ML17304B148
| ML17304B148 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 04/13/1989 |
| From: | Coe D, Fiorelli G, Miller L, Polich T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17304B146 | List: |
| References | |
| 50-528-89-06, 50-528-89-6, 50-529-89-06, 50-529-89-6, 50-530-89-06, 50-530-89-6, NUDOCS 8905110024 | |
| Download: ML17304B148 (42) | |
See also: IR 05000528/1989006
Text
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION V
Re ort Nos
~
Docket Nos.
License
Nos.
50-528/89-06,
50-529/89-06
and 50-530/89-06
50-528,
50-529,
50-530
Licensee:
Arizona Nuclear
Power Project
P.
0.
Box 52034
Phoenix,
AZ. 85072-2034
, through March 19,
1989.
Date Signed
Date Signed
Date Signed
(/- J'g~P
Date Signed
Ins ection
Conduc
d:
January
Inspectors:
T.
o ich,
Se
es'nt
Inspector
D.
C e,
Resident
ns ector
G.
Fi relli, Resid nt Inspector
Approved By:
Ins ection
Summar
L.. Mi1 1 er,
h f
Reactor Projects
Branch,
Section II
Ins ection
on Januar
28
throu
h March 19
1989
Re ort Nos.
50-528/89-
06
50-529/89-06
and 50-530/89-06
Areas Ins ected:
Routine, onsite,
regular
and backshift inspection
by
the three resident inspectors.
Areas inspected
included: previously
identified items; review of plant activities; engineered
safety feature
system walkdowns; monthly surveillance testing;
monthly plant
maintenance;
engineered
safety feature
system walkdowns - Units 1,
2 and
3; monthly surveillance testing - Units 1,
2 and 3; monthly plant
maintenance
- Units 1,
2 and 3; preparation for refueling - Unit 1;
reactor trip - Unit 1 due to control element
assembly calculator
(CEAC)
malfunction; control element drive mechanism
(CEDM) air cooling units
(ACU) Unit 1; feeder breaker
1E NAN-S02A failure to trip - Unit 1;
reactor trip due to low steam generator
No.
1 level - Unit 2; blown fuse
on power supply to valve AFA-HV-54 Unit 2; inadequate
radiological
'posting - Unit 2; inoperable
feedwater isolation valve (FMIV) - Unit 3;
failure to conduct quality control
(gC) review for additional
work
instructions to quality-related
work activities - Unit 3; and review of
periodic and special
reports - Units 1,
2 and 3.
8905110024
890419
ADOCK 0 0005 '8
9"
During this inspection
the following Inspection
Procedures
were utilized:
30703,
60705,
61726; 62703,
71707,
71710,
90713,
92701,
92702,
93702.
Safet
Issues
Mana ement
S stem
SIMS
Items:
None
Results:
Of the
10 areas
inspected,
3 violations were identified.
These
violations pertain to the failure to follow procedures
in the areas
of
operation,
radiological control
and work control.
General
Conclusions
and
S ecific Findin
s
Si nificant Safet
Matters:
None
Summar
of Violations:
Summar
of Deviations:
None
0 en Items
Summar
One item closed,
and three
new
items opened.
DETAILS
Persons
Contacted:
I
The below listed
those
contacted:
technical
and supervisory personnel
were
among
Arizona Nuclear
Power
Pro ect
R.
)kJ
P.
F.
)kR
C.
L.
J.
W.
R.
D.
R.
- J
)hW
D
J
J
W
A
J
K
A
- B
~C
J.
J.
W.
G.
D.
R.
Adney,
Allen,
Ballard,
Brandjes,,
Buckingham,
Butler,
Churchman,
Clyde,
Dennis,
Fernow,
Ferro,
Fowler,
Gouge,
Haynes,
Heinicke,
Ide,
Karner,
Kirby,
LoCicero,
Marsh,
McCabe,
Minnicks,
Oberdorf,
Ogurek,
Papworth,
Russo,
Scott,"
Shriver,
Sills,
Simko,
Sowers,
Stover,
Younger,
Assistant Plant Manager,
Unit 2
Relief Plant Manager
guality Assurance
Director
Central
Maintenance
Manager
Operations
Manager,
Unit 2
Standards
and Technical
Support Director
Work Control Manager,
Unit 3
Shift Technical Advisor Supervisor
Work Control Manager,
Unit 1
Training Manager
Chemistry Manager,
Unit 2
guality Systems
and Engineering
Manager
Operations
Manager,
Unit 3
Vice President,
Nuclear Production/Site
Director
Plant Manager,
Unit 2
Plant Manager,
Unit 1
Executive Vice President,
Director, Nuclear Production Support
Independent
Safety Engineering
Manager
Plant Director
Maintenance
Manager,
Unit 1
Maintenance
Manager,
Unit 3
Radiation Protection
Manager, Unit 1
Radiation Protection
Manager, Unit 2
Site Services Director
Assistant guality Assurance
Director
Operations
Manager,
Unit 1
Compliance
Manager
Radiation Protection
Standards
Supervisor
Maintenance
Manager,
Unit 2
Engineering Evaluations
Manager
Nuclear Safety Acting Manager
Plant Standards
and Control Manager
The inspectors
also talked with other licensee
and contractor
personnel
during the course of the inspection.
"Attended the
on March 22,
Exit meeting held with NRC Resident
Inspectors
1989.
2.
Previousl
Identified Items - Units
1
2
and
3
92702
92701
Closed
Unresolved
Item
530/88-39-01':
"Work Grou
Su er-
visor Si nature Block Missin
From Work Order Attachment"-
Unit 3.
