The inspector
noted that
more than
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />
had elapsed
between
the
SS observations
and the
verification performed in response
to the inspector raising the
same question.
The inspector
asked if this constituted
a missed
TS surveillance.
The licensee
subsequently
determined that the elevated electrolyte levels did
not affect the operability of the battery.
Further,
the licensee
determined
that the level limits were not intended to apply when
a battery
was being
equalized.
The licensee
concluded that it had not been
necessary
to perform
the category
B surveillance
requirements
and that they
had not violated the
TS.
Although the licensee's
conclusion
appeared
reasonable,
the inspector
noted
that this was the first, time. that the licensee
had performed
an equalizing
charge
on the newly installed
AT&T batteries.
The inspector considered
that
the diverging Channel
0 cell specific gravities
and the need for an equalizing
charge did not appear to have received
appropriate
management
attention
and
review.
Licensee
management
concurred,
and noted that
had the equalizing
charge
been
adequately
reviewed,
the applicability of cell level limits could
have
been
addressed
prior to the charge.
Furthermore,
the licensee
noted that
the Channel
0 battery
was
made
up of cells from several
manufacturing strings,
which accounted
for the variation in specific gravity of the battery.
They
found that all the cells with high electrolyte levels were from the
same
string,
and that these cells
had started with a higher specific gravity and
voltage level.
As
a result,
the licensee
concluded that more electrolysis
developed
in these cells.
They also noted that the cells with lower specific
gravities
were from a different string.
Based
on discussions
with the battery
manufacturer,
the licensee
concluded that
a 72-hour equalizing
charge
may be
insufficient to eliminate cell specific gravity variations,
and intends to
conduct further equalizing charges
on the battery.
The inspector
concluded that the licensee
had not appropriately
addressed
questions
involving AT&T battery cell electrolyte level until prompted
by the
NRC inspector.
Furthermore,
although the inspector
agreed with the licensee's
conclusion that the batteries
remain operable,
prompt further evaluation'of
the cause
and correction of cell specific gravity variations
appeared
to be
warranted.
This is
an open item
( Inspector
Followup Item 528/9514-03).
i'
I
-13-
3.4
Estimated Critical Position Durin
Reactor Startu
- Unit 2
On July 18, the licensee
performed
a reactor startup following a trip of the
unit on the previous day.
Operators
performed the initial "pul'I to
criticality" of the reactor
and subsequently
stopped after the reactor
engineer
and shift technical
advisor
(STA) calculated
two successive
ACPs that
were more than
500 percent millirho (PCM) below the estimated critical rod
position
(ECRP).
Operators
subsequently
inserted all the full length
regulating control element
assemblies,
as directed
by procedure.
The licensee
performed another calculation of the
ECRP,
and borated
the
system
(RCS) to the
new estimated critical boron concentration
(ECBC).
The
SS conferred with the
STA and reactor engineer
and concluded that
the reason for the initial ACPs being more than
500
PCM below the
ECRP was due
to the decay of Xenon
and boron concentration
being low in the allowable band.
The
SS then
commenced
another reactor startup.
The inspector
reviewed the two
ECBCs used to perform the reactor startups.
The inspector
noted that the data
and calculations
used
in the
ECBCs were
accurate,
and concluded that the licensee
had correctly performed the
ECBCs.
The inspector
noted that the changes
in reactivity in the
ECBCs were
due to
the decay of Xenon.
The licensee
compensated
for the 300
PCM decrease
in
by adding
300
Since the reactivity conditions in the core
for both startups
were nearly identical,
the inspector
concluded that the
licensee
had performed the second reactor startup without completely resolving
the reactivity discrepancy
observed
during the first startup.
The inspector
reviewed the
1/M plots performed
by the reactor engineer
and the
STA.
The inspector
noted that the
1/M plot performed
by the
STA contained
an
error,
in that,
the reactivity information was not plotted correctly.
This
error appeared
to have resulted
in one of the two ACPs that were more than
500
PCM below the
ECRP.
The inspector discussed
this finding with the reactor
engineer,
who agreed that the calculation
appeared
to be in error.
The
licensee
noted,
however, that the point was within 5
PCM of the value
calculated
by the reactor engineer.
Additionally, at the point the
calculations
were made,
the
had not begun to converge
on the
ECRP.
The
inspector
agreed with the licensee that the calculation error was not obvious.
