ML17306A375
| ML17306A375 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 12/18/1991 |
| From: | Koltay P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17306A373 | List: |
| References | |
| 50-528-91-40, 50-529-91-40, 50-530-91-40, NUDOCS 9201070117 | |
| Download: ML17306A375 (44) | |
See also: IR 05000528/1991040
Text
U. S.
NUCLEAR REGULATORY COMMISSION
RE
ION
V
Re ort Nos.
Docket
Nos.
License
Nos.
Licensee
50-528/91-40,
50-529/91-40,,
and 50-530/91-40
50-528,
50-529,
and 50-530
and
Arizona Public Service
Company
P. 0.
Box 53999,
Station, 9012
Phoenix,
AZ 85072-3999
Faci lit
Name
Palo Verde Nuclear Generating Station
Units 1, 2,
and
3
x
Ins ection Conducted
October
13 through
November
14,
1991
Ins ectors
D. Coe,
F. Ringwald,
J. Sloan,
M. Young,
B. Ang,
D. Acker,
Senior Resident
Inspector
Resident
Inspector
Resident
Inspector
Resident
Inspector
Project Inspector,
Region
V
Inspect'or,
Region
V
o tay,
ie
Reactor Projects
Section II
a
e
igne
Ins ection
Summar
Ins ection
on October
13 throu
h November
14
1991
Re ort Numbers
50-528/9 -40
50-529/9 -40
and 50-530
9 - 0
Areas
Ins ected'
Routine, onsite,
regular
and backshift inspection
by the
t ree ress
ent inspectors,
and two inspectors
from the Region
V staff.
Areas
inspected
included: previously identified items; review of plant activities;
engineered
safety feature
system walkdowns - Units 1, 2,
and 3; surveillance
testing - Units 1, 2,
and 3; plant maintenance
- Units 1, 2,
and 3;
simultaneous
reactor trips - Units
1 and 3; cracked battery cell - Unit 1;
Unit 3 restart;
equalizing valve found open - Unit 3;
program enhancements
for loss of decay heat
removal - Units. 1, 2,
and 3;
refueling activities - Unit 2;
and review of licensee
event reports - Units 1,
2,
and 3.
During this inspection
the following Inspection
Procedures
were utilized:
60705,. 60710,
61726,
62703,
62704,
71707,
71710,
92700,
92701,
92702,
and 93702.
Results
Of the
10 areas
inspected,
>wo
cited violations were identified.
A Un>t
2 violation pertains
to two examples of failure to follow Radiation
t
Exposure
Permit requirements
(Paragraph 3.D.(ii)).
A Unit 3 violation
pertains to failure to follow procedures
(Paragraph
9).
920i070ii7 9ii2i8
ADQCK 05000528
8
1
tI
-2-
General
Conclusions
and Specific Findin
s
Significant Safet
Matters
None
Summar
cf Violations
2 Cited Violations
Summar
of Oeviations
0 en Items
Summar
None
2 items closed,
2 items left open,
and
4
nevi items opened.
Stren ths Noted
The analysis of the turbine control circuit response
resulting in the dual
Unit I and
3 trips was thorough.
Meaknesses
Noted
I
Several
examples
are noted in which personnel
exhibited
a relaxation in
standards
of control over activities
and
adherence
to procedures.
These
were
seen
in the areas
of 'core alterations,
radiological practices,
and compliance
with
a re'actor startup
procedure.
0
'f
I
DETAILS
1.
Persons
Contacted
The below listed technical
and supervisory
personnel
were
among those
contacted:
Arizona Public Service
(APS
'*R. Adney,
- J. Albers,
J.
N. Bailey,
B. Ballard,
D. Blackson,
T. Bradish,
R. Cherba,
- J. Fisher,
- R. Flood,
J. Fooarty,
D. Fuller,
R. Fullmer,
- R. Fountain,
- D. Gouge,
- S. Gross,
- S. Guthrie,
- W. Ide,
- A. Johnson,
'. Levine,
D. Mauldin,
J. Minnicks,
- G. Overbeck,
R. Prabhakar,
, *M. Radoccia,
- R. Rouse,
C. Russo,
R. Schaller,
T. Schriver,
J. Scott,
J. Scott,
- M. Shea,
R. Stevens,
Plant Manager,
Unit 3
Manager,
Radiation Protection
Operations
Vice President,
Nuclear Safety
8 Licensing
(NSEL)
Special Assistant to Executive
V P:
Manager,
Central
Maintenance
Manager,
Compliance
Manager, Quality Systems
Manager, Civil, (acting Dir.) Nuclear Engineering
Dept.
Plant Manager,
Unit 2
Manager,
Work Control Unit 2
Manager,
Chemistry Unit
1
Manager,
Quality Audits and Monitoring
Supervisor,
Quality Assurance
and Maintenance
Manager,
Plant Support
and
(Chairman Plant Review Bd.)
Engineer,
El Paso Electric
Site Director, Quality Assurance
(QA)
Plant Manager,
Unit
1
Supervisor,
Compliance
Vice President,
Nuclear
Power Production
Manager,'ite
Maintenance
Manager,
Maintenance
Unit 3
Site Director, Technical
Support
(STS)
Manager, Quality Engineering
Manager,
Site Nuclear Engineering
Dept.
(SNED)
Supervisor,
Compliance
Manager, Quality Control
(QA/QC)
Assistant Plant Manager,
Unit
1
Assistant Plant Manager,
Unit 2
Assistant Plant Manager,
Unit 3
General
Manaoer,
Chemistry
Manager,
Radiation Protection
Director, Licensing
E Compliance
SITE REPRESENTATIVES
- J. Draper,
Site Representative,
Southern California Edison
- R. Henry,
Site Representative,
Salt River Project
The inspectors
also talked with other licensee
and contractor
personnel
during the course of the inspection.
- Personnel
in attendance
at the exit meeting held with the
NRC Resident
Inspectors
on November
14,
1991.
2.
Previousl
Identified Items - Units
1
2
and
3 (92701
and 92702)
A
A.
Unit i
None this report.
B.
Unit 2
C.
None this report.
Unit 3
Closed
Fol lowup Item
530/91-29-05:
"Undervol ta
e Condition
-- on
ass
E Bus
PBA-S
3 - Unit 3"
9
0
This item involved evaluation of the Root Cause
of. Failure
(RCF)
and safety sionificance of an incorrectly set voltage tap
on the
Engineered
Safety Features
(ESF) Service Transformer supplying 4160
volt ESF
bus
PBA-S03.
The inspector
reviewed Condition
Report/Disposition
Request
(CRDR) 3-1-0086,
which documents
the
licensee's
evaluation.
The
CRDR determined that the tap 'had most likely been improperly
positioned
in April 1991 during the Unit 3 refueling outaoe
following testing of the turns-to-turns ratio for each tap setting.
