ML17305B676
| ML17305B676 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 07/23/1991 |
| From: | Wong H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17305B674 | List: |
| References | |
| 50-528-91-19, 50-529-91-19, 50-530-91-19, NUDOCS 9108130068 | |
| Download: ML17305B676 (30) | |
See also: IR 05000528/1991019
Text
Re ort Nos.:
Docket Nos.:
License Nos.:
Licensee:
Faci 1 it
Name:
U. S.
NUCLEAR REGULATORY COMMISSION
REGION
V
- 50-528/91-19,
50-529/91-19
and 50-530/91-19
50-528,
50-529
and 50-530
and NPF-74
Arizona Public Service
Com'pany
P. 0.
Box 53999, Station
9012
Phoenix,
AZ 85072-3999
I
Palo Verde Nuclear Generating Station
Units 1,
2 and
3
Inspection
Conducted:
May 12 through June
15,
1991
Ins ectors:
D. Coe,
Senior Resident
Inspector
F. Ringwald,
Resident
Inspector
J. Sloan,
Resident
Inspector
H. Wong,
Region
V Section
Chief,
P. Galon,
Region
V Inspector
( Intern)
P.6.
7- z.p-9/
. Wong,
h ef
g
Reactor Projects
Section II
Ins ection
Summar
Ins ection
on Na
12 throu 4 June 25, 199I
Re ort Numbers
50-528/9 -
9
50-529/9 -
9
an
50-530/91-
9
~AI
d:
I, I,
gg
dg
gggf
I
I
I
resident
inspectors
and
one inspector intern 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; hydrogen
analyzer fai lure due to mispositioned
valve - Unit 1; auxiliary feedwater
(AFW) pump trip throttle valve limits - Unit 1; spray chemical
addition
pump
inoperability - Unit 1; emergency
safeguards
features
actuation
system
(ESFAS)
actuation - Unit 1; maintenance
on wrong components
- Units
2
E 3; radiation
protection
(RP) technician in
a high radiation
area
(HRA) without an alarming
dosimeter - Unit 3; worker responsibility - Unit 3; refueling activities
and
startup
from refueling - Unit 3; valve prematurely released
to operations
- Unit 3; Westinghouse
ARD relay failure - Unit 3; Combustion Engineering
(CE) technical
performance - Units 1,- 2
im 3; "B" charging
pump Technical
Specification
(TS) interpretation - Units 1,
2
E 3; safety analysis error-
Units 1,
2
and 3; essential
and emergency lighting train separation-
Units 1,
2 and 3; fire watch training - Units 1,
2
and 3;
and review of
Licensee
Event Reports
- Units 1,
2
and 3.
9108130068
910723
ADQCK 05000528
0
-2-
During this inspection
the following Inspection
Procedures
were utilized:
30702
> 60710
s 61726 ) 62703
s
64704
p 71707
p 71710
p 71711
p 92700
g 92701
p
92702
and
93702
Results
Of the
22 areas
inspected,
3 violations were identified.
The
~v>o at>ons
involved three
examples
of workers not following procedures
which caused
unintended plant events,
a technician
not following the
Radiation Exposure
Permit by entering
a high radiation area without an
alarming dosimeter,
and fire watches
performing duties without being fully
- qualified.-
General
Conclusions
and
S ecific Findin
s
Si nificant Safet
Matters
None
Summar
of Violations
3
Cited Violations
1 - Unit 3,
1 - Units
2 and
3
1 - Units 1, 2,
and
3
Summar
of Deviations
Hone
0 en Items
Summar
Stren ths
Noted
8 items closed,
0 items left open,
and
5 new items opened.
While the Unit 1 spray chemical
addition system malfunction required
an
NRC
Temporary Waiver of Compliance to complete troubleshooting
and repairs. beyond
the time allowed by the Technical Specification Limiting Condition for
Operation,
plant
and engineering
personnel
were aggressive
in conducting
testing to identify the complex multiple causes.
Although the unbolting of an
online reactor coolant
pump seal injection filter during maintenance
occurred
as
a result of
a personnel
error, the prompt action by operations
to mitigate
the consequences
was noteworthy.
In addition, the Prefire Strategies
unit
walkdown and the Equipment gualification evaluation
which discovered plant
deficiencies
and resulted
in immediate
compensatory
actions
represents
proactive plant evaluations.
Weaknesses
Noted
Worker performance
issues
dominated this inspection period.
Of particular
concern
was the unbolting of an onli.ne reactor
coolant
pump seal injection
filter cover which resulted
in
a small unanticipated
reactor coolant leak by
a
mechanic,
with an
RP Technician
and
a
gC Inspector present.
This event
reflected
breakdowns
of several
barriers in the work control process.
The
RP Technician in
a High Radiation
Area without the alarming dosimeter required
by the Radiation Entry Permit represents
the second
instance identified by the
NRC in which this has occurred.
DETAILS
Persons
Contacted
The below listed technical
and supervisory
personnel
were
among
those contacted:
Arizona Public Service
(APS)
R.
- J
J.
B.
D.
- C
- T
P.
L.
W.
E.
- R
- R
R.
D.
- p
- W.
- S
F.
- J
D.
D.
- p
J.
- T
- G
T.
F..
- R
- C
R.
T.
J.
- J
G.
G.
B.
Adney,
N. Bailey,
A. Bailey,
Ballard,
Blackson,
Boswell,
Bradish,
Caudi ll,
Clyde,'onway,
Dotson,
Flood,
Fountain,
Fullmer,
Gouge,
Hughes,
Ide,
Kanter,
Larkin,
Levine,
Marks,
Mauldin,
Maynard,
Minnicks,
YIurphy,
Overbeck,
Radtke,
Riedel,
Rogalski,
Russo,
Schaller,
Schriver,
Scott,
Scott,
Shell,
Waldrep,
Webster,
Plant Manager, Unit 3
Nuclear Safety
& Licensing,
Vice President
Nuclear Engineering,
Director
Quality Assurance,
Director
Central
Maintenance,
Manager
Nuclear Safety,
Engineer
Compliance,
Manager
Site Services,
Director
Operations
Manager, Unit 3
Executive Vice President,
Nuclear
Engineering
5 Construction, Site Director-
Plant Manager, Unit 2
QA Deficiency Coordinator
Quality Audits and Monitoring, Manager
Plant Support,
YIanager
(Chairman Plant Revie
Site Radiation Protection,
General
Manager
Plant YIanager, Unit I
APS Site Representative
Security,
Manager
Nuclear
Power Production;
Vice President
Nuclear Safety,
Manager
Site Maintenance,
Manager
Site Nuclear Engineering Dept., Sr.