The inspector
had identified one- Work Order
(WO) attachment
which did not provide
a Work Group Supervisor
(WGS) signature
block for attachments
or amendments
which modified the scope or
intent of the original work order.
For certain quality related
work orders,
the level of review and signature
documentation
required for amendments
is the
same
as for the original work
order.
In the case identified by, the inspector,
a proper
review was conducted
by the
WGS,
who identified a problem with
WO amendment
which could have isolated plant letdown flow
unexpectedly while at power.
The inspector questioned
whether
all amendments
were receiving the required level of review.
The licensee's
investigation
showed that the computer
generated
WO amendment
signature
sheet did not include
a
WGS signature
block.
This signature
sheet
was immediately withdrawn from use
and
an Instruction
Change
Request
(ICR-549) was submitted to
modify the computer generated
amendment
signature
sheet prior
to further use.
In the interim,
a revised signature
page is to
be manually inserted,
as required, for WO amendments.
In
addition, the licensee
counseled
Unit 3 work control planners
to ensure that technical
reviews of WO's
made prior to release
of the
WO package
to the
WGS must
be conducted to ensur'e that
the equipment
and plant are in a proper configuration to
support the work activity without unexpectedly
impacting plant
operations.
The inspector
concluded that these actions
addressed
the concerns
of completeness
and quality of the
technical
review of
WO amendments.
This item is closed.
3.
Review of Plant Activities
71707
71710
93702
Unit 1
Except for minor power reductions to perform Control
Element
Assembly
(CEA) functional tests
and Control Element Assembly
Calculator
(CEAC) surveillance tests,
power level
was
maintained at 100K until the Unit tripped on March 5, 1989.
The reactor trip is discussed
in paragraph
8.
The unit
remained in Mode 3 until the
end of the report period.
b.
Unit 2
The unit operated at lOOX power from the beginning of the
inspection period until February
16,
1989,
when
due to low steam generator
level
(See Section 12).
The unit
was'estarted
on February
28, 1989,
and remained at power unti 1
March 15,
1989,
when the licensee voluntarily shutdown the unit
to perform testing of the Atmospheric
Dump Valves.
The unit
was in Mode
3 at the end of the report period.
c., Unit 3
Unit 3 began the inspection report period at approximately
100K
power.
On February
23,
1989, reactor
power was limited to
approximately
98K in accordance
with Technical Specifications
while testing Main Steam Safety Valves.
On February
24, 1989,
Unit 3 reduced
power to comply with Technical Specification 3.6.3
(See Section 15).
On March 3, 1989, Unit 3 experienced
a
reactor trip due to low steam generator
pressure
following a
large load rejection.
Because of apparent
malfunctions with
the
Steam
Bypass Control
System
and the Atmospheric
Dump
Valves,
and the occurrence
of a Safety Injection Actuation
Signal
(SIAS),
a Containment Isolation Actuation Signal
(CIAS),
and
a Main Steam Isolation Signal
(MSIS), an
NRC Augmented
Inspection
Team (AIT) was dispatched
to the Palo Verde site and
arrived
on March 4, 1989, to investigate
these
events.
The
findings of the AIT will be issued
as
a separate
report.
Plant Tours
The following plant areas
at Units 1,
2 and
3 were toured
by
the inspector during the course of the inspection:
Auxiliary Building
Conta'inment Building
Control
Complex Building
Diesel Generator Building
Radwaste
Building
Technical
Support Center
Turbine Building
Yard Area and Perimeter
The following areas
were observed
during the tours:
l.
0 eratin
Lo s and Records
Records
were reviewed against
Technical Specification
and administrative control
procedure
requirements.
2.
Monitorin
Instrumentation
Process
instruments
were
observed for correlation
between
channels
and for
conformance with Technical Specification requirements.
observed for conformance with 10 CFR 50.54.(k), Technical
Specifications,
and administrative procedures.
4.
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.
This verification included
routine control board indication reviews
and the conduct
of partial
system lineups.
5.
E ui ment Ta
in
Selected
equipment, for which tagging
requests
had been 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 would prevent the
systems
from fulfillingtheir functional requirements.
7.
Fire Protection
Fire fighting equipment
and controls were
observed for conformance with Technical Specifications
and
administrative procedures.
8.
Plant Chemistr
Chemical analysis results
were reviewed
for conformance with Technical Specifications
and admin-
istrative control procedures.
9.
~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.
10.
Plant Housekee
in
Plant conditions
and
material/equipment
storage
were observed to determine
the
general
state of cleanliness
and housekeeping.-
Housekeeping
in the radiologically controlled areas
was
evaluated with respect to,controlling the spread of
surface
and airborne contamination.
ll.
Radiation Protection Controls
Areas observed
included
control point operation,
records of licensee's
surveys
within the radiological controlled areas,
posting of
radiation
and high radiation areas,
compliance with
Radiation
Exposure
Permits,
personnel
monitoring devices
being properly worn,
and personnel
frisking practices.
An inadequate
Radiological
Posting
was identified at
Unit 2 (See Section 13).
No violations of NRC requirements
or deviations
were identified.
4.
En ineered Safet
Feature
S stem Walkdowns - Units 1
2 and
3
~71710
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
the walkdown of the systems,
items
such
as hangers,
supports,
electrical
cabinets
and cables,
were inspected
to determine that
they were operable,
and in a condition to perform their required
functions.
Accessible portions of the following systems
were walked
down during this inspection period.