The inspector also reviewed the
ACP data table
and noted that the licensee
had
not documented
an independent
review of the
1/M plot as required
by procedure.
The inspector discussed
this observation with the licensee.
The licensee
noted that the
STA had performed
an independent
1/H plot, meeting the intent
of the procedure,
but agreed that this independent
action
had not been
appropriately
documented
on the
ACP data table.
The licensee
subsequently
initiated
a
CRDR to evaluate
the startup
and
a
CRDR
to evaluate
the failure to properly document
the independent
review of the
1/M
plot.
At the exit meeting,
licensee
management
emphasized its expectation
that
a more rigorous evaluation of the startup
should
have
been
performed.
~ ~
-14-
The inspector will evaluate
the licensee
c'orrective actions
as part of routine
inspection.
4
MAINTENANCE OBSERVATIONS
(62703)
4. 1
Atmos heric
Dum
Valve Interaction with Plant Protection
S stem
Unit 3
0
On July 12, the inspector
observed
instrumentation
and controls technicians
perform post-modification testing
on atmospheric
dump valve
(ADV) 179.
Site
Modification 03-SM-SG-016
was initiated to assure
that control for the
ADV was
retained
in the
CR in the event that power to the remote
shutdown
hand
indicating controllers
was lost then regained.
As part of the postmaintenance
test,
a nuclear operator
performed
a partial
stroke of the
ADV from the remote
shutdown
room.
During this test, pretrip
and trip lights were received
on the Plant Protection
System
Channel
C.
The
CR operators verified that these
were indicating lights only and that
no
actual pretrips or trips had
been received.
ADV 184 was partially stroked
from the remote
shutdown
room,
and the
same
lights were received
in the
CR.
ADV 184
had not been modified with the
new
controller.
The handswitch
from the
CR was taken to the open permissive
then
to normal position.
The Plant Protection
System trip and pretrip lights did
not
come in, but the Control
Element Assembly
C and Core Protection Calculator
fail lights came in.
The reactor operator verified that
a fail condition did not exist.
The
additional tests
provided assurance
that the site modification was not
a
contributor to the failing lights.
A CRDR was initiated to determine
the
cause of these
indicating lights.
The postmaintenance
test for the
ADV 179 was completed satisfactorily.
The
inspector
noted
good communications
between
licensee
personnel
in the field
and in the
CR.
The inspector
noted that operators
had properly responded
to
the indication
and
had taken appropriate
action to address
the problem.
4.2
Motor End
Ca
Bolts Loose - Unit 3
On July 20, the inspector
observed that
one of four motor end bell bolts was
visibly loose
on SIA-HV306 "LPSI-SD Cooling
HX A Bypass Valve."
The inspector
informed the Maintenance
Valve Services
section leader of the problem.
Valve
Services
issued
a work order to investigate
and correct the problem.
Although
Valve Services
could not find the cause of the bolt being loose,
the inspector
noted the aggressive effort performed to investigate
the cause of the problem.
The licensee
had performed
comprehensive
inspections, of similar valves in all
units
and
had conducted
appropriate
reviews of the as-found condition.
The
inspector
agreed with the licensee that the valve was operable with one bolt
loose
and concluded that the licensee
investigation of the problem was
appropriate.
-15-
4.3
Other Maintenance Activities Observed
The inspector
observed
portions
oF the maintenance
activities noted
below.
The activities observed
were performed appropriately.
~
Charging
pump
A Unit 3
fire Protection Modification of Control Cabinet for Control Building
Battery
Rooms
Unit
1
5
SURVEILLANCE OBSERVATION
(61726)
5. 1
Main Steam Isolation Valve Stroke Test
Unit 3
On July 12,
1995,
the inspector
observed
the licensee
perform portions of a
partial stroke test of the Unit 3 main steam isolation valves
(MSIVs) in
accordance
with 43ST-3SG01,
Revision 6,
"MSIVs Surveillance 4.7. 1.5."
When
the operator
placed
the
CR handswitch for MSIV SGE-UV-170 Train
A to the
exercise position,
the blue exercise light immediately illuminated.
Normally
the blue light does
not
come in until the valve has
reached
the
10 percent
closed position.
The
AO observing
the test at the valve did not observe
any valve motion.
The
reactor operator
stopped
and informed supervision.
The system engineer
was
contacted.