Mech.
En
Maintenance
Manager,
Unit 3
RYIS Supervisor,
Chemistry
Technical
Support, Site Director
Operations
Supervisor,
Unit 3
Operations
Manager, Unit I
Audit Supervisor
Quality Control, Manager
Assistant Plant Manager,
Unit
1
Assistant Plant Manager, Unit 2
Assistant Plant Manager, Unit 3
Chemistry General
Yianager
Duality Systems,
Manager
Plant Modification Department,
Manager
Component Specialty Engineering,
Manager
w Bd.)
gineer
Other Personnel
- A.
J.
- K.
- R.
Cordova,
Draper,
Hall,
Henry,
Public Service of New Yiexico Site Representative
Southern California Edison, Site Representative
El
Paso Electric, Site Representative
(EPE)
Salt River Project, Site Representative.
The inspectors
also talked with other licensee
and contractor
personnel
during the course of the inspection.
- Attended the Exit meeting held with the
NRC Resident
Inspectors'on
June
20,, 1991.
2.
~P
A.
Unit
1
Identified Items - Units
1
2 and
3
92701
and
92702
(Closed
Foll owu
Item (528/90-54-01:
"Turbine Driven
Auxi >ar
AFM
Porn~Bi Leuc
s
- Units
1 and
3
~92701
This item refers to the licensee's
evaluation of the cause
and
significance of oil levels which have
been
observed
to be above
the high level marks
on the sight glasses
for the turbine
driven
AFW pumps
(AFA-POl) in Units
1 and 3.
The inspector
reviewed Engineering
Evaluation Report
(EER)
91-AF-001, in which the licensee
determined that the oil levels
had increased
due to thermal
expansion after being taken from
storage
{at about
45 degrees
Fahrenheit)
and
added to the
turbine.
The average
bulk oil temperature
in the turbine was
estimated
to be
110 degrees
Fahrenheit,
and the calculation
provided in the
EER demonstrated
that sufficient oil expansion
would occur to result in the observed
high levels.
Instruction
Change
Request
2504S
was submitted to add
a caution statement
to the preventive maintenance
task for oil changes
to warn
personnel
that thermal
expansion
might result in high oil
levels if the oil is not allowed to adjust to normal
room
.
temperature prior to adding to the turbine.
The licensee further determined
in
EER 91-AF-001 that the
observed
levels were not high enough to cause
a turbine
operability concern,
as the level
was about'-3/4
inches
below
the invert elevation of the turbine shaft.
2.
Based
on the above review, this item is closed.
$Clo~sed
Follow~uItem j528/91-01-03:
"Potential for
Small
Break
LOCA Bue to Tube Rupture
in the Reactor
CooMant Pum~SeaT
CooTer
- Units. 1,
2 and 3~9270TI
This item resulted
from the licensee's
identification of the
possibility of a small break intersystem
LOCA which would occur
if tubes in the Reactor
Coolant
Pump High Pressure
Seal
Cooler
failed.
The licensee's
Justification for Continued Operation
(JCO)
was reviewed
by the
NRC staff.
The licensee
revised
the
JCO based
on
NRC staff comments.
In a Nay 20,
1991 letter to
the licensee,
the
NRC accepted
the technical
basis for the
JCO
and the compensatory -measures
committed to by the licensee.
The licensee
committed to initiate an orderly plant shutdown if
Reactor
Coolant System
(RCS) activity exceeds
0.2 uCi/gm dose
equivalent
I-131 for more than
48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />
and
be in at least
Mode
3 within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />,
and to modify procedures
to
require initiation of
a plant shutdown within four hours of
identification of RCS activity in the nuclear cooling water
system.
A design modification to correct the identified
deficiency is anticipated
by the licensee
to be completed in
all units
by November
1993.
Based
on completion of the
NRC review of the JCO, this item is
closed.
B.
Unit 2
(Closed)
Followu
Item (529/91-01-01
, "Incorrect Lube Oil
82eB to~ox>>ar
eedwater
um
an
onc
ci
Makeup
~Pum
- Unit 2
92701
The licensee identified several
instances
in which the
incorrect lube oil was
added to various plant equipment.
Incident Investigation Report
( IIR) 3-2-91-003
was initiated to
investigate
these. incidents.
IIR 3-2-91-003
was subsequently
superseded
by Corrective Action Report
(CAR) 91-0005,
which the
inspector
reviewed.
The licensee
appeared
to perform
a thorough evaluation of these
incidents,
including the technical significance of using the
incorrect lube oil.
Procedural
non-compliances
and inadequate
procedures
were determined
to have resulted in the Lube Mianual
not being updated
when the Preventive
Maintenance
(PM) tasks
were revised,
and in
PM tasks
being revised without
documentation of justification.
Additionally, improper or
inadequate
labeling of secondary
storage
containers
was
identified as
an additional deficiency.
The licensee
reviewed
all.PM tasks
to identify differ'ences with the Lube Manual,
and
initiated procedural
changes
to prevent further discrepancies.
All existing differences will be resolved
by Engineering.
The
Lube Manual will become
the source
document for determining the
correct lube oil.
Many corrective actions
have
been
completed,
with the remainder
scheduled for completion
by July 15,
1991.'he
inspector
concluded that the licensee's
actions
were
appropriate
and appeared
adequate.
Based
on this review, this
item is closed..
3.
Review of Plant Activities+71707
and
9~3702
'.
Unit
Unit
1 operated
at essentially
100'X power throughout the reporting
period.
B.
Unit 2
Unit 2 operated
at essentially
lOOX power throughout the
reporting period.
C.
Unit 3
The unit began this inspection period in mode 5.
Reactor startup
from refueling occurred
on Nay 31,
1991
and
was followed by low
power physics testing.
The reactor
was
shutdown
on June
1, 1991,
for control element
assembly indication troubleshooting
and repair.
The next approach
to criticality occurred
on June 2,
1991
and the
plant proceeded
with power ascension
testing.
The plant ended
the
inspection
period at
100Ã power.
D.
Plant Tours
The followin'g plant areas
at Units 1,
2 and
3 were toured
by the
inspector during the inspection:
Auxiliary 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:
1.
0 eratin
Logs
and Records - Records
were reviewed against
>>n
d
d
procedure
requirements.
2.
N~lonitorin
Instrumentation
- Process
instruments
were
h
1
d f
conformance with Technical Specifications
requirements.
3.