Unit 1
Safety Injection Tanks
Essential
Control
Room Heating
and Ventilation System
"A"
and "B" Trains
Essential
Cooling Water System "A" and "B" Trains
Pump System
"A" Train
Unit 2
Safety Injection Tanks
Essential
Control
Room Heating
and Ventilation System
"A"
and "B" Trains
Essential
Cooling Water System
"A" and "B" Trains
Unit 3
Safety Injection Tanks
Essential
Control
Room Heating
and Ventilation System
"A"
and "B" Trains
Essential
Cooling Water System "A" and "B" Trains.
No violations of NRC requirements
or deviations
were identified.
5.
Monthl
Surveillance Testin
- Units 1
2 and
3
61726
'a \\
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.
b.
Specifically, portions of the following surveillances
were
observed
by the inspector during this inspection period:
Unit 1
Battery Charger Surveillance Test.
Atmospheric
Dump Valve Functional
Test.
Unit 2
Diesel Generator
"B" Test.
Mode 1 Surveillance
Logs.
Unit 3
Prepare
Safety Valve Set Pressure
Verification.
No violations of NRC requiremen'ts
or deviations
were identified.
6.
Monthl
Plant Maintenance
- 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,
required
gA/gC
involvement, proper
use of safety tags,
proper equipment
alignment
and
use of jumpers,
personnel
qualifications,
and
proper retesting.
The inspector verified that reportability
for these activities was correct.
The inspector witnessed portions of the following maintenance
activities:
Unit 1
Troubleshooting
CEAC/CPC System.
Repair of Air Leak on Feedwater
Control Valve FWV-137
Accumulator Pressure
Transmitter.
Troubleshooting of Electrical Breaker
Unit 2
Descri tion
Replacement
of "B" Auxiliary Feedwater
Pump Impeller.
Emergency Diesel Instrumentation
Preventative
Maintenance
"A" Train.
Welding of Safety Injection Valve SIA-HV-637 Yoke to Body.
Repair of the Auxiliary Feedwater
Pump Seal
Leak
"B" Train.
Unit 3
Descri tion
Repair of Feedwater Isolation Valve Oil Pump.
Installation of Reactor
Vessel
Level Indication for
Midloop Operations.
Pre aration
For Refuelin
- Unit 1
60705
The Unit 1 refueling outage
was planned to begin
on April 8, 1989.
The licensee
received fuel during the inspection period and the
inspector
observed
several
fuel receipt,
unloading
and storage
operations,
noting that procedures
governing the operation,
72AC-9NF01, Revision 0, "Control of Special
Nuclear Material
(SNM)
Transfer
and Inventory" and 72MT-9FH01, Revision 2,
"New Fuel
Handling" were being followed.
Observations
of good housekeeping
and attentive personnel
were
made.
Access control to the Zone
3
housekeeping
area
was being maintained
and the receipt/storage
operations
were continuously supported
by radiation protection.
The inspector attended
several
outage
meetings
during which the
status of .outage work preparation
were discussed
with
representatives
from the organizational
units participating in the
outage.
Work schedules
had been developed,
and the basic refueling
procedure
had been written.
However, specific fuel movements
and
positions will not be available until shortly before the reactor is
shutdown.
Procedures
covering shutdown margin determination,
spent
fuel pool level
and temperature
monitoring, containment integrity
control,
and decay heat
removal
were written and approved.
Preparations
for the upcoming refueling outage
appeared
adequate
to
support <he scheduled
outage
work activities.
No violations or deviations of NRC requirements
were identified.
Reactor Tri
Unit j. Due to Control
Element Assembl
Calculator
CEAC Failure
93702
On March 5, Unit 1 tripped from a power level of 100K.
The trip was
caused
by a response
of the reactor protection system to a low
departure
from nucleate boiling signal.
An action plan, consisting of five amendments,
was developed
by the
plant compute~ organization
and used to troubleshoot
the cause for
the
DNBR signal generation.
The CEAC/Core Protection Calculator
(CPC) channels
were also quarantined
by the licensee.
Investigative
efforts confirmed that the penalty factors generated
and input into
the
CPCs were not caused
by control element
assembly
(CEA)
deviations or erroneous
CEA position indications.
Furthermore
the
troubleshooting
confirmed that
CEAC No.
1 functioned normally,
however,
CEAC No.2 would not communicate with the
CEA display,
operators
module or plant monitoring system
(PMS) data link.
The
CEAC was also generating
erroneous
penalty factors.
This was the
direct cause of,the trip.
The cause for the
CEAC No.
2 malfunction
was identified as
a failed processor
board which was replaced.
During subsequent
testing of the
CEAC/CPC system,
performance
was in
accordance
with the acceptance
criteria of the surveillance tests
and the components
were declared
The licensee
plans to
conduct
a root cause failure analysis
on the failed processor
board.
At the time of the trip the power supply to the non-class
loads,
such
as the reactor coolant
pumps
(RCPs)
was from the auxiliary
transformer.
When the main generator tripped the fast transfer of
power to bus
1E NAN-S02 did not occur, resulting in the trip of
"1B" and "2B" (discussed
in NRC Inspection
Report 528/89-13,
529/89-13,
and 530/89-13).
The reactor
was brought to a stable
condition with the other two RCPs.
No engineered
safety feature
actuations
occurred.
The
NRC reviewed the licensee's
planned
and
completed corrective actions
and considered
them adequate
to correct
these
problems.
No violations of NRC requirements
or deviations
were identified.