Work Order
(WO) 462655 indicates
the tap was properly set at
position three,
but
no other work activity was identified in which
the position could have
been
changed
since then,
and
such
an
activity would not likely have
gone unnoticed while the transformer
was energized.
The licensee initiated Instruction
Change
Request
( ICR) 24701 to procedure
by which the testing
was done,
to include
a step for independent
verification of the as-found
and
as-left tap positions.
In evaluating
the safety significance of the improperly set voltage
tap, the licensee
determined that there wasno nuclear safety
concern
as
a result of this occurrence
because
the undervoltage
condition was
sensed
by the protective relays
as designed.
This condition is bounded
by the safety analysis.
Based
on this
review, this item is closed.
No violations of
NRC requirements
or deviations
were identified.
3.
Review of Plant Activities
71707
and
93702
A.
Unit 1
Unit
1 entered
the reporting period at 100 percent
power.
On
October
27,
1991,
at 7:21
AN (MST), Units
1
and
3 tripped
simultaneously after experiencing turbine load osci llations (see
Paraoraph
7).
A Notice 'of Unusual
Event
was declared
because
a
safety injection
and containment isolation also occurred during the
event.
Both Units were stabilized in Mode 3.
Unit 1 was restarted
on October
31,
1991.
Power
was increased
to lOOX on November 2,
1991,
where it was maintained for the duration of the reporting
period.
Unit 2
Unit
2 entered this 'reporting period at
100 percent
power.
Power
was reduced
and the reactor
was taken off line on October
17,
1991, for
a scheduled
70 day refueling outage.
Prior to the
shutdown
on October
14,
1991,
high temperature
alarms
were
experienced
on the unit auxiliary transformer.
Operators
shifted
in-house
loads to the startup transformers
where they remained
until shutdown.
Cooldown to Mode
5 was -completed
on October
17,
1991.
Mode
6 was entered
on October
23,
1991,
and the core offload
was completed
on November
2, 1991.
The unit remained
in this
defueled
Mode for the duration of the reporting period.
Unit 3
Unit 3 entered this reporting period at
100 percent
power.
On
October 27; 1991,
at 7:21
1
and
3 tripped
simultaneously after experiencing turbine load osci llations
(see
Paragraph
7).
Unit 3 first experienced
a reactor
power cutback.
A
Notice of Unusual
Event
was declared
because
a safety injection
and
containment isolation also occurred during the event.
Both Units
were stabilized in Mode 3.
A reactor startup
was
commenced
on
October
28,
1991,
but was terminated to address
questions raised'y
the
NRC Resident
Inspectors
regarding
whether plant conditions
were
consistent
with the applicable
bounding safety analysis.
Following
the resolution of these
items, Unit 3 was restarted
on October 30,
1991
(see
Paragraph
12).
Power
was increased
to 100 percent
on
November
1, 1991,
where -it was maintained for the duration of the
reporting period.
Plant Tours
The following plant
areas
at Units 1, 2,
and
3 were toured
by the
inspector during the inspection:
o
Auxiliary Building
o
Control
Complex Building
o
Diesel Generator
Building
o
Fuel Building
o
Main Steam Support Structure
o
Radwaste
Building
o
Technical
Support Center
o
Tur bine Bui lding
o
Yard Area
and Perimeter
(
O.
x
L
The following areas
were observed
during the tours:
0 eratinq
Lo'
and Records - Records
were reviewed .against
ec naca
peel
scatsons
and administrative control procedure
requirements.
(2)
(4)
(5)
Durino
a walkdown of the Unit 2 instrument air system with the
responsible
system
and nuclear engineers,
the systems
enoineer
found that the dryer towers
were not performing
as expected.
The operating train of dryer towers
(two towers per train) are
designated
to swap the drying function every five minutes
allowing the dormant tower to discharge
the moisture
accumulated
during the previous five-minute cycle.
However,
contrary to the design,
the towers were being manually
and
locally swapped
by the operations
personnel
every six hours or
when the high moisture
alarm indicated in the Control
Room.
This condition
had existed for three days,
however the
operations staff had not referred the problem to the
appropriate site technical
support
group.
The potential
exists,
in this configuration, for excessive
moisture in the
system to exceed
the moisture
removal capability of the
instrument air system.
Because
the second train of dryers
was
unavailable
excessive
moisture in the affected train could
degrade
the instrument air system.
The instrument air system
is not safety related,
but serves
main feedwater
and other
. secondary plant valves,
as well,
as
letdown
and charging
system valves.
The systems
engineer
responded
to the finding expeditiously,
contacting the appropriate
level of supervision
in his
own
management
as well as in the operations
and work control
departments.
The second train was subsequently
restored to
service.
Licensee
review of this matter will be documented
on
Condition Report/Disposition
Request
(CRDR)
Number 2-1-190.
Monitorin
Instrumentation - Process
instruments
were observed
for corre ation
etween
c annels
and for conformance
with
Technical Specification requirements.
~She<<S<<i
.C
1
i<< <<iq
for conformance with 10 CFR Part 50.54.(k), Technical
Specifications,
and administrative procedures.
E ui ment Lineu
s - Various valves
and electrical
breakers
were verified to be in the position or condition required
by
Technical Specifications
and administrative
procedures for the
applicable plant mode.
E ui ment
Ta oin
- Selected
equipment, for which tagging
requests
a
een initiated,
was observed
to verify that tags
were in place
and the equipment
was
in=-the condition
specified.
(6)
General
Plant
E ui ment Conditions - Plant equipment
was
observed for indications of system
leakage,
improper
lubrication, or other conditions that could prevent the
systems
from fulfillingtheir functional requirements.
The inspector
noted that the oil level in the Unit 3 "A"
pump turbine
was
above the upper mark-
indicated
on the sight glass.
Oil had
been
added earlier that
day followino routine sampling.
The licensee initiated
a
Condition Report/Oisposition
Request
(CROR)
and is installing
improved indicators
on the,siaht
glasses
in all three units
and is sensitizing. its personnel
to be more attentive
when
monitorino the oil level.
(7)
(8)
(9)
(10)
(11)
Ouring this period,
the licensee
noted slight degradation
of
the Reactor
Coolant
Pump
(RCP) "lB" middle seal,
and.initiated
increased
monitoring of seal
performance;
Since
Nay 30,
1991,
RCP "1B" middle seal differential pressure
has steadily
decreased
about
19 percent
from 970 psid to 781 psid
as of
November',
1991.
The licensee
is principally tracking third
seal inlet pressure,
which over the
same period
has
increased
from 246 psi to 289 psi, 'an increase
of about
17 percent.