Shift Staffing - Control
room and shift staffing were
observed for conformance with 10 CFR Part 50.54.(k),
Technical Specifications,
and administrative
procedures.
4.
Equipment Lineu2s - 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.
5.
E~ui ment T~a~in
- Selected
equipment, for which tagging
requests
tiad been'initiated,
was observed
to verify that
tags
were in place
and the equipment
was in the condition
specified.
6.
7.
8.
9.
10.
General
Plant
E uipment Conditions - Plant equipment
was
onserved
or
>n >cat>ons of system
leakage,
improper
lubrication, or other conditions that could prevent the systems
from fulfillingtheir functional requirements.
Fire Protection - Fire fighting equipment
and controls were
onoserve~or
conformance with Technical Specifications
and
administrative
procedures.
The inspector
observed
several
examples of deficient thermolag
on safety-related
components
in the Unit
1 Main Steam Support
Structure.
These observations
were passed
to Region
It and
personnel
performing
a fire protection inspection
(See
NRC
Inspection
Report 528/91-21).
Plant Chemistry - Chemical analysis results
were reviewed for
T
1
i
1S
if'
d
d
control procedures.
Secur~it
- 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.
A tour of the
SAS was included during this report period.
Plant
House~kee
ing - Plant conditions
and material/equipment
storage
were observed
to determine
the general
state of
cleanliness
and housekeeping.
Radiation Protection Controls - Areas observed
included control
point operation,
records
of Ticensee's
surveys within the
Radiological Controlled Areas
(RCA), posting of radiation
and
compliance with Radiation
Exposure
Permits
(REP), personnel
monitoring devices
being properly
worn,
and personnel
frisking practices.
The inspector
observed
a radiation worker turn in an alarming
dosimeter
to
a Radiation Protection
(RP) Technician at Unit
One.
The
RP Technician turned off the alarming dosimeter
without reading it.
When questioned,
the
RP Technician replied
that
he
assumed
that based
on his knowledge of where the
radiation worker had been,
the alarming dosimeter
reading
was
not significant and that the Self Indicating Dosimeter
(SID)
was the dosimeter of record for the entry.
The SID indicated
that minimal exposure
had occurred.
The inspector
commented
that all available dosimetry information should
be evaluated
and inconsistencies
resolved
since comparison of redundant
readings
can identify dosimetry failures or unusual
radiation
field patterns.
The licensee
responded
by questioning all
Technicians
on that shift and identified two of eleven
Technicians
who routinely turn off alarming dosimeters
without
reading
them.
Based
on this survey,
the licensee
has affixed
a
sion at the Unit
1 Radiological
Reports
and Access
Control
System
(RRACS) computer terminal advising every
RP Technician
to read alarming dosimeters
when they are returned.
In
addition, the licensee
issued
a
memo to all Unit
1
Technicians
stating the management
expectation that all
dosimetry data will be read
and evaluated.
A copy of 'this
memo
was sent to the
RP Managers
at Units
2 5 3.
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.
't
During this inspection period the inspectors
walked
down accessible
portions of the following systems.
Unit 1:
Safety Injection Train "8"
Emergency Diesel
Generator
"A" and "8"
Unit 2:
Emergency
Diesel
Generator
"A" and "8"
Unit 3:
Emergency
Diesel
Generator
"A" and "8"
No violations of NRC requirements
or deviations
were identified.
5.
S ill~i-U i
i, 2,
d 3
61i26
d 6i725)
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:
~ e
Unit
1
Procedure
De~seri tinn
PBB-S03 Undervoltage
Relay Test
Section
XI Valve Testing - Feedwater
Isolation
Valves
Unit 2
~D
Section
XI Valve Testing - Feedwater
Isolation
Valves
PPS Functional Test - RPS/ESFAS
Logic
Unit 3
Procecfur e
Descri tion
Incore Detector
Channel
Check
COLSS Ysargin Alarms
Adjustable
Power Signal Calibrations
No violations of
NRC requirements
or deviations
were identified.
6.
Plant Maintenance
- Units l~and
3
62703)
A.
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 Quality Assurance/Quality
Control
involvement, proper
use of safety tags,
proper equipment alignment
and use of jumpers,
personnel
qualifications,
and proper retesting.
The inspector verified that reportabi lity for these activities
was
correct.
B.
Specifically, the inspector witnessed
portions of the following
maintenance activities:
Unit l
Description
o
Visual inspection of "8" emergency
diesel
generator
(EDG)
o
Change air filters on "8"
EDG starting air system
o
Lube "8"
EDG turning .gear
and bull gear
o
Change
"8" EDG turning gear motor oil
o
Calibration of 1JDGNPI80 (lube oil pressure
at engine for "8"
EDG)
Unit 3
Descry
tion
o
Reload
power ascension
test
o
Reload criticality and low power physics testing
o
CPC "C" troubleshooting
and repair, including retest
using
a
portion of 77ST-9SB03
"CPC Channel
C Calibration"
No violations of NRC requirements
or deviations
were identified.
Anal zer Failure
Due To Nis ositioned
Valve
Unit l ~92700)
On Yiay 27,
1991, the Unit
1 "A"'ydrogen analyzer failed to meet the
acceptance
criteria of surveillance test 41ST-lHP02,
"Containment
Hydrogen Analyzer Functional Test."
This was later determined
to be
caused
by a mispositioned
reagent
gas valve.
The licensee initiated
Condition Request/Oisposition
Request
(CROR) 1-1-001 to document its
investigation of the event.
This review failed to conclusively determine
the root cause of the valve being mispositioned.
The licensee is
considering
actions to reduce
the possibility of recurrence.
The inspector
reviewed the operability of the "8" hydrogen analyzer since
the previous
successful
surveillance test of the "A" .hydrogen analyzer
and determined that both the hydrogen analyzers
were not 'simultaneously
inoperable for longer than the
72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowed by Technical
Specifications
and the "8" hydrogen analyzer
was unavailable
less
than
the
30 days allowed by TS.
No violations of NRC requirements
or deviations= were observed.
Auxiliar
(AFM)
Pu~m ~Tri
Throttle Valve Limits-
Un>t
1
00~
On Yiay 28,
1991, during the performance
of a manual test of the overspeed
trip mechanism of the Unit
1 turbine-driven
41ST-1AF02, "Auxiliary Feedwater
Pump AFA-P01 Operability Test," the trip
throttle valve
( IAFA-UV-54) could not be reset.
The licensee
determined
that limit switch
4 in the Limitorque SNC-4 motor operator for the valve
had,to
be adjusted
by 1/4 hand wheel turn
{HWT) to allow the valve to be
reset.