After some discussion
and evaluation,
the
AO was directed to reset
the exercise limit switch.
After the limit switch was reset,
the blue
exercise light extinguished.,
The reactor operator re-performed that portion
of the test
and the valve responded
as expected.
The
same
sequence
of events
was experienced
during the test of the Train
B handswitch.
A CRDR was initiated
and work requests
were written to repair the limit
switches.
The inspector
questioned
the significance of the exercise limit
switch
on the operability of the MSIV.
The
SS stated that the exercise limit
switch had
no affect on the safety related fast close function and, therefore,
did not impact the ability of the
MSIV to close
when required.
As
a
conservative
measure
was initiated.
The inspector
reviewed the surveillance testing requirements
and determined
that the operators
responded
appropriately.
On July 31, the inspector
observed
the licensee
perform sections of
"MSIV's Inservice Test," in Unit 2.
The inspector
noted that
operators
adequately
performed the procedure
in the
CR and in the field.
5.2
Other Surveillance
Observations
The inspector
observed
portions of the
ST activity noted below.
The
activities observed
were performed appropriately.
S
~ ~
-16-
~
Procedure
32FT-9(D02 Exide Emergency Lighting System,
8 Hour
Verification Testing for 1,2,3E(DNN02 - Unit 2
6
ONSITE ENGINEERING (37551)
6.1
Water
Hammer Durin
Containment
S ra
Pum
Start - Unit 2
On July 21, operators
noted
an abnormal
noise in the containment
spray
(CS)
system during performance of a
ST in Unit 2.
The operators
noted that the
noise occurred during the initial start of the
CS pump.
Operators
indicated
that the noise quickly subsided
and the
pump continued to run smoothly.
Operators
discussed
the observation with engineering.
The licensee
issued
an
indicating that the
CS system
remained
The inspector
agreed with the licensee operability assessment.
The licensee initiated
an evaluation to determine
the cause of the problem.
The licensee
attached
accelerometers
to several
sections of the piping,
performed
system walkdowns,
vented the system in several
locations,
and re-
performed the test.
Engineering
determined that the cause of the problem was
incomplete venting of the system during the past refueling outage.
Upon
further inspection,
the licensee
noted that
one of the
CS trains in Unit
1
experienced
similar characteristics
when vented.
The licensee
intends to
evaluate
the optimum venting process
to alleviate this problem.
The inspector
concluded that engineering's
evaluation
was thorough,
and will monitor the
change
in the system venting process
as part of routine inspection.
6.2
Sam le Line Weld Crack Unit 3
On July 23,
1995,
an auxiliary operator identified
a small leak on Main Steam
Sample Isolation Valve SGN-V053 to the Unit 3
1 Main Steam Line 2.
Engineering
was contacted
and
a
CRDR was initiated.
After testing
and
evaluation
by engineering, it was determined that the crack
may have resulted
from main
steam. line vibration.
Following last year's
implementation of RCS hotleg temperature
reductions
on
Unit 3, operators
began to hear
a loud humming noise in the turbine building
and the main steam support structure.
Engineering
performed extensive
vibration data collection
and analysis to determine
the source of the noise.
Prior to the cracking of the
sample line, they had not been
able to identify
the source of the noise.
They determined that the highest
measured
vibrations
were not of sufficient energy to damage plant equipment.
They continued to
trend the noise
and did not identify significant change
over time.
After the crack developed,
the licensee
noted that the sample line protruded
into the steam line to provide
a mixed sample.'hey
subsequently
determined
that the vibration was centralized
around
a thermowell located
on Main Steam
Line 2, near the turbine stop valve,
and just upstream of the
sample line.
The licensee
speculated
that
a vortex created
by the
steam
on the thermowell
,
1
i
t
I
l
f
-17-
created
a humming noise.
The location of this thermowell
and its proximity to
the
sample line was unique to Hain Steam Line
2 in Unit 3.
The licensee
determined that the vibration was not of sufficient magnitude to
have
caused
the sample line weld to crack.
They speculated
that there
was
a
preexisting
weld defect
and planned to perform further inspection of the weld
during the Unit 3 refueling outage.
As an interim action to reduce stress
to
the
sample line valve,
a clamp was installed.
Operations
and engineering
personnel
planned to monitor the valve until it can
be replaced
during the
outage.
The inspector
concluded that engineering
personnel
had aggressively
pursued
the vibration and noise problem.