The
vendor
does not consider the middle seal failed until third
seal inlet pressure
reaches
1000 psi,
and the licensee
projects that third seal inlet pressure will be about
500 psi
at the beginning of the next Unit 3 refueling outage, if the
rate of change
remains constant.
Also, the licensee
has not
detected
a measurable
change
in seal
bleedoff flow.
The
inspector
concluded that the licensee's
monitoring activities
appear
adequate
and that no immediate
concern regarding
seal
integrity exists.
Fire Protection - Fire fighting equipment
and controls
were
S
if'dministrative
procedures.
Plant Chemistr
- Chemical
analysis results
were reviewed for
con ormance with Technical Specifications
and administrative
control procedures.
~Securit
- Activities observed for conformance with regulatory
requirements,
implementation of the site security plan,
and
administrative
procedures
included vehicle
and personnel
access,
and protected
and vital area integrity.
Plant
Housekee
in
- Plant conditions
and material/equipment
storage
were observed to determine
the general
state of
cleanliness
and housekeeping.
Radiation Protection Controls - Areas
observed
included
contro
point operation,
records of licensee's
surveys within
the Radiological Controlled Areas
(RCA), posting of r adiation
and high radiation areas,
compliance with Radiation
Exposure
I
t
14
Permits
(REP), personnel
monitoring devices
being properly
worn,
and personnel frisking practices.
The inspector
noted that personnel
performing the core offload
in Unit 2 were not wearing double rubber oloves to cross
the
hot particle control
area
(HPCA) adjacent to the refueling
machine.
This requirement
was part of'he Radiation
Exposure
Permit..(REP) briefing package,
and
had
been
discussed
with the
refueling crew during the pre-job briefing.
The licensee
discussed
this with the refueling crew and ensu'red that the
additional
gloves
were worn for subsequent
work.
The inspector
noted that personnel
working in another
HPCA
were not monitored for hot particles for over
90 minutes.
The
REP. required monitoring in accordance
with licensee
procedures.
approximately every 30 minutes.
The inspector
observed
the
hot particle monitoring after informino Radiation Protection
(RP).
No hot particles
were identified.
Licensee
management
acknowledged
at the exit meeting the
need for strict adherence
to'EP requirements.
These observations
are
examples
of an
apparently relaxed attitude toward
RP requirements
and are
cited
as v'iolations of
NRC requirements
(Violation
529/91-40-01).
(12) Shift Turnover -. Shift turnovers
and special
evolution
briefings were observed for effectiveness
and thoroughness.
One violation was identified.
4.
En ineered
Safet
Feature
ESF)
S stem Malkdowns - Units
1
2
and
3
717
0
Selected
engineered
safety feature
systems
(and systems
important to
safety)
were walked
down by the inspector
to confirm that the systems
were aligned
in. accordance
with plant procedures.
During this inspection period the inspectors
walked
down accessible
portions of the following systems.
A.
Unit I
Low Pressure
Safety Injection Trains
"A" and "B"
High Pressure
Safety Injection Trains "A" and "B"
Essential
Chilled Water Trains "A" and "B"
Containment
Spray Trains "A" and "B"
Containment
Spray Trains
"A" and "B"
Refueling Water Tank
Containment
Hydrogen Control Trains "A" and "B"
B.
Unit 2
Shutdown Cooling Trains
"A" and'"B"
Instrument Air
Containment
Hydrogen Control Trains
"A" and "8"
During the safety injection system
and shutdown cooling system
~ 'nss,
the inspector
noted occurrences
at all three units of
erroneous
valve handwheel
"OPEN" indications.
Manual
and
motor-operated
valves in the high-pressure
and low-pressure
safety
injection
and containment
spray systems
had local
handwheel
"OPEN"
indications in the wrong direction
(handwheels
being inverted) or
dual indication (arrows for "OPEN" pointing in both directions).
The licensee
has initiated
an effort to identify and correct
erroneous
valve handwheel
"OPEN" indications throughout all
safety-related
systems
by addino
a specific check to'the
system
engineer
system
walkdown checklist.
Unit 3
LowLLressure Safety Injection Train "A"
High Pressure
Safety Injection Train "A"
Core Spray Train "A"
. Essential
Batteries
(PK)
Essential
Chilled Water Trains
"A" and "8"
Refueling Water Tank
Containment
Hydrogen Control Trains
"A" and "8"
While inspecting the Unit 3 refueling water tank, the inspector
also inspected
the reactor
makeup water tank located nearby,
and
noted that the feed line to the auxiliary feedwater
system
was not
completely insulated.
The insulation stopped
before contacting
the
ground,
leaving approximately
seven
inches of piping exposed.
This
is inconsistent
with the insulation configuration of the
same
piping at Units
1 and 2.
The licensee
determined that the
installation configuration
does
not present
a freeze
problem.
The inspector
observed
the joint walkdown process,
initiated in
1989 by the licensee,
which involves the walkdown of an assigned
system
by the responsible
system engineer
and nuclear engineer.
The inspector
accompanied
the system
and nuclear engineers for two
systems;
(1) the containment
hydrogen control
system
and,
(2) the
instrument air system,
in their respective joint walkdowns.
In
both cases,
the walkdowns
had
been
scheduled
annually
and were
completed in 1990
and
1991 at all three Units as scheduled.
Each
System Engineer
used
a modified version of the general
checklist
provided in the guidance
procedures for the joint walkdown,
and
recorded
such data
as
system pressure,
work request/work
order tag
status,
system configuration,
and overall
system condition.
This
modified checklist
was .specific to the system being inspected.
Although the system engineers typically perform informal walkdowns
of their assigned
systems frequently, this joint walkdown process
appears
to be
an effective method to ensure that the system
engineer
is aware of the overall condition of his/her
assigned
system.
It also provides
a means for the nuclear engineer,
normally stationed
at the corporate office, to interface with
'his/her counterpart
in the systems
engineerino
department,
and with
the system itself, at least
once
a year.
e
I
l
During the joint walkdown of the Unit
1 containment
control system,
the inspector
noted
clumps of 'glue (or sealer)
on
the heat trace control panel.
The sealer
was applied
on the heat
trace setpoint
temperature
dials to prevent tampering.
These
temperature
dials
are horizontal
wheels
located
on the front of
the panel
inside
an unlocked,
glass
door.
Although th'e seal
can
be broken to adjust the dial, the application of sealer
to
an adjustable dial appears
to inhibit the operational
readiness
of that dial.
The licensee
evaluated this condition
and determined
that the dials could not
be reouired to be operated
during
recombiner operation.
If for some
reason
they did require
movement,
the inspector
determined
the, seal
could be removed.
The inspector
noted considerable
rust
on carbon steel
studs
on
several
valves in the Essential
Chilled Water system in Units
1
and 3.
System Engineering
was
aware of the general
corrosion
problem
and is evaluating the significance of the inspector's
specific observations.