This adjustment
was performed
and the system
was subsequently
made
4 was set at 0.5
HWT (about
7 percent
open),
which is within the
0 to
10 percent
open
range specified in the Yiotor
Operated
Valve Database,
01-J-ZZI-004, for this valve, which has
a full
stroke of
7
HWTs.
However, the licensee's
experience
indicates
that
a
switch setting closer to 0.35 percent
open is necessary
for reliable
function of this system feature.
The system is designed
such that, in this mode of operation,
the motor
operator closes until either limit switch
4 or the torque switch act to
stop the motor,
and the limit switch is supposed
to be controlling. If
the motor does
not latch with the valve stem, operators
can jog the motor
further closed to engage
the latch.
This could have
been
done in this
instance,
but was not.
The surveillance
procedure
does not provide
guidance for this contingency,
and apparently
not all operators
were
aware that this action
may
be necessary
in order to allow the valve to be
reset.
The licensee
committed to issue Instruction
Change
Request
24417 to
provide this guidance in the surveillance
procedure.
Additionally, the
licensee
committed to consider revising the setpoint. for limit switch 4.
The inspector
concluded that the additional
procedural
guidance
was
appropriate
to ensure
operators
can reset the valve and reopen it as
necessary.
The licensee's
actions with respect
to this event appeared
to
be appropriate.
Ho violations of NRC requirements
or deviations
were identified.
A dii~e
bill
.
U i
9>>02)
On June
13,
1991, the licensee
requested
a Temporary Waiver of Compliance
for relief from Technical Specification
(TS) Limiting Condition of
Operability
(LCO) 3.6.2.2,
due to the inability of the "8" Spray Chemical
,Addition Pump
(SCAP) to maintain the minimum required flowrate per
ASNE
Section XI.
NRC Region
V granted
the waiver on June
13, documented this
in a letter to APS on June
14,
1991,
and the .licensee
achieved
compliance
on June
16,
1991.
The
SCAP is
a positive displacement
pump,
and the test is performed at
103 psig,
near the pressure
safety valve
(PSV) relief setpoint of
110'sig.
The licensee
determined that the pressure
pulsations
caused
by the
SCAP resulted
in the
PSV "simmering" as it failed to reseat,
thereby
establishing
an unintentional alternate
flowpath and reducing the
effective system flow to below the required value of 0.63
gpm.
During
this test,
the test pressure
is established
by manually throttling the
vent on the Spray Chemical
Storage
Tank with a 1-inch globe valve.
The
operator apparently
increased
pressure
too much, causing
the
PSV to
simmer during normal
SCAP operation.
The licensee
was able to
demonstrate
that the
pump performance
was acceptable
in several
tests
with the
PSV gagged,
"and again in several
more tests after the
PSV was
replaced
and the test pressure
carefully increased
to the required value.
Complicating the evaluation of the system
performance
was the
problem of
gas entrained
in the flow transmitter.
Erratic indication resulted
from
this condition, which was not easily resolved
due to -the absence
of a
high point vent.
The licensee installed
a temporary rotometer flow
indicator and confirmed the presence
of gas in the flow.
The =licensee
implemented
a method of backfilling the transmitter to remove entrained
gas which successfully
resolved
the indication deficiency.
The licensee
previously had implemented
a design
change
in Unit 3 which
inverted the transmitter,
making it easier
to vent.
This design
change
also increased
the
PSV relief setpoint to 120 psig, providing greater
margin for the performance of this test.
The design
change
has
not been
10
implemented
in Units
1 or
2 because'he
licensee
is pursuing deletion of
the
TS requirements
for this system.
No violations of NRC requirements
or deviations
were identified;
10.
Emer enc
Safeguards
Features
Actuation System
(ESFAS) Actuation
- Unit
1
93702T
On Nay 17,
1991, Unit
1 experienced
a Containment
Purge Isolation
Actuation and
a Control
Room Essential
Filtration Actuation due to the
failure 'of the Train "B" Power
Access
Purge
Area Radiation Yionitor,
RU-38.
All equipment
responded
as designed,
and the licensee verified that
the actuation
was spurious
and that
no abnormal radiation levels existed
in the vicinity of RU-38.
The cause of the event
was malfunctioning central
processing
unit and
random access
memory boards
in RU-38, which were old style circuit
boards.
The defe'ctive
components
were replaced with upgraded
new circuit
boards
and the monitor was tested
and returned to service.
Additionally,
the licensee
has accelerated
the schedule for replacement
of old style
boards
in the other monitors in all three units which still have not been
upgraded.
This event is also described
in Licensee
Event Report 91-006-00
(see
.paragraph
22 of this report).
No violations of NRC requirements
or deviations
were identified.
111
Mainte'nance
on Mto~nC~om onents
- Units
2
6
3
62703)
Three events
occurred involving maintenance
on the wrong component.
One
of these
events
involved an inadvertent
leak of the pressurized
charging
system resulting in
a primary to atmosphere
leak inside the auxiliary
building.
The other
two events
involved inadvertent actuations
of safety
equipment,
including an Emergency
Diesel
Generator
(EDG), the Containment
Purge Isolation Actuation System
(CPIAS),
and the Control
Room Essential
Filtration Actuation System
(CREFAS).
A.
Reactor
Coolant
Pump
(RCP)
Seal Injection Filter Changeout
On Hay 24,
1991, three Unit 3 mechanics
were to change
out the "A"
train seal injection filter, 3YiCHNF02A.
However, the workers
unbolted
the inservice
"B" train filter, 3MCHNF02B, due to:
turnover communication errors; fai lure to take the work order into
the contaminated
area
as suggested
by 300P-9MP01,
"Conduct of
Maintenance"; failure to properly verify the identification of
equipment
being worked as specified
by the work order
(WO 495993);
failure to verify the equipment
tagged
out as advised
by 40AC-90P15,
"Station Tagging
and Clearance";
and failure of the
gC inspector
present
to provide
an adequate
backstop.
As soon
as
the bolts were loose
enough,
the mechanics
observed
a
high pressure
stream of water coming out the sealing
surface.
They
attempted
to re-torque
the bolts to stop the leak, but were
unsuccessful
because
the o-ring had shifted.
An auxiliary operator
present
contacted
the control
room and control
room operators
immediately isolated
seal injection stopping the leak,
then
proceeded
with other immediate actions required for loss of RCP seal
injection.
The control
room operator actions
were done promptly to
prevent degradation
of RCP seals,
particularly seals
on an idle RCP.