Control Element Drive Mechanism
CEDM Air Coolin
Units
ACU-
During an inspection of equipment inside of containment
subsequent
to the reactor
shutdown
on March 5, 1989, the inspection
revealed
that the "B" CEDM fan had dropped approximately
8 feet from its
installed position to the plenum floor.'he fan,
one of four,
is paired with a second
"D" fan which was noted to still be in its
installed position as were the "A" and "C" fans.
The purpose of the
fans is to cool the
CEDMs in the upper
head area
by drawing air into
ducts
equipped with coolers
and then discharging the air into the
containment building.
A licensee
review of the background
performance of the "B" fan
revealed that
on December
25, 1988, the "B" and "D" CEDM air cooling
units tripped off line.
An investigation of the trip at the time
revealed that fuses
were blown.
Testing established
that the
electrical fai lures existed at the
CEDM fan motors.
The licensee's
inspection confirmed that the fallen "B" fan unit had
damaged
the
power cabling to the "D" fan.
The inspection revealed that the
sixteen 1/2" bolts holding the fan to the top frame of the air
plenum were broken.
Samples of these bolts were sent to a
laboratory for metallurgical
examination.
No results
had
been
received at the conclusion of the inspection.
The bolting associated
with the "A", "C" and "D" fans
was inspected.
The "D" fan bolting was found intact.
Three bolts
on the "A" fan
and two bolts
on the "C" fan were found broken,
and were replaced.
An inspection of the bolts
on the four Unit 2 fans revealed
two to
be broken
on one of the fans,
and were replaced.
All bolts
on the
four Unit 3 fans were found intact.
An engineering
evaluation of the unsecured
"B" fan was performed
by
the corporate
engineering office.
The configuration was analyzed
for overturning
and sliding during a safe shutdown/seismic
event
(SSE).
The analysis
concluded that it was acceptable
to leave the
fan unsecured
and that the fan will remain inside the housing during
a seismic event.
The calculations
indicate the maximum movement of
the fan during an
SSE would be approximately one-half inch.
Only
one of four fans
was necessary
to provide adequate
plenum cooling
to the
The inspectors
observed
the fan unit positioned
on the floor of the
air plenum.
The plenum was observed to be constructed
of heavy
plate (3/8 inch thick) welded to a frame
made of 4 inch x 4 inch x
1/2 inch angle iron spaced
approximately
21 inches apart.
The fan
unit appeared
stable.
Repair of the failed fan would have required
an extended
outage,
including cooldown of the plant,
and extensive
personnel
radiation exposure.
Based
on the engineering
evaluation,
licensing management
approved
operation of the reactor with the unsecured
fan for approximately
2 weeks, until the refueling outage at which time it would be
repaired.
The inspectors
considered this plan to be technically
acceptable.
The licensee's
short term resolution
was to replace
the broken bolts
on the Unit 1 and Unit 2 fans
and torque
them to 48 foot pounds
versus
the
35 foot pounds initially recommended
by the vendor.
The
bolts in Unit 3 will also
be replaced with higher strength bolts.
The longer range resolution will involve a structural
change to
reduce
the increased
vibrations which have
been
measured
over the
past year.
(0/I 50-528/89-06-01)
No violations or deviations of NRC requirements
were identified.
ll.
Feeder
Breaker
1E NAN-S02A Failure to Tri
- Unit 1
62703
At the time the plant non-class
loads
such
as the reactor coolant
pumps
(RCPs) were being supplied
power by the auxiliary transformer.
The main generator trip caused
the switchyard breakers
915 and 918
to open
as designed.
A fast transfer signal
was generated
and the
transfer of power to bus
1E NAN-SOl from the auxiliary transformer
to off-site power was successfully
accomplished.
The fast transfer
of power to bus
1E NAN-S02, however,
did not occur
because
the 13.8
KV feeder
bt eaker
1E NAN-S02A did not trip open.
As a result, the
loads
powered
by bus
1E NAN-S02 such
as
"1B" and "2B" tripped.
Following the reactor trip a Confirmatory Action letter
dated
March 7, 1989,
was issued to the licensee
by the
NRC.
The licensee
agreed to develop
a troubleshooting
plan for breaker. 1E NAN-S02A.
10
Prior to troubleshooting
breaker
1E NAN-S02A, the licensee
developed
a plan.
These
plans
were presented
to and reviewed
by the
NRC. It
included the following:
Inspectionof the breaker for proper lubrication, galling,
damage,
degradation,
and deformation.
Measurement
of forces required to trip the breaker.
Installation of a
new trip coil.
Performance of
PM task 32MT-9ZZ29, Revision 3, "Maintenance of
Medium Voltage Circuit Breakers"
which includes installation
measurements;
inspection of controls, insulation, trip
mechanisms;
gap measurements,
lubrication,
and functional
testing.
Performance
of a minimum trip coil voltage
(70
V DC) test
as
recommended
by the vendor.
No specific cause for the breaker malfunction was discovered
as
a
result of the inspections,
testing,
and engineering
evaluations
which were performed.
It was noted that the trip coil was severely
charred
from over heating or fire.
Several
findings which could
have contributed to the failure of the breaker to trip were noted
by
the licensee
as follows:
The trip coil and latch mechanism
were found slightly
misaligned (not considered
a significant contribution).
Several
preventive maintenance
(PM) tasks involving exercising
the breaker
1E NAN-S02 had been waived or cancelled in the past
two years.
Preventive
maintenance
tasks
and associated
procedures
on
medium voltage circuit breakers
do not'eet
the recommendations
of the technical
manual
and
GE verbal
recommendations.
a.