The inspector
noted that the flow control valves for the essential
ventilation coolers in the
pump rooms in Units
1
and
2 do not
have placards
warning that the valves
are reverse
acting.
Placards
are affixed to the, valves in Unit 3.
The inspector
also noted that
the essential
ventilation coolers in Units
1
and
3 lack flip-cap
covers
over the 3/8-inch diameter
temporary instrumentation
access
holes.
In Unit 3, the holes
were uncovered,
while in Unit 1,
some
were covered with plastic plugs
and
some
were uncovered.
Unit 2
coolers
had the appropriate
caps.
The licensee
stated that the
inconsistencies
between unit areas will be evaluated for
appropriate corrective action.
No violations of NRC requirements
or deviations
were identified.
I
5.
Surveillance Testino - Units
1
2
and
3
61726
Selected
surveillance tests
required to be performed
by the Technical
Specifications
(TS) were reviewed
on
a sampling basis to verify that:
~1)
The surveillance tests
were correctly included
on the facility schedule;
2)
A technically adequate
procedure
existed for performance
of the
surveillance tests;
3) The surveillance tests
had
been performed at the
frequency specified in the TS;
and 4) Test results satisfied
acceptance
criteria or were properly dispositioned.
Specifically, portions of the following surveillances
were observed
by
the inspector during this inspection period:
A.
Unit
1
Procedure
41ST-1S I03
41ST-1S I 11
Description
Containment
Spray
Pump Operability Test - 4.6.2.1.8
Low Pressure
Safety Injection
Pump Operability Test
4.5.2.F.2
0
B.
Unit 3
Procedure
Description
PPS Transmitters
Time Response
Test
(2SGA-LT-1124A)
C.
Unit 3
Procedure
Description
ESFAS Train A Subgroup
Relay Monthly Functional
Test
No violations of
NRC requirements
or deviations
were identified.
6.
Plant Yiaintenance - Units
1
2
and
3
62703
During the inspection period,
the inspector
observed
and reviewed
selected
documentation
associated
with maintenance
and problem
investigation activities listed below to verify compliance with
regulatory requirements,
compliance with administrative
and maintenance
procedures,
re'quired ljuality Assurance/(}uality Control involvement,
proper
use of safety taas,
proper equipment
alignment
and
use of
jumpers,
personnel
qualifications,
and proper retesting.
The inspector verified that reportabi lity for these activities
was
correct.
Specifically, the inspector witnessed
portions of the following
maintenance
activities:
Troubleshooting for ground fault on emergency lighting circuit
QBN D74A
Monitoring Equalizing Charge
on replacement
battery cells Class
1E batteries;
U.
UI
I~D
Detensioning of Reactor
Vessel
Head
Core Offload
Installation of Reactor
Vessel
FME Cover
Removal of Snubber
2SI175H022
per Snubber
Reduction
Program
Design
Change
I.
UI U~i
Retorque
and Reassembly
of operator for valve 3SGB-UV-1136B
No violations of
NRC requirements
or deviations
were. identified.
7.
Simultaneous
Reactor Trips - Units
1
and
3
92700
and
93702
J
On October 27,
1991, Units
1 and
3 were at 100 percent
power when
a grid
disturbance
occurred.
The disturbance initially caused
the closing of
two main turbine control valves in Unit
1
and all four main turbine
control valves in Unit 3.
The resultant
drop in steam flow caused
quick
4
I
10
open signals to the
Steam Bypass'ontrol
Valves
(SBCV) in both Units
and
a reactor
power cutback in Unit 3.
The main turbine control valves
reopened within
a few seconds
and the resultant
steam
demand .with both
control
and bypass
valves
open
caused
a rapid decrease
in reactor
temperature
and pressure.
The hioh reactor
power level coupled with
a
rapidly'ecreasing
temperature
caused
a variable over power reactor trip
in both units.
Subsequently,
the'Safety Injection Actuation System
(SIAS)
and the Containment Isolation Actuation System
(CIAS) actuated
in
both Units due to low pressurizer
pressure.
In both Units
1
and 3,
average
reactor coolant temperature
(Tave)
dropped
below the normal
post-trip temperature
of 564 degrees
F.
The Unit 1 pressurizer
level
reached
10 percent with the Reactor
Coolant
System
(RCS) pressure
at
of 1781 psia.
The Unit 3 pressurizer
level reached
15 percent with the
RCS pressure
at 1835 psia.
The SIAS/CIAS setpoints for all Palo Verde
Nuclear Generating
Station Units is 1837 psia;
Each Unit classified the event
as
a Notification of Unusual
Event due to
the
SIAS generated
by the low pressurizer
pressure.
Both units were
stabilized in Mode 3.
No problems with safety equipment
were noted
during this event.
The licensee
investigated
the cause
of this event.
A brief description
of the initial investigation,
other planned
actions
and preliminary
results
are provided below.
The investigation
determined that the event
was caused
by
a lightning
'trike
on
a 230 kilovolt (KV) line remote from the site.
This faulted
line was connected
via remote substation
to two 525
KV lines which were
also connected
to the site switchyard.
The lightning apparently
caused
an ungrounded
3-phase-fault.
The grid was lightly loaded with Units
1
and
3 providi'ng
a high percentage
of the power to the grid.
The fault
lasted
approximately
two cycles.
A comparison of this event with previous grid faults
showed that this
event
caused
current osci llations with lower minimum values
than
previous grid faults.
The current osci llations also continued for a
longer time during this event.
The licensee
continues to analyze the
.
differences
between
the fault which caused this event
and previous
similar grid faults which did not affect the Units.
A review of instrument traces
taken
by the Units'igital Fault
Recorders
(DFR) during the event indicated that the turbine control
valves shut in less
than 0.3 seconds
and then reopened within a few
seconds.
Three types of signals
could cause
these
valves to close;
1)
servo motor, 2) fast acting solenoid
and 3) turbine trip.
The servo
motor would require approximately two seconds
to close these
valves.
A
turbine trip dumps the hydraulic fluid and must
be reset to reopen the
valves.
Therefore,
only the fast acting. solenoid signal
had the ability
to fast close
and automatically reopen
the turbine control valves.
r
't
Only one plant circuit was connected
to the fast acting solenoid,
the
turbine
Power
Load Unbalance
(PLUB) circuit.
The
PLUB circuit was
designed
to compare turbine throttle pressure
and generator
output
current
and close the turbine. control valves
and turbine intercept
valves with high throttle pressure
and rapidly falling generator
current.
This circuit was designed
to prevent turbine overspeed'.
The
licensee
concluded that the
PLUB circuit activated to close the turbine
control valves
as described
above.
The alignment of the
PLUB circuit
was checked
and
was found to be satisfactory.