The inspector
rioted that the
QC inspector
complied with the
requirements
of the
QC Plant Inspection
Report (PIR) which required
the inspector to check
each of the work order hold points,
note
correct equipment,
inspect housekeeping,
verify work authorization
and ensure control of material.
The inspector determined that the
QC'inspector
had verified correct equipment
by comparing the work
'order cover sheet
(W.O. 495772) with the equipment identification
label
on the wall near the filter housing,
but did not look at
enough of the work order to identify that the steps for changing out
the filter had already
been completed
and signed off.
The inspector
concluded that the cursory review by the
QC inspector resulted in
his failing to identify that the wrong component
was being worked
on.
The
NRC inspector discussed
this event with the
QC Manager
and
Quality Assurance
(QA) Director.
The licensee
concluded that the
inspector
met their expectations
during the event.
The inspector
concluded that while certain specific
QC requirements
were met,
personnel
should ascertain
that the correct work instructions for the
correct equipment
are being used
and are being followed.
In this
case,
the
QC inspector
was present for sufficient time that
a review
of the work order status
should
have identified that steps
were
being repeated.
Inadvertent
EDG Start
On May 16,
1991
a Unit 3
I&C Technician
performed part of Section
8.6.2 of procedure
on the "8" train auxiliary relay
cabinet rather than
on the "A" train as specified
by Step 8.6.2. 1
resulting in an inadvertent start of the "8" EDG.
The inspector
noted that Step 8.6.2. 1 had
been
signed off in error.
Inadvertent
CPIAS/CREFAS - Unit 2
On June
5, 1991, while attempting to restore
the alarm setpoint
on
the containment
purge radiation monitor,
RU-34, to the post purge
setting in accordance
with procedure
74RM-9EF40, "Radiation
Monitoring System Operations,"
a Unit 2 Chemistry Effluent
Technician inadvertently
changed
the setpoint
on another radiation
monitor, RU-38, resulting in an inadvertent
CPIAS/CREFAS.
While
generic
procedure
74RM-9EF40 did not specifically identify that work
was to be performed
on RU-34, the technician
was also following
procedure
"Gaseous
Radioactive
Release
Permits
and
Offsite Dose Assessment,"
step 10.2.2,
which addresses
only RU-34;
and procedure
74RM-9EF42, "Radiation Monitor Alarm Setpoint
12
Determination," step 6.6.6, which also addresses
only RU-34.
The
control
panel for RU-38 is physically located just below the control
panel for RU-34 and the identification tags for RU-34 and
RU-38 are
at the bottom of the respective
control panels.
While the
technician
could have
looked at the
RU-34 identification tag
and
mistakenly 'associated it with the RU-38 control
panel
below, there
is
a keylock switch in both control panels
which must be operated
to
change
setpoints
and
a second
label is present
under
each
keylock
switch with also correctly identifies the monitor.
It'is important for maintenance
workers to follow the maintenance
program to ensure that appropriate
precautions
are followed,
especially
when maintenance
activities
have the potential for
'impacting plant operations.
The inspector
concluded that in each of
these
cases,
the maintenance workers'ailure
to follow the work
control
program directly caused
the events.
In the seal injection
filter event,
the inspector
concluded that the
gC inspector review
of the work order should
have prevented
the occurrence
of the event,
and that 'the prompt actions of plant operators mitigated the
consequences
of this event.
In each of these
cases,
the failure of workers to verify that they
were working on the correct equipment
are examples of
violations of
NRC requirements
(Violation 529/91-19-01
and
530/91-19-01).
The licensee
responded
to the first event
by initiating Problem
Resolution'Sheet
(PRS)
1572; conducting
an investigation; clarifying
the work order
and requiring
a separate
equipment identification
signoff step;
developing
a formal on-the-job training program for
this task; initiating a work request
to add equipment ide'ntification
labels to the filter lids and shield plugs; briefing all mechanics
on self and team verification practices;
evaluating
the
need for a
work order requirement
to check clearance
tags;
and disciplining
'he
APS and contract workers.
The licensee
responded
to the second
event
by initiating PRS
1544;
conducting
an investigation;
including this event in l&C quarterly
training;
and disciplining the
APS and contract
I&C Technician.
The
licensee
is evaluating possible additional corrective action.
The licensee
responded
to the third event
by initiating Condition
Report Disposition Request
(CRDR) 2-1-0004;
conducting
a
Human
Performance
Evaluation
System
(HPES) evaluation;
and disciplining the
worker.
The
NRC inspector
expressed
concern
regarding
the relatively short
interval of time in which these
three events
have occurred
and that
they each involve personnel
errors.
Senior
APS management
also
expressed
concern that each of these
events
occurred
and
was
evaluating additional corrective actions.
One violation of NRC requirements
was identified.
"t
13
Radiation Protection
(RP) Technician
in
a Ki h Radiation
A~rea
KRA
7
On Nay 31,
1991,
a Unit 3
RP Technician
was observed
by the
NRC inspector
-to enter
a posted HRA'ithout an alarming dosime'ter.
The
RP Technician
indicated 'that since
a survey meter
was being used,
an alarming dosimeter
was not required.
In subsequent
discussions
the
RP Technician identified
that
an error had
been
made.
The inspector
reviewed the
RP Technician's
Radiation
Exposure
Permit
(REP)
and confirmed that
an alarming dosimeter
was required for entry into a posted
HRA.
This is
a violation of
NRC
requirements
(Violation 530/91-19-02).
The inspector
concluded that while the significance of this was lessened
by the presence
and proper
use of an operable
survey meter,
the
requirement
was not met.
In addition,
RP Technicians
are expected
to set
the standard for adherence
to
REP requirements.
A similar violation was
issued
in Inspection
Report 528/90-23
and the corrective actions
focused
on better briefings to radiation workers prior to
RCA entries.
The licensee
responded
by initiating RP Problem Report 3-91-020,
disciplining the
RP Technician involved and adding
"REP Compliance"
as
an
additional topic for the next quarterly
RP Technician training.
One violation of NRC requirements
was identified.
Marker ResRonsibilit
- Unit 3
71707)
The inspector
observed
two examples
in which workers did not follow
through with identified plant problems.
The first example occurred
on
June 4, 1991, during the performance of 72ST-9RX08, "Incore Detector
Channel
Check."
Limitations and Precautions,
step
5. 1, states
that
"Reactor
power should
be at steady state
above
20%
.
. ." and step 7.3
requires
the performer to initial that "Limits and precautions
have
been
read
and understood."