Minimum pickup voltage of the trip and closing coils were
not measured,
nor were main contact
open 'and closing
times.
b.
The technical
manual
recommended
routine maintenance
(lube, inspect, etc.) every two years.
Procedure
32MT-9ZZ29-specified this work every third refueling
outage.
The bearing"lubricant specified
by GE would eventually
harden after extended
usage-at
high ambient temperature.
Complete
removal
and replacement
of lubricant was verbally
recommended
every five years.
d.
Inconsistencies
existed
between
the preventive
maintenance
procedures
and the technical
manual involving how to
perform the armature travel
measurement
were noted.
e.
,
Vendor representative
guidance
was given that the general
breaker
overhaul
sh'ould
be performed every five years.
A new trip coil was installed in breaker
1E NAN-S02A.
The breaker
was inspected,
lubricated
and tested in accordance
with procedure
33MT-9ZZ29, Revision 3, "Maintenance of Medium Voltage Circuit
Breakers".
The breaker
was declared
and reinstalled.
Near
term corrective actions to be taken
by the licensee will be to cycle
13.8
KV breaker
1E NAN-S01A and
RCP breakers
on
1E NAN-SOl and
lE NAN-S02 a minimum of two times.
The alternate
supply breakers
to
lE NAN-SOl and
1E NAN-S02 will also
be cycled when the buses
are
transferred
to the auxiliary transformer.
The longer range corrective actions will include revision of'PM
procedures
to include all appropriate
PM tasks,
perform the
PMS on
all 13.8
KV breakers
during the forthcoming refueling outage
and
review the process
for waiving
PM tasks,
such that proper
justification and appropriate
level of management
concur rence will
be required.
No violations of NRC requirements
or deviations
were identified.
12.
Reactor Tri
Due to
Low Steam Generator
No.
1 Level Unit 2
93702
On February 16,
1989, Unit 2 was operating at lOOX power when
a
reactor trip occurred
due to low level in Steam Generator
(SG)
No.
1.
The event .was initiated when the economizer
control valve to No.. 1
SG failed shut.
The
SG level continued to
decrease
and resulted in an Auxiliary Feedwater Actuation Signal
1.
Following the reactor tr ip,
No.
1
excessive
flow resulted in a cooldown to the primary
system.
The
RCS pressure
decreased
to the SIAS/CIAS setpoint
and
a
Safety Injection Actuation Signal
(SIAS) and Containment Isolation
Actuation Signal
(CIAS) were received.
The
SG No.
1 continued to
fill to the
MSIS setpoint,
and the event
was terminated
by a Main
Steam Isolation Signal
(MSIS).
The licensee's
post-trip investigation
was closely monitored
by the
inspector.
This investigation
appeared
to address
the resulting
issues with sufficient detail to ensure that licensee
management
fully understood all relevant concerns.
The inspector
made the
following observations:
Although the event
was initiated by the sudden failure of the
pneumatic controls
on the
No.
1
SG economizer flow control
valve causing it to stroke shut from 85K open,
the
No.
1
Control
System
(FWCS) automatic 'response
to this
became inhibited due to a strip chart recorder which
was improperly connected
to the system.
The licensee's
investigation determined that approximately nine hours prior to
12
the reactor trip a technician
improperly connected
a strip
chart recorder to the
FWCS with reversed
input polarity.
Although no effect on the
FWCS was
seen
when th'e connection
was
made to No.
1
FWCS,
a small
occurred
due to the
reversed polarity of the recorder input when it was
subsequently
connected
to No.
2
FWCS.
Operators stabilized the
plant and decided to disconnect
the recorder
from No.
2
FWCS,
but to leave it connected to No.
1
FWCS since there
was
no
apparent
impact in doing so.
The licensee's
Post Trip Review
Report
(PTRR) described
actions
being taken or considered
to
upgrade technician
knowledge,
revise work practices,
and add
test equipment labeling to input leads.
The inspector
noted
that due to the
No.
1
SG economizer flow control valve being
placed in manual, this problem did not contribute to the
However, the operations
and maintenance staff on
shift, with concurrence
from operations
management,
allowed the
recorder to remain connected
to the
No.
1
FWCS following an
observed perturbation to the
FWCS directly related to the
recorder
and without a full understanding
of why the recorder,
had the observed effect on the
FWCS.
The licensee
has
acknowledged this concern
and reiterated their
existing policy to not proceed with activities until
an
understanding
of the reasons
for unexplained perturbations
is
achieved.
The licensee's
investigation determined that the Secondary
Plant Operator attempted to regain control of the
No.
1
economizer flow control valve in manual following its failure
and
had inserted
a 17K manual
open signal to the controller
when the reactor trip occurred.
The operator left the valve in
manual at 17K as
he began his post trip safety function checks.
This action was'contrary to the requirements
of 420P-2ZZ05,
Revision 5, "Power Operations",
Appendix
G which states
that
following a reactor trip with any
FWCS controller in manual,
the controller should
b'e returned to auto and "the operator
must verify the economizer (flow control valve) goes closed".
This omission
caused
the overfilling of the
SG to the
setpoint (529/89-06-01)
and unnecessarily
increased
the reactor
coolant system
cooldown.
The cooldown limits in the Technical
Specifications
were not exceeded.
The inspector
noted that
Unit 1 previously experienced
a SIAS/CIAS following reactor
trip due to the economizer control valve being left open
(PTRR
1-86-013).
The inspector
concluded that previous corrective
actions
were ineffective in preventing recurrence
of this
similar event in Unit 2.