A review of the records
of the event
showed that the current osci llations which occurred
during
this event
appeared
to match criteria for activation of the
PLUB
circuit.
The licensee
obtained
a spare
PLUB circuit and fed the data previously
recorded
by the
DFR into the spare circuit using
a digital to analog
converter.
Preliminary results
indicate that the
PLUB circuit could have
activated
under conditions which occurred
on the grid, but the circuit
may not have activated
long enough to close all the control valves in
Unit
1
and the intercept valves in both Units.
The licensee
was
continuing to investigate this circuit to ensure
that the preli'minary
results
were correct.
In order to preclude future grid faults from again causing
a rapid plant
cooldown event,:the
licensee
moved the
PLUB output signal from the fast
acting solenoid circuit to the turbine trip circuit.
This modification
will preclude
automatic reopening of'he turbine control valves
and
subsequent
r apid cooling of the primary system
caused
by both turbine
control
and bypass
valves
being open at the
same time.
The licensee
also
began
a review of the turbine
and generator
control
and trip circuits. to determine if other circuits, including
a single.
fault, could cause plant cooling beyond the safety analysis.
No
circuits or single faults have
been found which could cause
cooling
beyond the safety analysis.
Following modifications to the
PLUB circuit
in Unit 3 and the determination that 'the initiating event
was
bounded
by
the Justification for Continued Operation resulting form the inadvertent
opening of steam
bypass
valves in Unit 3 on October
20,
1990,
(NRC
Inspection
Report 530/90-45),
the licensee
authorized restart of Unit 3
and
commenced
startup
on October
28,
1991.
The inspector
questioned
licensee
management
as to whether the conditions set
by the
JCO still
existed in Unit 3 since modification work had
been
done to the Unit 3
steam
bypass
control system.
The licensee
halted the startup until it
was determined that the modification was not fully implemented
and the
JCO commitments
were still being met.
The inspector
noted that
licensing
and engineering
supervisors
were cognizant of the Unit 3
JCO
status.
In addition, the inspector postulated
that
a single failure of
a turbine control valve to the fully open position during this event
sequence
might create
a condition beyond the
JCO analysis.
Licensee
safety analysis
engineers
reviewed this concern
and determined that this
failure constituted
an infrequent event
and
as
such
was bounded
by an
existing
UFSAR analysis.
0
12
Although these
questions
were resolved
by the licensee without
identifying any safety issues,
the inspector
encouraged
licensee
management
to ensure all relevant questions
have
been resolved prior to
unit restart..
The inspector
concluded that licensee
actions
taken
and planned
were
adequate
to identify a root cause
and to preclude future plant cooldown
from PLUB circuit activation.
No violations of
NRC requirements
or deviations
were identified.
Cracked Batter
Cell
Unit
1
71707
On October
20,
1991, the licensee initiated Material Nonconformance
Report
(MNCR) 91-PK-1024
when
a crack
on Cell
47 of the
PKB 125
VDC
essential
battery
was found to have propagated
down the side
enough to
allow electrolyte to weep.
The licensee
jumpered out the defective cell
per Temporary Modification 1-91-PK-007. 'n reviewing the
10
CFR .50.59
safety evaluation for this modification, the inspector noticed that the
battery safety margin in the evaluation
was inconsistent
with the value
given in Calculation 13-EC-PK-161,
referenced
in the safety evaluation.
The safety evaluation
uses this incorrect value,
2.18
VDC instead of
2.81
VDC, to calculate
the safety margin with one cell jumpered.
Though
the result is incorrect,
the inspector
noted that the conclusion that
jumpering the cell
was acceptable
would not have
been
changed,
and that
the error was in the conservative direction.
However, the inspector
concluded that this is
an example of lack of attention to detail in the
review and approval of the safety evaluation.
The licensee
corrected
the safety evaluation
and,
at the exit meeting,
licensee
management
stated that they view this
as
a personnel
performance
issue
and not
a
weakness
with the review process.
No violations of NRC requirements
or deviations
were identified.
Unit 3 Restart
71707
On October
30,
1991, during reactor startup in accordance
with procedure
the inspector
observed that the licensee failed to stop
Control Element Assembly
(CEA) withdrawal at the Estimated Critical Rod
Position
(ECRP) -500
pcm position
(Group
3 at 92 inches),
as required
by
the procedure.
Operators
instead
completed
a full 15 inch pull,
resulting in CEAs beino two inches
above the
ECRP -500 pcm position.
After the inspector pointed this out, operators
reinserted
CEAs to the
ECRP -500
pcm position
and then performed actions required at that
point, including evaluation of the 1/M plot to confirm that reactor
response
was
as expected.
As .1/M predictions
up to this point were very close,
and the
ECRP
(Group
4 at 60 inches)
was far off, the additional
two inch withdrawal
was not significant from
a nuclear. safety perspective.
The inspector
discussed
the situation with the shift supervisor
and the operations
supervisor,
who was also in the control
room at the time.
The assistant
t
13
10.
shi : surerv'sor
apparently did not understand
that the procedure
reauired
the withdrawal to be stopped
at the
ECRP -500
pcm position.
However, the inspector
considers
that the operators
should
be ver'
familiar with the requirements
and intent of important procedures
such
as the reactor startup
procedure.
The failure to follow procedures
is
an apparent
violation of
NRC requirem'ents
(Violation 530/91-40-02).
One violation of
NRC requirements
was identified.
Auxiliar
Flow Transmitter Equalizina Valves
Found Open-
Unit 3
71707
On November 4,
1991,
an Auxiliary Operator
in Unit 3 found the
equalizing valves
open for flow transmitters
3AFB-FT-41A and
Each feedline is also monitored by,a train "A" flow
transmitter.
The licensee
entered
the action of Technical Specification 3.3.3.6 until the flow tr ansmitters
were restored to operable status.
Condition Report/Disposition
Request
(CRDR) 3-1-0192
was initiated to
document. the licensee's
investigation into the root cause
of this
condition.
The licensee
immediate performed
a 100 percent verification
of all other instrumentation
in both trains of auxiliary feedwater
and
found
no other discrepancies.
The inspector= will review the licensee's
evaluation
upon completion
(Followup Item 530/91-40-03). "
No violations of
NRC requirements
or deviations
were identified.
Refuelin
0 erations Activities - Unit 2 (71707
and
92700
During inspection of refueling operations activities, significant
discrepancies
were identified regarding
(1) failure to recognize
120
Vac
TS requirement
during core alterations,
(2) lack of senior reactor
operator supervision
(SRO) of core alterations,
(3) missed reactor
- coolant
boron sampling prior to spent fuel pool
and fuel canal
gate
opening,
and (4) lack of direct communications
between
the control
room
and personnel
at the refueling station.
These discrepancies
are
discussed
in Inspection
Report 50-528,
529, 530/91-49.