The test
was performed with BDELT power at 19.7%
power yet
no annotation
in the test log was present
documenting
the
apparent
discrepancy.
The performer told the inspector that
an
assumption
had
been
made that this limit- had
been
met because
BDELT was
within the general
Reactor
Engineering definition of their
20% power
plateau.
The inspector
acknowledged
that the minor deviation in power
level
was not significant.
The second
example occurred
on June
13,
1991,
when the inspector
identified posted
Survey
Map 326
on the
120 foot elevation of the
Auxiliary Building to be dated April 16,
1991,
when the latest
survey
map
had
been
performed in Nay 1991.
The inspector identified that
an
Technician
had identified this out of date survey
map
a couple of days
earlier.
The Lead Technician stated that this did not meet their
expectations
in that when the out of date survey
was identified by the
Technician, it should
have
been
updated
immediately.
The
NRC inspector
acknowledges
that local survey
maps
are for worker assistance
and that
up-to-date
surveys
are available at the
RP control point.
However, the
14
local survey maps, if not updated,
may give out of date radiological
information to workers.
This matter is also discussed
in Inspection
Report 50-528/91-23.
The inspector concluded that while the individual significance of these
two problems
were minor, the failure of the individuals to identify and
initiate corrective action reflects
a failure of workers to meet
management
expectations
and to initiate appropriate corrective actions
when deficiencies
are identified.
The licensee
acknowledged
the
inspector's
comments
and is evaluating possible corrective action.
No violations of NRC requirements
or deviations
were identified.
Refuelin
Activities and Startup
From Refuelin
- Unit 3
60710
and
7T7TT7
The inspector walked
down significant portions of the unit, with special
attention to the Emergency
Oiesel
Generators
and "8" High Pressure
Safety
Injection Train,
and concluded that the unit appeared
to be ready to
resume
power operations.
The inspector
observed
the approach
to criticality, portions of low power
physics testing,
and preparations
for performance of the rod shadowing
factor/radial
peaking factor measurement
per procedure
"Reload
Power Ascension Test," Appendix L.
In general
the licensee
conducted
these activities acceptably.
Inspector
questions
with regard
to
a lack of guidance for determination of Group
5
CEA rod worth were
resolved
based
on the minimal impact on safety significance.
The inspector
noted that initials were missing from the review block for
three reviews of the
CECOR Snapshot
Record
(72PA-9ZZ07, Appendix 8).
These occurred over
a short period of time.
The procedure
states
that
the review should
be performed at approximately hourly intervals.
This
apparent
discrepancy
was pointed out to the reactor engineering
supervisor,
who evaluated
the omissions
and determined that adequate
reviews
had occurred.
One additional
comment from power ascension
testing is in paragraph
13 of
this report.
No violations of NRC requirements
or deviations
were observed.
Valve Prematurely
Released
t~o 0 erations
- Unit 3 (61726)
Valve SI-652 was tagged
out and the actuator partially disassembled
for
an
MOV grease
inspection.
When the actuator
was reassembled,
the limit
switch clutch was not re-engaged.
The work step associated
with this
step (step 4.7 of Work Order 493034) specified reinstalling the limit
switch but did not address
re-engaging
the clutch.
The clearance
was
released
before the work was complete
and when operations
stroked the
valve,
the position indication did not change
and the actuator
backup
breaker tripped
on overload.
This occurred
because
the limit switch
never
moved from its open position
and the torque
bypass
switch remained
15
closed disabling the torque switch function.
An engineering
evaluation
of the valve concluded that
no damage
occurred
and the valve could
be
declared, operable.
The inspector
concluded that the work order
needed
to
be more detailed
and that there
was
an over-reliance
on "skill of the
craft" to remember
to re-engage
the limit switch clutch when the switch
is installed.
The inspector further concluded that there
appeared
to be
poor communications
and
a failure of the foreman to ensure that the work
was complete prior to releasing
the clearance.
The licensee
acknowledged
arid agreed with the inspector's
comments
and is evaluating corrective
actions
No violations of
NRC requirements
or deviations
were observed.
Wrestle
house
ARU Rela
Failure - Unit 3
92700)
On May 22,
1991, following the failure of a Westinghouse
ARD 660-UR relay
in a Unit 3 auxiliary relay cabinet,
the .licensee
issued Material
Nonconformance
Reports
(MNCRs) 91-ZA-9004 and 91-ZJ-9004
because
of the
potential for common
mode failure.
The relay failed due to epoxy,
possibly from the relay internals, interfering with the plunger.
The
licensee
has identified 54 continuously energized,
harsh
environment
relays of this type in safety-related
applications
in each unit,
and
has
initiated Root Cause of Failure
(RCF) Engineering Evaluation
Requests
91-ZA-016 and 91-ZA-033.
Another
ARD 660-UR relay failed the previous
month in Unit '2 and,was
sent to Westinghouse
for RCF evaluation.
This
vendor's
RCF evaluation
provided additional
information, but was
inconclusive.
The licensee
has
requested
that the relay be returned for
inclusion in the licensee's
RCF evaluation.
The licensee
is also
evaluating
the testing
program for each specific affected relay.
The licensee
has
reviewed the history of Westinghouse
ARD relays
regarding
the deterioration of the coi 1 encapsulation
(epoxy) material
and the cracking of relay cases
of continuously energized
relays.
Subsequent
to this inspection period, Westinghouse
issued
a Part
21
report dated
June
24,
1991 regarding
the
ARD relays
and others with
potential
epoxy deficiencies.
The inspector will review the licensee's
RCF evaluation
upon completion
(Followup Item 530/91-19-03).
No violations of NRC requirements
or deviations
were identified.
Nuclear
Steam
Supp~1
S stem
(NSSS)
Vendor Technical
Performance-
Units 1, 121 3~71707
Several
recent technical
products
from the
NSSS vendor have
been identified
by the licensee
to have quality discrepancies.
The products that
contained quality discrepancies
were:
CECORE coefficient files provided for the Unit 3 restart in June
1991 were in error.
The error was discovered
by the licensee's
Nuclear Fuels
Management
personnel
who reviewed the results.
16
B.
C.
The mini-incore instrument replacement
project
had
a data collection
unit which did not work and
had never
been tested
by the
vendor.
In addition, minor computer
program errors inhibited full
testing of the mini-incore instruments.
Control
Element Assembly
(CEA) lower gripper coil leads
were
reversed
to eliminate coil movement which is believed to have
contributed to the damaged insulation,
momentary grounding,
and
slipped/dropped
CEA events.