The licensee's
investigation determined that following the
reactor trip, an alarm indication was received
on a Control
room annunciator
panel
which indicated less
than
10 degrees
F
upper
head subcooling margin.
The alarm occurred approximately
one minute into the event
and lasted for 28 seconds.
13
Throughout the event operators utilized Class
1E pressure
and
temperature
instruments
to manually calculate
RCS bulk
subcooling margin and ensured
an adequate
margin of 28
degrees
F was maintained.
Operators
made
no attempt to
reconcile their subcooling margin calculations with the alarm.
Although 42EP-2ZZOl "Emergency Operations"
procedure
recommends
the use of Class lE instruments
to make decisions within the
procedure, it also
recommends all channels
of a parameter
should
be used,
both Class lE and non-class
1E.
The inspector
considered that any indication of an off-normal parameter with
safety significance
such
as subcooling margin should
be
understood
by operators
during the course of an event.
The
licensee clarified 40AC-90P08 "Determination of Subcooling
Margin" to specify the available
means of subcooling margin
determination,
and the uses to which each indication may be
put.
The inspector
emphasized
to licensee
management that
subcooling margin is an extremely important indicator of
heat
removal capability and any anomalies
must be recognized
by
operators
and,
understood prior to taking actions
based
on it.
The licensee
acknowledged
the inspectors'omments.
The inspector
observed that although Quality Assurance
(QA)
representatives
offered
no criticism or input at Post Trip
Review and troubleshooting
strategy
meetings
a
QA monitoring
report
(No. SI-89-0028)
was issued
on March 16, 1989, assessing
the performance
of the post trip evaluation process.
The
inspector also noted that
an Independent
Safety Engineering
representative
was frequently present
and participated in the
analysis of the overall troubleshooting
strategy.
Throughout the licensee's
Post Trip Review the Plant Manager,
who coordinated
the entire review effort, tasked
many different
groups with various review and followup responsibilities.
These
included operations,
STA's, maintenance,
on-site
engineering, off-site engineering,
and vendor organizations.
The inspector
observed that the coordination of these
groups
appeared
to be well managed.
In addition, the depth of the
inquiry into the various concerns
and the extent of corrective
actions
taken after discussion with the resident
inspectors
and
Region
V NRC management,
appeared
adequate.
13.
Blown Fuse
on Power
Su
l
to Valve AFA-HV-54 Unit 2.
71707
On February
12,
1989, during the performance of his duties,
an
auxiliary operator discovered that light indicator for control power
to the turbine driven auxiliary feedwater
pump trip throttle valve
AFA-HV-54 was burned out.
After referring to a light bulb index
list used
by the Shift Cler k to purchase
replacement light bulbs,
he
selected
a 28 volt bulb to replace the burned out light bulb.
Upon
insertion the bulb again burned out.
A check of the circuit
revealed that
a 120 volt light bulb should
have
been
used.
In
conjunction with the burning of the light bulb was the failure of
the circuit fuse.
The electrician
who inspected
the light socket
found it badly damaged
and grounded to the panel.
Loss of the control power to AFA-HV-54 does not render
the auxiliary
pump inoperable
as this valve remains in the "open"
position during plant operation.
protection is not lost
either
as the governor controls are supplied
by a different power
supply.
What is affected
by the loss of power to AFA-HV-54 is the
ability to electrically reset the overspeed trip mechanism following
a trip.
This would require
a manual action.
The pump however,
was
declared
inoperable until the bulb socket repairs
were completed.
A review of the bulb purchase list by the inspector revealed that
the operator incorrectly read the bulb requirement.
He chose
a bulb
for the "F.P. Terry Turbine Control Panel" (fire protection panel)
which he assumed
to be the feedwater
pump panel.
The l,ist included
a line item for the feedwater
pump however, there
was
no fuse size
associated
with the line item.
Several
weeks previous to the Unit 2
event,
Unit 3 experienced
a blown fuse
on the power supply to
AFA-HV-54.
The blown fuse
was the result of a grounded socket,
which occurred while an operator
was trying to remove
a broken
indicating light.
The concern of using incorrectly sized indicating light bulbs
and
the grounding of electrical
sockets
was discussed
with licensee
management.
It was stressed
that
some
method should
be developed
which would provide accurate light bulb sizing information to
operators for the
numerous
panels
which contain indicating lights.
Licensee
management
was also informed that an engineering evaluation
should
be
made to assess
the causes
for the grounding of the
sockets.
Several
groundings
have occurred at the Palo Verde Nuclear
plant in past years.
This matter will be pursued
by the inspector
(529 89-06-02).
No violations of NRC requirements
or deviations
were identified.
14.
Inade uate Radiolo ical Postin
- Unit 2
71707
On February
15,
1989, the inspector
was touring Unit 2 Auxiliary
Building and noticed that each skid of the two Boric Acid Makeup
Pumps
(BAMPs) were enclosed with radiation warning tape,
but no
radiation warning signs were posted to identify the radiological
hazard within the taped area.
The inspector brought this to the
attention of the Unit 2 Radiation Protection
Manager
(RPM) who
immediately
had the area
surveyed.
The results of this survey
identified the areas
as contaminated
areas,
and based
on these
results proper signs were immediately posted.
However, at the time
of discovery,
the requirements
of procedure
"Radiological Posting",
were not met'or these
areas
(529/89-06-03).
The
RP Manager initiated an investigation into this incident which
identified the following facts.