. 12.
Loss of Deca
Heat
Removal - Pro
rammed
Enhancements
Review
Generic
Le ter
L
-
emporar
nstruction
recommended
various licensee
expeditious
actions
and
programmed
enhancements
for the operation of the
NSSS,
durino shutdown cooling of
the reactor,
to reduce
the risks associated
with those operations.
responses
to
GL 88-17 were submitted in the following letters:
(1) Ltr
161-01597-DBK/BJA dated
January
6, 1989,
(2) Ltr 161-01614-DBK/BJA dated
February 6,
1989,
and (3) Ltr 161-04033-WFC/GEC
dated July 2, 1991.
NRC
,review and
comments
on the licensee
responses
were contained
in letters
from the
NRC to the licensee
dated
May 5, 1989,
and August 31,
1990.
The licensee's
expeditious
actions for the subject generic letter
were
inspected
and documented
in inspection reports
50-528,
529,
530/89-16
and 89-36.
The licensee's
modifications for the installation of the
Refueling Water Level Indication System
(RWLIS) was inspected
and
documented
in inspection report 50-528,
529, 530/90-23.
This inspection
was performed to verify the licensee's
programmed
enhancement
as
recommended
by
0
14
A.
Instrumentation
recommended
the following:
Provide reliable indication of 'parameters
that describe
the state of the
and the performance
of systems
normally used to cool'the
RCS for both
normal
and accident conditions.
At a minimum, provide the following in
the
CR:
two independent
RCS level indications
at least
two independent
temperature
measurements
representative
of
the core exit whenever
the
RV head is located
on top of the
RY.
(The
GL suogested
that temperature
indications
be provided at all
times.)
the capability of continuously monitoring
DHR system
performance
(1)
RCS Level Indications
The licensee's
response
committed to the installation of
a permanent
RWLIS.
The
RWLIS system
had
been installed
by the licensee
in all Palo
Verde units.
The
RWLIS taps off both hot legs providing two control
room
RCS level indications.
The
RWLIS has provisions for
a backup tygon
tubing local level indication for train "A".
In addition, the
RMLIS
also includes
a local
glass
in each train that provides indication
in the minimum mid-loop level range.
RWLIS includes visible
and audible
alarms for refueling water level
LO and
LO-LO to alert control
room
operators
of RCS levels that jeopardize reliable
pump
operation; i.e. possible vortexing due to reduced level.
The licensee
neither
committed nor provided alarms for inadvertent entry into
"reduced inventory" or "mid-loop" RCS levels.
An inspection of the Unit
2 RMLIS was performed.
The hot leg connections utilize flexible
metallic braded
hose.
The use of flexible metallic braided
hose while
more rigid than rubber type
hose or tygon tubing,
appeared
to be
susceptible
to 'undesired
dips
and bends that could cause
erroneous
level
indications.
The licensee
was informed of and acknowledged
the
inspectors
observations.
Additional inspector observations
regarding
RMLIS are'contained
in the discussion
regarding
procedures.
APS'upplemental
response
to
GL 88-17 dated July 2, 1991, stated that
core exit temperatures
were available with the
RV head installed.
The
letter further stated that
upon
head removal,
the core exit
thermocouples
are withdrawn
and temperature
would be monitored using the
shutdown cooling heat
exchanger inlet temperature
indication to allow
monitoring of core exit temperature.
However,
no alarms
are normally
provided for either core exit thermocouple
or shutdown cooling heat
exchanger inlet temperature
indications.
Operating procedure
Revision 1, provided the requirements for reduced
inventory and mid loop
operations.
The procedure
required monitoring of core exit
thermocouples
during reduced
inventory and mid loop operations.
The
procedure
did not specifically require monitoring of the
shutdown
cooling heat
exchanger inlet temperature
when the
RY head
and core exit
thermocouples
are
removed.
r
15
(3)
Shutdown Coolino
S stem
SDCS
-Performance
APS's
GL 88-17 response
dated
February
6,
1989 listed numerous
instrumentation for monitoring
SDCS performance
including indications
for SDCS temperature,
pressure,
flow and
pump motor current.
It'further
listed available
alarms for the essential
cooling system that cools the
SDCS.
The letter committed to installation of
a low flow alarm for the
pumps
used for the
SDCS by the third refueling outages for Units
1
and
2
and the second refueling outage for Unit 3.
At the time of the
inspection,
the low flow alarm had not been installed in any of the
units
and the licensee
was processing
a revised
response for GL 88-17 to
delay implementation of
a design
change for the alarms to the next
ref uel ing outages for each
uni
t.'.
Procedures
recommended
that licensees
develop
and
implement procedures
that cover reduced
inventory operati'on
and that provide
an
adequate
.basis for entry into
a reduced
inventory condition.
These include:
procedures
that cover normal operation of the
NSSS,
the'ontainment,
and supporting
systems
under conditions for which
cooling would normally be provided by DHR systems;
procedures
that cover emergency,
abnormal,
off-normal, or. the
equivalent operation of the
NSSS,
the containment,
and supporting
systems if an off-normal condition occurs while operating
under
conditions for which cooling would normally be provided by DHR
systems'dministrative
controls that support
and supplement
the procedures
970e04in
items (a), (b),
and all other actions identified in this
communication,
as appropriate.
Unit 2 procedures
were reviewed.
Similar procedures
existed for the
other two units.
APS procedure
Revision 7, provided the
instructions for initiation and operation of the shutdown cooling
system.
APS procedure
40AC-90P20 provided'he
administrative controls
for reduced
inventory and mid-loop operations.
The procedure
included
the assignment
and responsibilities for
a "mid-loop oper ation
coordinator" (the on-shift
STA) whose responsibilities
included review
of ongoing/planned
work activities for work that could cause
perturbations.
The procedure
also assigns
to the Work Control
Manager/Outage
Nanager
the responsibility of ensuring that outage
schedules
minimize work during mid-loop operations
which can perturb the
RCS,
and that the
number
and length of time the containment
equipment
hatch is to be open during mid-loop operations
is minimized.
Procedure
Revision 1, provided the instructions for RCS drain
operations.
The procedure
provided instructions for draining reactor
vessel
(RV) water level to either partially drained,
reduced
inventory,
or mid-loop conditions, with or without fuel in the RV.
Procedures
42AL-2RK2A, Revision 2,
and
40AL-9RK2B Revision 0,'rovide response
instructions for alarm panels
B02A and
B02B.
'Reactor
vessel
LO and
e
i
l
I
0
16
LO-LO alarms,
and essential
cooling water system
(ECWS)
alarms
were
included in panels
B02A and
B02B.