Inadequate
testing of this design
change failed to identify a problem which occ'urred during low power
physics testing in which with CEA
1 fully withdrawn and
Regulating
Group
3 inserting,
spurious
reed switch position
indications
caused
Control Element Assembly Calculator
(CEAC) input
data errors.
Tkis design
change
was
removed prior to the
continuation of critical plant operations.
D..
Loose Parts
Event Analysis Computer .is experiencing
a memory lock-up
error and co'ntinuous
alarm, which is design related.
The inspector
acknowledged
the licensee's
review and testing
programs
which identified these
problems
and encouraged
continued
commitment to
this effort.'he inspector further acknowledged
the licensee's
efforts
to develop
some technical
resources
in-house to diminish reliance
on
vendor technical
support,
including that provided
by the
NSSS vendor.
The inspector
was concerned
in that reliance is placed
on the
NSSS vendor
to provide accurate
and reliable technical
responses
to address
regulatory concerns.
The licensee
responded
by stating that they are
presently
addressing
these
concerns
with the
NSSS vendor.
See also
paragraph
19 of this inspection report.
No violations of NRC requirements
or deviations
were identified.
18:
"8"
Ch
i
1 i~lifi ~ilTE)
Uni ts 1,
2
3
71707
This issue relates
to
TS 3.3.3.5 for the remote
shutdown
panel
and the
fact that the "B" charging
pump is necessary
for safe
shutdown
under
certain postulated fires.
The "B" charging
pump circuits, are listed
under
The inspector
noted that Unit
1 recognized
the
need to
enter Limiting Condition. for Operation
(LCO) 3.3.3.5.b
when the "B"
charging
pump was inoperable
on April 10,
1991.
The lack of timely
resolution of the ensuing
disagreement
over whether entry into the
LCO
was appropriate
resulted
in Unit 2 not entering this
LCO on May 20,
1991.
The "B" charging
pump was restored within 7 days
and therefore
the
LCO
was met.
The inspector
concluded that the lack of timely resolution of
this
TS interpretation resulted
in inconsistent plant administrative
actions
and encouraged
the licensee to resolve
TS interpretation
issues
promptly.
The licensee
acknowledged
the inspector's'omments.
No violations of
NRC requirements
or deviations
were identified.
17
19.
Safet
Anal sis Error - Units 1,
2 and
3 (92700)
A significant non-conservative
error in the initial subcritical
power
level assumption
used in the continuous
Control
Element Assembly
(CEA)
bank withdrawal analysis
was identified by Asea
Brown Boveri/Combustion
Engineering
(ABB/CE) when investigating differences
between results of
calculations
by
a Korean utility and
CE.
CE notified the licensee of the
'error
on Nay 24,
1991.
The erroneous
power level
was calculated
by the
ORIGIN computer code,
which apparently
had two errors.
One error was the
omission of a conversion factor (238 g/mole U-238)
and the other was
an
incorrect factor in the burnup of the
CEA modeled
by ORIGIN.
The result
was that the initial subcritical
power level
(when
1% subcritical) for
the
CEA bank withdrawal analysis
was too high by a factor of about
5000.
During the Unit 3 reactor startup
from the'ycle
3 refueling outage,
the
licensee
complied with the administrative restrictions
recommended
by
to compensate
for this error.
This involved maintaining Reactor Coolant
System
above the hot full power critical boron
concentration until the shutdown
CEAs were fully withdrawn.
The licensee
determined
the following relevant information in its
discussions
with CE:
o
The ORIGIN calculation applies at least to all
CE 16x16 reactors,
and is not generally repeated for each reactor
or fuel cycle.
o
The Palo Verde reactors
are at greater risk than other utilities
because their shutdown
banks
have
more reactivity and
a larger
initial reactivity insertion rate (0. 18% delta rho/inch).
The worst
case withdrawal is shutdown
bank "B," due to its large
bank rod
worth.
o
The safety analysis
assumes
a trip on high logarithmic power.
The
power spike from a continuous withdrawal event initiated at
a higher
power level is less significant than if initiated at
a lower power
level,
due to the lower startup rate
(SUR).
o
Two administrative
methods
prevent this faulty initial condition
from being
a problem,
because
the combination of lower core
reactivity (due to boron concentration)
or lower reactivity
insertion rates
prevent the worst case initial conditions
from
occurring.
Either of the two following methods will compensate
for
the error in the analysis:
Require all part-length
(PLCEAs) to be inserted
whenever
shutdown
CEAs are inserted.
This inserts
an
8% penalty factor on
the planar radial
peaking factor which results
in
a
DNBR trip when
the
CPC trip is enabled at 10E-4 percent
power.
This trip occurs
much earlier than the high logarithmic power trip would occur.
and the licensee
have concluded that the regulating
banks
are
limiting under this condition.
~ P.
'
i
18
Require
to be maintained greater
than the
hot full power critical boron concentration
whenever
shutdown
are not withdrawn.
o
CE and the licensee
have confirmed that the safety analysis is
conservative with respect
to current operating practices.
The
licensee
is verifying if its procedures
already
implement these
restrictions
under all conditions,
and Night Orders
are in place
until appropriate
procedural
changes
are
implemented.
o
Based
on discussions
with Shift Supervisors,
the licensee
has
determined
the operating practice
has
always
been to withdraw the
shutdown
CEAs prior to the
PLCEAs during startup.
o
CE performed additional evaluation
and determined that the Palo
Verde safety analysis
remains valid.
Licensee
personnel
went to
headquarters
to review the vendor's calculations
and analysis.
letter V-19-196, dated
June
17,
1991,
documents
that adequate
protection exists
due to the Core Protection Calculator trips
without reliance
on administrative controls.
This letter concludes
that the
NRC Safety Evaluation Report for this event remains valid.
Additionally, CE concluded that these errors
do not result in
consequences
which are reportable
under
The licensee
does
not regard this event
as reportable.
No violation of NRC requirements
or deviations
were identified.
20.
Essential
and
Emer enc
Li hartin Train S~earation
- Units 1,
2 and
3
During the performance of Prefire Strategies
unit walkdowns,
the licensee
identified that the power cables for both trains of Emergency Lighting
and Essential
Lighting for the control
room all passed
through the "A"
Essential
Switchgear
room.
This condition is
common to all three units.
On May 29,
1991, the licensee
issued
a Conditional
Release
to Material
Nonconformance
Report
(MNCR) 91-QD-9084 specifying compensatory
measures,
which include implementation of design modifications in all units within
four months to properly separate
the trains.