Fiv'e days earlier the
rooms in
which the
BAMP's are located were decontaminated
with the exception
of the
BAMP skids
due to pump packing leaks.
The two
RP technicians
involved with the post-decontamination
survey
(one utility, one
contractor) failed to ensure that de-posting of the surveyed
area
accounted for the remaining contaminated
15
In response
to this incident, the Unit 2
RPM counseled
the two
technicians
as well as the
Lead Technician
and crew leader for the
responsible shift crew.
This counseling specifically reviewed the
requirements
of 75RP-OZZ01.
In addition,
a Night Order was issued
which required all Unit 2
RP personnel
to reread
75RP-OZZOl and the
incident report for lessons-learned.
The utility technician
received
a written reprimand
and both technicians will receive
future quarterly performance
appraisals.
Finally, for two months
following the incident, the
RP shift technician will log all
posting changes
in the
RP shift log and will visually verify the
changes within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Units 1 and
2 RPM's and Chemistry Manager
were notified of the incident and actions taken.
The inspector
concluded that the actions
taken were prompt and appeared
to be
adequate.
. Ino erable
Isolation Valve
FWIV - Unit 3
71707
On February 24, 1989, Unit 3 received
a low oil level alarm on
Feedwater Isolation Valve SGB-UV-132 oil reservoir.
The operators
followed the alarm response
and initiated the precharge
check of the
hydraulic accumulator.
At 0417 the
FWIV was declared
inoperable while the check was
performed.
They found pressure
was greater
than that required
by
operating procedure
"Main Steam,"
Section 10, "Feedwater
Isolation Valve Accumulator Precharge
Check."
However, accumulator
pressure
was within the design limits of the accummulator
as
was
the accumulator oil level.
The licensee
entered Technical Specification 3.6.3 Action l.a which required the valve to be
demonstrated
operable within four hours or be in hot standby within
the next
6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
The inspector
observed
the preparations
for shutdown.
It was noted
that the plant Director (Acting Unit 3 Plant Manager)
was present
in
the control
room and
was involved with the problem and ensured
the
system engineer
was involved with the troubleshooting of the
problem.
The licensee
was unable to declare
the
hours
and
commenced
a power reduction at 0852.
The power reduction
was halted at 0938 when the valve was declared
The licensee
determined
the cause of the higher
pressure
to be
a failed air regulator allowing the air drives oil pump to
pressurize
the accumulator to a higher pressure.
The licensee
replaced
the air regulator
and conducted
post maintenance
testing.
The inspector
observed
the change out of the air regulator
and the
subsequent
post maintenance
testing.
The work order was followed
and the inspector
noted the maintenance
manager
was present
during
replacement
and testing.
No violations of NRC requirements
or deviations
were identified.
16
16.
Failure to Conduct
ualit
Control
C
Review for Additional Work
Instructions to
ualit -Related
Work activities - Unit 3
62703
Installation of Reactor
Vessel
Temporary
Level Indicators
on
Loops
1 and
2 were completed
on March 16,
1989,
by Work Order 35034.
- These indicators consist of two (2) one inch clear tygon tubes
attached to both
RCS hot-leg connection points at the low elevation
end,
and to a pressurizer
vent valve or a poly bottle at the upper
elevation
end.
During reduced
RCS inventory operations,
such
as
draindown
and midloop operation,
these indicators provide dual
independent
means of establishing
actual reactor vessel
water level.
Work Order 335034 referred to maintenance
procedures
"RCS Loop 1, Shutdown Cooling Train "A", and 31MT-9RC28,
"RCS
Loop 2, Shutdown Cooling Train "B", for -step-by-step
instructions
on
installation.
Both procedures
required
QC holdpoint checks for
level graduation
marks properly referenced
to valid elevation
marks
on the wall structure,
and also required
a check of the tubing for
kinks on loops that would inhibit,proper indication.
On March 19,
1989, at the direction of the Unit 3 Work Control Manager,
a portion
of the "B" Train tygon tubing was repositioned
so
as to provide
accurate
level gradations
at lower elevations
than existed
previously.
The
RCS System Engineer directed the repositioning of
the tubing which included rerouting
a small portion of the tube
and
relocating the level graduation
seal
away from the wall structure.
The inspector
observed
both the original
and the modified
installations
and concluded that the modification was adequate
with
respect
to the two
QC hold point checks.
However, the licensee's
procedure
"Work Planning," required that additional work
instructions to quality related work activities
have
a
QC review for
inspection point insertion.
The modification to the "B" Train
tubing was
made without benefit of documented
work instructions
or
a
QC review for reverification of hold point criteria on affected
structures
on systems.
This is an apparent violation of the
licensee's
Work Planning Procedure
(530/89-06-01.)
As a result of
the inspector's
questions,
the licensee initiated an incident
investigation
and
a Quality Assurance
(QA) monitor report to assess
the root cause
and develop appropriate corrective actions.
In
addition,
QC performed
an immediate verification check of applicable
hold point criteria.
17.
Review of Periodic
and
S ecial
Re orts - Units 1
2 and
3
90713
Periodic
and special
reports
submitted
by the licensee
pursuant to
Technical Specifications 6.9. 1 and 6.9.2 were reviewed
by the
inspector.
This review included the following considerations:
the report
contained
the information require'd to be reported
by
NRC
requirements;
test results
and/or supporting information were
consistent with design predictions
and performance specifications;
and the validity of the reported information.
Within the scope of
the above,
the following reports
were reviewed
by the inspector.
17
Unit
1
Monthly Operating
Report for January,
1989.
'onthly
Operating
Report for, February,
1989.