The instructions referred operators
to abnormal
operatino
procedure
42A0-2ZZ22, Revision 2, "Loss of
Shutdown Cooling," for indications of valid
ECWS trouble alarms,
essential
spray
pond system
(ESS) trouble alarms,
and
ECWS
pump
discharge
pressure
alarms.
Procedure
42AO-2ZZ22 provided instructions
for restoring 'core heat
removal
upon loss of shutdown cooling
and
isolation of the containment.
The procedure
provided five flow paths
for gravity flow and nine flow paths for forced flow.
The inspector
reviewed the
above
noted procedures
and discussed
the
procedures
with control
room operators,
system engineers
and operations
standards
personnel.
The inspector
had the following additional
comments
regarding
the procedures.
(1)
No piping
and instrumentation
diagram
(PAID) had
been
prepared for
the
RWLIS.
420P2ZZ16,
Appendix D,
and 31NT-94C41,
Appendix A,
included sketches
of the
RWLIS.
The sketches
appeared
to be the
only drawings available to the control
room operators for the
RWLIS.
The sketches
were incomplete
and contained errors.
The
420P2ZZ16
sketch contained
a wrong location for the lower isolation
valve for the
SDC Loop "B" gage glass.
Neither sketch
showed
installed level indicator drain valves
and piping.
Both sketches
appear to show the backup tygon tubing
as
always connected
when
RWLIS is connected.
In Unit 2,
RWLIS was connected
but the backup
tygon tubing was not.
Valve numbers
were not assigned
or installed
for numerous
level instrument isolation
and equalizing valves.
The inspector reiterated
the observations
documented
in inspection
report 50-528,
529, 530/90;23,
paragraph
14, that identified
some
of the
above noted discrepancies
and identified valve line up
errors experienced
by other utilities due to similar discrepancies.
Furthermore,
the inspector reiterated
the difficulties experienced
by Palo Verde Unit 3, during the Unusual
Event of Narch 3,
1989,
and the difficulties experienced
in accomplishing
valve line-ups
for manual
operation of the atmospheric
dump valves
due to lack
of valve labeling.
(2)
Procedures
and 420P-2ZZ16 required review of containment
closure status
and verification that the containment
equipment
hatch is closed,
unless specific authorization to leave the hatch
open
had
been granted
by the Plant Nanager, prior to entry into
reduced
inventory.
However, neither procedure
provided
any criteria
for allowing the containment
hatch to be left open
such
as existing
level,
decay heat,
length of time to close the .hatch, etc.
Furthermore,
neither procedure
had provisions for PRB or peer
,
review of the Plant Nanager's
authorization.
(3)
420P-2ZZ16 requires disabling of the
SDCS automatic closure
interlocks prior to entry into mid-loop conditions.
The procedure
does
not require disabling the interlocks prior to reduced
inventory operations.
e
I
I
j
i
f
17
(4.)
Numerous
less significant
comments
were provided by the inspector
regarding
and 40AC-90P20.
These
included appropriate
identification of equipment
and instrument
numbers in the
procedures,
assurance
of consistency
in the terminology for reduced
inventory
and mid-loops operations,
and clarification of mid-loop
coordinator responsibi l.ities.
The licensee
acknowledged
the inspector
comments.
C.
~Eui ment
recommended
that licensees:
0
Assure that
adequate
operating,
and/or available
equipment
of high reliability is provided for cooling the
and for avoiding
a loss of RCS cooling.
P
Main'tain sufficient existing equipment
in an operable
or available
status
so
as to.mitigate loss of
DHR or loss of RCS inventory should
they occur.
This should include at least
one high pressure
injection
pump
and
one other system.
The water addition rate capable
of being
provided by each
equipment
item should
be at least sufficient to keep
the core covered.
Provide
adequate
equipment for personnel
communications that involve
= activities related to the
RCS or systems
necessary
to maintain the
in
a stable
and controlled condition.
The licensee's
February 6,
1989,
response
identified equipment in place
and
how they are
used for reduced
inventory and mid-loop operations.
The response
also stated that
a study of personnel
communications
equipment
would consider
design
changes
where deficiencies
are found.
The communications
study was completed in April 1990
and determined that
"the adequacy of the installed equipment for maintainino the
RCS i'
a stable
and controlled condition is marginal in many areas
of the plant."
A plant change
request
was
approved
in July of 1990.
A design
change
package
had not been
issued
at the time of the inspection.
D.
~Anal ses
recommen'ded
that licensee's:
Conduct
analyses
to supplement
existing information and develop
a
basis=for
procedures,
instrumentation installation
and response,
and equipment/NSSS
interactions
and response.
The analyses
should
encompass
thermodynamic
and physical
(configuration) states
to which
the hardware, can
be subjected
and should provide sufficient depth
that the basis is developed.
Emphasis
should
be placed
upon obtaining
a complete understanding
of NSSS behavior
under
nonpower operation=.
The licensee's
response
committed to perform the various
analyses
recommended.
The analyses
were not reviewed
by the inspector.
e
1'
18
E.
Technical
S ecifications
recommended
that:
Technical specifications
(TS) that restrict or limit the safety
benefit of the actions identified in this letter should
be identified
and appropriate
changes
should
be submitted.
The licensee's
GL response
identified its intent to submit.
TS chanoes
to
(1) eliminate
SDCS automatic closure interlocks
and (2) reduce
SDCS flow
rate to reduce potential for vortexing
and air entrainment.
Those
TS
amendment
requests
were submitted
by the licensee
on September
9, 1991,
and~ November
20,
1990,
but had not yet. been
approved
by NRR.
F.
RCS Perturbations
recommended
that:
Item (5) of the expeditious
actions
should
be reexamined
and operations
refined
as necessary
to reasonably
minimize the likelihood of loss of
DHR.
The licensee
repsonse
to
GL 88-17 committed to performance of an
ISEG
review of RCS perturbations
to determine
the
adequacy of procedural
controls, identify activities that should not
be performed during
mid-loop operations,
or additional
measures
that should
be taken during the
performance of certain activities.
Vhile
ISEG had performed
several
reviews for specific conditions for
specific units related to reduced
inventory and mid-loop operations,
a
comprehensive
review of reduced
inventor'y and mid-loop operations for
all units
had not been
completed.
D.
Conclusions
The inspection
determined that the licensee
generally met commitments
contained
in its
GL 88-17 response.
Some actions
were late
and revised
.completion dates
were to be submitted.
Some
GL 88-17 recommendations.
were not addressed
in the licensee
response
and were identified in this
report.
All discrepancies
identified were discussed
with various
licensee
personnel for their action
as appropriate.
No violations or deviations
were identified.
13.
Review of Licensee
Event Reports - Units
1
2
and
3
92700
The following LERs were reviewed
by the Resident
Inspectors.
A.
Untt
1
None this report.
19
B.
Units
2 and
3
0 en)-LER 529/90-04-LO/Ll: '!Pressurizer
Code Safet
Valve
Set-points.