The inspector
noted that the identification
of the leaking sample line by the auxiliary operator
was
a good example of
operator
awareness.
Plans to resolve the vibrat-ion and noise problem are
scheduled
during the next refueling outage.
7
FOLLOWUP HAINTENANCE (92902)
7. 1
Violation 530 9431-08
CLOSED
Im ro er Tor uin
of Essential
Chiller
Hotor Terminal
Fasteners
This violation involved maintenance
on the Train
B
EC in Unit 3 to install
a
new motor terminal
adapter.
During maintenance,
the technicians
tightened
the
adapter
fasteners
using personal
judgement rather than the required torque
values
in the vendor technical
manual.
The inspector
was concerned
that the work order instructions did not clearly
reference
the required torque values.
The licensee
determined that the cause
of the violation was cognitive personnel
error on the part of the maintenance
technician for failing to use the implementing references
specified in the
work order for torquing the adapter
fasteners.
However,
the licensee
acknowledged that the work order was deficient in that the correct section for
the vendor technical
manual
was not referenced
in the instructions to install
the motor terminal
arrangement kit.
The licensee
briefed all the heating, ventilation,
and air conditioning
technicians
on conduct of maintenance
expectations
and developed
a model work
procedure for all preventativ'e
and corrective maintenance
on the essential
chillers.
The inspector
reviewed the model work order
and noted that the licensee
had
developed
an appendix that gave instructions for installation of the motor
terminal
adapters
and that the appropriate
torque specifications
had
been
incorporated
into these instructions.
The inspector
concluded that the
licensee
had significantly improved the instructions for working on the
essential
chillers,
'I
t
i,l
,,'
-18-
8
FOLLOWUP ENGINEERING/TECHNICAL SUPPORT
(92903)
8. 1
Violation 529 9508-01
CLOSED
Failure to Identif
Startu
Strainer
Installed in the Containment
S ra
S stem
On February
17,
1995,
the licensee
discovered
startup strainers
in the Unit 2
containment
spray
system which should
have
been
removed prior to initial plant
startup.
A special
inspection
was conducted
and
a violation was issued
in
NRC
Inspection
Report 50-528/95-08
concerning
the licensee's
failure to identify
startup strainers prior to February
17.
The licensee
completed
an
investigation of the event
on March
10 and concluded that the primary cause
was personnel
inattention to detail
and lack of follow up for issue closure.
The licensee
also concluded that personnel
failed to aggressively
review
industry notifications which highlighted the potential
problems with startup
strainers.
Inspection
Report 50-528/95-08
noted that the weaknesses
in the licensee's
corrective action program
and review of industry events contributed to the
licensee's
failure to identify the startup strainers.
The inspector
reviewed
corrective action Audit 95-008,
conducted
in the
end of April to assess
the
effectiveness
of the licensee's
changes
to the corrective action program
implemented
in August of 1994.
The audit team concluded that although the licensee's
corrective action
program
was being effectively implemented,
problems with the adequacy
of root
cause
determinations
continued to compromise
the process'pecifically,
the
licensee
determined that three out of eight significant
CRDR root cause
evaluations
reviewed
were unsatisfactory.
The licensee
determined that interim corrective actions to strengthen
root
cause
evaluations after
a previous audit were ineffective.
The licensee
initiated
CRDR 9-5-f214 to document the problems with root cause
evaluations
and the Executive Vice President,
Nuclear assigned
a Level
1 action to the
Nuclear Assurance
Director to address
the deficiencies
in the corrective
action program.
The inspector
noted that
Phase III of the Level
1 actions
was
to include program changes
to strengthen
root cause
evaluations,
and
was
scheduled
for completion
by April of 1996.
The audit team also concluded that Industry Operating
Experiences
were being
evaluated
in a timely manner
and corrective actions
appeared
to be effective
at preventing similar occurrences.
The inspector previously noted that the
licensee
had conducted
appropriate
reviews of Information Notices 94-60
on
operation with inoperable
and 94-82
on essential
chiller operation during low temperature
operations,
and agreed with the audit
team's
conclusion.
The inspector
concluded that the licensee
had conducted
a thorough
and
critical assessment
of the corrective action program.
The inspector
also
r~
,
1
i
~
-19-
noted that the corrective action program
was included
on the Nuclear Assurance
"top ten issues" list,
and that licensee
management
was appropriately
focused
on improving the effectiveness
of the corrective action program.