Additionally, each unit
issued
a Night Order advising operators
of the condition, since
a fire in
the "A" Essential
Switchgear
room could disable all control
room
lighting.
The Night Order instructs operators
to shutdown the unit from
the control
room if all lights are lost as
a result of a fire, but leaves
the decision to evacuate
and remotely shutdown to the Shift Supervisor.
During an event of this nature,
the licensee
anticipates
that- lighting
from annunciators
and indicators,
in addi tion to the available
flashlights,
would provide adequate
illumination to safely conduct the
shutdown
from the control
room.
Based
on the physical
separation
of cables within the area
and the fire
suppression
capability, the inspector
concluded that this was
a low
probability event.
The inspector
reviewed the
MNCR and concluded that
licensee
actions
were prudent
and adequate,
No violation of
NRC requirements
or deviations
were identified.
19
21.
Fire Watch Trainin~Units 1,
2 and~364704)
In
a letter dated April 1, 1991, the
NRC Region
V Office requested
APS to
provide certain information regarding
the fire watch training program at
Palo Verde.
APS provided
a response
in a letter dated
Nay 31,
1991 which
confirmed that
12 of 155 personnel
who had conducted
roving fire watches
during the time period of interest
were not fully qualified.
The basis
for not being fully qualified included,
no fire watch training (5
people),
incomplete fire watch training (2 people),
and not current for
annual retraining
(5 people).
APS took immediate actions to verify that
the personnel
who were currently performing fire watch duties
were in
fact fully qualified and to develop
a list of qualified fire watches.
The failure to ensure that fire watches
had
been fully trained or had
completed re-training prior to performing fire watch duties is
a
violation of NRC requirements
(Violation 528/91-19-01).
A review of the
Nay 31,
1991 response
by .APS and discussions
with
Employee
Concerns
personnel
who performed the training program review for
APS, identified that the formal fire watch training program consists
of
two parts,
a computer-based
portion and
a classroom practical
course.
This training is specified in procedure
and detailed in
procedure
In addition, on-the-job training has
been
documented
by the use of "qualification cards" which include
documentation
of the completion of the formal training, reading
and
understanding fire watch procedure
performance of a 'fire
watch under instruction of a qualified fire watch,
and
a final checkout
with the work group supervisor.
However, completion of the qualification
card is not considered
to be
a requirement prior to being qualified as
a
Procedure
was stated to have
been
covered during
the formal 2-part training program.
A "Fire Watch Orientation Guide" has
been distributed which serves
to facilitate completion of the
qualification card
and will contain updated
procedure
14AC-OFP04 which is
currently being revised.
The
APS review focused
on the formal training
and not the comp/etion of the qualification card.
Based
on the review of the training for fire watches
used for
compensatory
measures
and the training deficiencies identified,
expanded its review to "hot work" fire watches.
APS initial results
indicate that
some "hot work" fire watches
were also performed
by
individuals
who had not been given requalification training.
IIR
3-1-91-041 is being prepared
by the Fire Department regarding this
review.
22.
One violation of
NRC requirements
was identified.
Review of Licensee
Event
Re orts - Unit
1 (90712
and
92700
The following LERs were reviewed
by the Resident
Inspectors.
Unit
1
- a.
Closed)
LER 528/88-06-Ll/L2: "Surveillance Interval
Exceeded
For Incore Detecto~r
S stem,~ Unit
1
92700
This report refers to the March 21,
1988, discovery that
a
Surveillance
Test
(ST) was not performed prior'o Narch 20,
1988,
as
20
required
by Technical Specification (TS) 4.3.3.2.a.
This event
was
initially reviewed
and documented
in
NRC Inspection
Report
528/88-14.
The licensee
determined that the event
was
caused
by a cognitive
personnel
error, but that the lack of a formal tracking mechanism
for conditional
was
a contributory cause.
The inspector
reviewed the procedures
developed
or revised
as
a result of this
event
and
has discussed
ST tracking
on several
occasions
with the
licensee.
Additionally, no
ST performance intervals
have
been
reported
as having
been
exceeded for approximately
one year.
The
inspector
concluded that the licensee's
corrective actions
have
adequately
addressed
tracking of STs
such that recurrence
of this
event is less likely.
Based
on this review, this item is closed.
Closed
LER 528/90-02-LO/Ll:
"Un uglified Air Re ulators
in
DV Contro
ir S stem -
Un ts
1,"
2 and
3
92700
This
LER describes
the
May 23, 1990, discovery of unqualified air
regulators
in the Atmospheric
Dump Valve (ADV) control air system.
This
LER also served
as
a Part
21 report, in that the procurement
documentation for the regulators
required
Environmental
Qualification
(EQ) and seismic qualification.
The
LER describes
the
procurement activities associated
with these regulators.
Even
though the supplier claims these
were supplied
as
commercial
grade
materials,
licensee
records
indicate that documentation
supporting
environmental
and seismic qualification were received,
though this
documentation
cannot
now be located.
Additionally, a
1986 Material
Nonconformance
Report
(MNCR) regarding
a subsequent
purchase for
Unit 3, for which qualification documentation
was not provided,
was
dispositioned
by changing
the quality classification to
a
non-quality class.
Justification for the quality class
change
has
not been located
by the licensee.
The licensee
determined
that no ineediate operability concern
existed,
and subsequently
procured
and installed qualified
regulators
in the
ADV control air system.
The licensee
asserted
that programmatic
changes
in its procurement
and design
change
programs
have
been
made over the years
since these
regulators
were
purchased
which would prevent recurrence
of this event.
Additionally, the licensee
completed
a review (Quality Deficiency
Report 90-0317,
Incident Investigation Report 3-2-90-025) of a
sample of purchase
orders
(POs) to evaluate
the transportability of
the lack of adequate
engineering specifications
and the inadequate
PO-review
and approval
process.
This evaluation
concluded that,
with 95 percent confidence,
the error experienced
in the procurement
of the regulators
is absent
from more than
95 percent
of. the
populati'on of "Q" class
POs with field material requisitions
referencing
home office specifications.
Based
on this review, this
LER is closed.
21
c.
(Closed)
LER 528/91-06-LO:
"ESF Actuation Due To Radiation
Nonitor Fai ure
- Unit
1
92700
This event is described
in paragraph
10 of this report.
This
LER is
closed.
23.
Exit Meet~in
An exit meeting
was held on June 20, 1991, with licensee
management
during which the observations
and conclusions
in this report were
generally discussed.
The licensee
did not identify as proprietary
any
materials
provided to or reviewed
by the inspectors
during the
inspection.
~ b
I
0
I