Out of To erance"
- Unit
2
and
LER 530/9 -0 -LO/Ll
"Safet
Va ve Set-points
Out of To erance
'
Unit 3
92700
The inspector
examined
the licensee's
basis for concluding that the
as-found settings for Pressurizer
(PSVs
and
NSSVs) would not have
caused
the
RCS pressure
safety
limit to be exceeded if the limiting accident
(Loss of Condenser
Vacu'um causing turbine .trip) were to occur.
The inspector
determined that,
had the original
UFSAR assumptions
been
used,
the
analytical results
would have
exceeded
the 2750 psia safety limit
for all three Units (Unit
1 reported
PSV set-point drift in LER 528/89-07).
The licensee
relaxed three of these
assumptions
for
.
'nits
1
and 2,
and four for Unit 3 such that the analytical result
was 0.7 psia less
than the safety limit for Unit 3, 0.8 psia less
for Unit 2,
and
18 psia less for Unit 1.
The original
UFSAR result
was approximately
8 psia less
than the safety limit using original
assumptions.
Of these
relaxed
assumptions,
some were based
on using as-found
trip response
time
and trip set-point valves,
the use of which is
normal for an analysis of as-found conditions.
However, in each 'unit, two assumptions
were relaxed
based
on
changes
in modeling the plant's response.
One involved
a less
conservative
flow friction factor
and the other,
more
significantly, involved the opening characteristic
of
a PSV.
The
first relaxation gains approximately
a
22 psia
advantage
in the
final result.
The second
gains
approximately
10 psia.
The
licensee
has stated that additional conservatisms
in the
CESEC
computer
code
used to model the plant during the simulated
are
between
40 to 50 psia.
The inspector
concluded that the,LER's safety
assessments
did not
clarify that the licensee's
analysis of as-found conditions
would
have
shown that using original
UFSAR conservations,
the pressure
safety limit would have
been
exceeded for the limiting event.
Furthermore,
there
was
no discussion
of the licensee's
need to
relax
some of the conservatisms,
or that even with these
relaxations that the analyzed
margin to the safety limit was
0.8 psia or less
in two cases.
During
a routine managment
meeting
in Region
V offices
on November 6, 1991, licensee
management
acknowledged
the
NRC's desire for greater specificity in LER safety
assessments
when margins
are small,
and conservatisms
are relaxed.
Licensee
management
committed to submit additional
supplements
to
these
LERs to provide further details.
20
C.
Unit 3
Closed)
530/91-04-LO:
"ESF Actuation
Due to Radiation Monitor
Failure"
This
LER describes
the July 13,
1991, failure of the "A" Power
Access
Purge
Area radiation monitor (RU-37), which resul.ted
in
generation
of
a Containment
Purge Isolation Actuation Signal
and
a
Control
Room Essential
Filtration Actuation Signal
on both trains,
as designed. 'he uhit was in Mode
1 at the, time,
and
no containment
purge
was in progress.
All equipment
actuated
as designed.
The
licersee
confirmed that
no actual
high radiation condition existed.
RU-37 failed due -to
a slightly dented Geiger-Mueller tube.
The
cause
of the dent
was not determined,
though maintenance
techni,cians
were not previously aware that minor denting could lead to detector
failure.
In .response
to this event,
the licensee
briefed its
Radiation Monitoring System maintenance
technicians
and enhanced its
model
work document to ensure
appropriate
inspections
of the
Geiger-Mueller tubes
are performed.
The monitor was repaired
and
returned to service.
The inspector
concluded that the licensee's
corrective actions
were
adequate
and appropriate.
This item is closed
on the basis
of this
1
review.
.14.
Exit Meetino
An exit meeting
was held
on November
14,
1991, with licensee
management
during w'hich the observations
and conclusions
in this report
were'enerally
discussed.
The licensee
did not identify, as proprietary
any
materials
provided to or reviewed
by the inspectors
during the
inspection.
0
ACCELERATED DISTRIBUTION DEMONSTRATION SYSTEM
v
D
I
REGULATORY INFORMATION DISTRXBUTION SYSTEM
(RXDS)
ACCESSION NBR'9201070257
DOC.DATE: 91/12/27
NOTARIZED:
NO
DOCKET I
FACIL:STN-50-528 Palo Verde Nuclear Station, Unit 1, Arizona Publi
05000528
STN-50-529 Palo Verde Nuclear Station, Unit 2, Arizona Publi
05000529
STN-50-530 Palo Verde Nuclear Station, Unit 3, Arizona Publi
05000530
AUTH.NAME
AUTHOR
AFFILIATION'ONWAY,W.F.
Arizona Public Service
Co.
(formerly Arizona Nuclear Power
RECIP.NAME
RECXPXENT AFFILIATION
MARTIN,J.B.
Region
5 (Post
820201)
I
SUBJECT:
Responds
to concerns
raised in Xnsp Repts 50-528/91-30,
50-529/91-30
6 50-530/91-30. Corrective actions:work order
process
changed to provide for in-line review of emergency
lighting PM work orders.
S
DISTRIBUTION CODE:
IE01D
COPXES RECEIVED:LTR
ENCL
SIZE:
/
TITLE: General
(50 Dkt)-Insp Rept/Notice of Violation
esponse
NOTES:STANDARDIZED PLANT
Standardized
plant.
Standardized
plant.
RECXPXENT
ID CODE/NAME
PD5
THOMPSON,M
NTERNAL: ACRS
AEOD/DEIIB
DEDRO
NRR MORISSEAUID
NRR/DLPQ/LPEB10
NRR/DREP/PEPB9H
NRR/PMAS/ILRB12
OE DIR
RE
-ILE
2
EXTERNAL: EGGG/BRYCE IJ. H.
NOTES:
COPIES
LTTR ENCL
1
1
1
1
2
2
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
RECIPIENT
ID CODE/NAME
TRAMMELL,C
AEOD/DSP/TPAB
NRR HARBUCK,C.
NRR/DLPQ/LHFBPT
NRR/DOEA/OEAB
NRR/DST/DIR 8E2
NUDOCS-ABSTRACT
OGC/HDS1
RGN5
FILE
01
NRC PDR
COPIES
LTTR ENCL
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
A
05000528
05000529
D
05000530
D
S
D
NOTE TO ALL"RIDS" RECIPIENTS:
D
D
PLEASE HELP US TO REDUCE iVASTE! CONTACT THE DOCUMENT CONTROL DESK,
ROOivl PI-37 (EXT. 20079) TO ELlivIINATEYOUR NAME FROM DISTRIBUTION
LISTS FOR DOCUMENTS YOU DON'T NEED!
TOTAL NUMBER OF COPIES
REQUIRED:
LTTR
26
ENCL
26