Unit 2
Monthly Operating
Report for January,
1989.
Monthly Operating
Report for February,
1989.
Unit 3
Monthly Operating Report for January,1989.
Monthly Operating
Report for February,
1989.
No violations of NRC requirements
or deviations
were identified.
18.
Alle ation Fol-lowu
RV-89-A-09; RV-80-A-009 OI Case
No.
5-83-079
a.
Characterization
1)
Vhile in the construction
phase
in 1986, Unit 3 fire door
labels
were changed without formal documentation.
The
change
was performed in
a
somewhat secretive
fashion.
2)
Modifications were
made
on Unit 3 fire doors during
construction, without an Underwriter Laboratory
(UL)
representative
present
and
no traceable
documents exist.
Two examples
were giVen:
a.
At the
120 foot level of the rad waste bui'lding at
stairwell "D".
The door
number is R209.
This door
modified by cutting 4" off the length of the door on
the hinge side in order to fit the frame.
A piece of
steel
was
formed to make
a
new door edge
and welded
in place
by
a Bechtel carpenter.
b.
On the active door of the double door by the main
opening
hatch going
down to the machine
shop,
a steel
, patch of 1$ " by lk" was welded to cover
a welding
burn.
b.
Im lied Si nificance to Oesi n, Construction or 0 eration
The changing of fire door labels could result in a fire door being
labeled with a higher hourly rating than the door's actual as-built
rating.
This could potentially lead to doors
b'eing unable to
provide the protection required
by the fire hazards
analysis, after
the plant begins operation.
If the label
changing
was improper and
purposefully done to substitute
lower rated fire doors for door
requiring
a higher rating, criminal activity may be involved.
Likewise, if-fire doors
were improperly modified, the fire doors
may
not be capable of performing their intended function, potentially
invalidating aspects
of the fire hazards
analysis.
18
Assessment
of Safet
Si nificance
The
NRC Region
V Office of Investigations
Field Office determined
that the changing of fire classification
labels
on fire doors
and
frames at Palo Verde Unit 3 in 1986 did not represent
an improper
activity.
The upgrading
and downgrading of fire doors
and frames
was permissible
as all of the fire doors
and frames for the Palo
Verde site were manufactured
by Fenestra,
Inc. to three hour
protection specifications.
The changing of the fire rating was
caused
by
NRC changing its requirements after approximately
970
doors
had
been manufactured
and labeled at the factory to the
original 3/4, lk, and
3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> levels of fire protection.
The
changing of the labels
was approved
by Underwriters Laboratories
(UL) and Fenestra.
ANPP found that the architect engineer,
Bechtel
Power Corporation
did not communicate to their field supervisors
and carpenters
that
the changing of labels
was authorized.
Trade workers
and other
involved personnel
could have thought that what was being done
was
wrong and represented
clandestine activity.
Sufficient records
existed to substantiate
the fire doors
were
3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> rated,
Fenestra
doors.
The dimensional/visual
examination of fire door R209,
performed
by
the licensee,
identified that the door had been modified.
The hinge
side
had
been cut approximately k" along the entire length.
Field
Engineering
personnel
indicated that the modification had
been
performed without documentation.
The fire rating of the modified
door was indeterminate
and
was replaced
before initial startup.
The double door by the main opening
hatch
was determined
to be door
A204 between
the Auxiliary and Radwaste
Buildings.
A visual
examination of the door confirmed that
a burn hole in the door shim
had been repaired.
This repair
had also
been
accomplished
without
documentation.
Bechtel
workers
removed all Bondo from the repaired
area at NRC's request.
A subsequent
visual examination
revealed
complete continuity of the repaired
area;
no gaps
in the metal
were
found.
The door was dispositioned use-as-is.
The licensee initiated
Corrective Action Report
C(} 86-0067
as
a result of Construction's
failure to document the maintenance
performed
on the two doors.
The licensee's
corrective actions
were extensive
and thorough.
Fire
doors in all three units were examined to identify all rework and
modifications.
Fire watches
were maintained
as compensatory
measures
at each unit until the functionality of all fire doors
covered
by Technical Specifications
was verified.
This effort was
ongoing during 1986-1988.
Training was also provided to responsible
field engineers,
reemphasizing
the
need to document all fire door
maintenance activities.
19
d.,
Staff Position
The
NRC concluded that the Unit 3 fire door label
changes
were
proper
and adequate
documentation
existed that the doors were rated
for three
hours.
This allegation
was not substantiated.
The allegation regarding improperly performed
and documented
modifications to fire doors
was substantiated.
The licensee's
investigation, corrective actions
and compensatory
measures
were
extensive
and thorough across
the site.
Impact on safety
was
minimal.
e.
Action Re uired
None.
The inspector
met with licensee
management
representatives
periodically during the inspection
and held an exit meeting
on
March 22,
1989.
During the exit meeting,
the inspector
emphasized
procedure violations in the areas of operation,
radiological
controls
and work control.
The licensee
acknowledged
the violations and
had
no further
questions
on them.
The inspector also pointed out that during this report period three
reactor trips (one at each unit) and several
safety
system
actuations
occurred.
The inspector
emphasized
safety
system
actuations
and reactor trips are part of the performance
indicators
that the
NRC monitors,
and that the events that occurred during this
report period and complicating factors that accompanied
the events
did not indicate that performance at Palo Verde was improving.
The
inspector did note that the depth of the investigations after events
occur had
shown improvement.
The licensee
acknowledged
the
inspector's
statements
and
had
no further questions.
I
I