The
inspectors will continue to monitor the effectiveness
of the corrective action
program during future routine inspections.
8. 1.2
Other Corrective Actions
The inspector verified that the system engineering third quarter industry
events training included
a briefing on the startup strainer event.
'The
inspector also noted that the licensee
had included guidance
on
how to
identify temporary startup devices during system
walkdowns in the system
engineering
procedure.
The licensee
had also completed
system
walkdowns for
systems
important to safety and,production.
The licensee
planned to complete
walkdowns of other systems
by the
end of 1995.
The inspector verified that the licensee
had
removed all of the startup
strainers
from the piping and instrumentation
drawings.
The inspector also
noted that the licensee
had reduced
the total
number of incorporable
changes
by 50 percent
and reduced
the backlog of drawing changes
(those greater
than
45 days old) by 65 percent.
The licensee's
goal
was to incorporate all
drawing changes within 30 days.
The inspector
concluded that the licensee
had completed all the corrective
actions
committed to during the startup strainer 'special
inspection.
9
IN OFFICE REVIEW OF LERs
(90712)
The inspectors
reviewed the following licensee
event reports
and found that
they included appropriate
root cause
evaluations
and corrective actions to
prevent recurrence:
LER 529/95-03:
TS 3.0.3 Entry For Loss of Both Trains of Essential
Cooling Water
and Hydrogen
Recombiners
LER 529/95-02:
TS 3.0.3 Entry Due to Loss of Charging
Pumps
and Boration
Flowpaths
v'
l
1
t
1
Persons
Contacted
ATTACHMENT 1
1. 1
Arizona Public Service
Com an
- H. Anderson III, Senior Engineer,
Nuclear Fuels
Management
J. Bailey, Vice President,
Nuclear'Engineering
- M. Burns,
Department
Leader,
Nuclear Engineering
Design
- C. Emmett,
Media Consultant,
Strategic
Communications
- R. Fullmer,
Department
Leader,
Nuclear Assurance
- D. Garchow, Director, Engineering
- B. Grabo,
Section
Leader Compliance,
Nuclear Regulatory Affairs
- V. Huntsman,
Department
Leader,
Radiation Protection
- W. Ide, Director, Operations
- A. Krainik, Department
Leader,
Nuclear Regulatory Affairs
- D. Lamontague,
Senior Consultant,
Licensing,
Nuclear Regulatory Affairs
- J
~ Levine, Vice-President,
Nuclear Production
- D. Mauldin, Director, Maintenance
M. Shea,
Director, Radiation Protection
- J. Steward,
Department
Leader,
Radiation Protection
- W. Stewart,
Executive Vice-President,
Nuclear
- R. Stroud,
Regulatory Consultant,
Nuclear Regulatory Affairs
J. Taylor, Unit
1 Operations
Department
Leader
- R. Taylor, Acting Unit
2 Operations
Department
Leaders
1.2
NRC Personnel
- K. Johnston,
Senior Resident
Inspector
- D. Garcia,
Resident
Inspector
- J. Kramer,
Resident
Inspector
1.3
Others
- F. Gowers, Site Representative,
El
Paso Electric
- B. Drost,
E&0 Committee
Member, Salt River Project
- Denotes those present
at the exit interview meeting held
on August ll, 1995.
The inspector
also held discussions
with and observed
the actions of other
members of the licensee's
staff during the course of the inspection.
2
EXIT MEETING
An exit meeting
was conducted
on August 11,
1995.
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
t
e
i
i
ATTACHMENT 2
LIST OF
ADV
CR
CRDR
EC
ECBC
ECRP
gpm
Kv
LER
MRT
NRC
TS
anticipated critical position
atmospheric
dump valve
auxiliary operator
Arizona Public Service
containment
spray
control
room
condition report/disposition
request
control
room supervisor
essential
chiller
estimated critical boron concentration
estimated critical rod position
feedwater control
system
gallons per minute
high integrity container
high pressure
safety injection
Kilovolt
Licensee
Event Report
low pressure
safety injection
management
response
team
Nuclear Regulatory
Commission
Office of Nuclear Reactor Regulation
Public Document
Room
Palo Verde Nuclear Generating
Station
system
spray
pond
shift supervisor
surveillance test
shift technical
advisor
Technical Specification
Unresolved
Item
~
~