ML17306A674
| ML17306A674 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 04/07/1992 |
| From: | Vandenburgh C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17306A672 | List: |
| References | |
| 50-528-92-05, 50-528-92-5, 50-529-92-05, 50-529-92-5, 50-530-92-05, 50-530-92-5, NUDOCS 9204220052 | |
| Download: ML17306A674 (42) | |
See also: IR 05000528/1992005
Text
. S.
ATORY
ON
GION V
~t
~t
ce
se
os.
~ice see
50-528/92-05,
50-529/92-05,
and 50-530/92-05
50-528,
50-529,
and 50-530
and NPF-74
Arizona Public Service
Company
P. 0.
Box 53999, Station
9012
Phoenix,
AZ 85072-3999
g
yi
II
d
g
i
g
i'gg<<i
Units 1, 2,
and
3
s ect
on
onducted:
roved
B
January
26 through February
29,
1992
an
en urg
,
c sng
le
Reactor Projects
Section
2
ate
sgne
g.
g
L. Coblentz,
F. Ringwald,
J'. Sloan,
L. Tran,
W. Ang,
ns ect on Suaear
Senior Resident
Inspector
Radiation Specialist
Resident
Inspector
Resident
Inspector
Resident
Inspector
Project Inspector
s ectio
o
Ja uar
26 t r u
h Februar
29
199
Re ort
umbers
50-528 92-05
50-529 92-05
and 50-530
9 -05
td:
g ti,
it,
gi
dg ttiitt
d ti
tytt
resident
inspectors
and Region
V based
inspectors.
Areas inspected
included:
review of plant activities
engineered
safety feature
system walkdowns
Unit 2
surveillance testing
Units 2 and
3
plant maintenance - Units 1, 2,
and
3
incore instrument cable withdrawal
Unit
1
plant protection
system setpoint incorrect - Unit
1
essential
spray pond, pump breaker failed to close
on demand
Unit 2
emergency diesel
generator
engineered
safety features
walkdown - Unit 2
startup testing - Units
2 and
3
pump plant computer alarms - Units 2 and
3
reactor
power cutback - Unit 3
9204220052
920407
ADOCK 05000528
0
core operating limit supervisory
system software modification
implementation
Unit 3
quality assurance
and audit program review - Units 1, 2,
and
3
followup on previously identified items.
During this 'inspection the following Inspection
Procedures
were utilized:
35701,
40702,
61726,
62703,
71707,. 71710,
72700,
92700,
92701,
92702,
and
93702.
lLesults:
Of the
14 areas
inspected,
three violations were identified.
Th'ese
involved the failure to follow procedures
during the withdrawal of incore
nuclear instrumentation
(Paragraph
6) and the failure to follow procedures
during surveillance testing of the plant protection
system
(Paragraph
7).
One
violation regarded
lack of documentation
concerning the quality of calibration
gas for containment
hydrogen monitors
(Paragraph
4).
General
Conclusions
a
d
S ecific Fi din s:
Si nificant Safet
Matters:
None
Violations;
Deviations:
Two cited violations - Unit
1
One cited violation
Units 1, 2,
and
3
None
Five new followup items were opened,
seven followup items
were closed,
and
one followup item was left open.
Stren ths Noted:
Operator response
to a Unit 3 tripped condensate
pump
was'rompt
and appropriate.
A senior operator's
prompt
identification of an incorrect reactor trip setpoint
was
also noted.
The
gA audit program was reviewed
and found to
be performance oriented
and focused in areas of relative
importance.
~k<<Ntd:Dp
t
i tt ti
t
1gk pig
dt hgd
inattention to
a procedure
resulted
in a missed reactor trip
setpoint discrepancy.
Haintenance
personnel
were observed
departing
from a procedure to withdraw. instrumentation
cable
from the core during refueling.
e sons
Cont
ted
The below listed technical
and supervisory
personnel
were
among those
contacted:
ri ona
ublic Se v'ce
- R.
- T
%J
- S
- R.
- E.
- R.
- R.
- S
- 'g
- M
- J
D.
- G
- R
T.
R.
- B
Adney,
Bradish,
Baxter,
Borst,
Bouquot,
Dotson,
Flood,
Fullmer,
Guthrie,
Ide,
Kerwin,
Levine,
Hauldin,
Overbeck,
Rouse,
Shriver,
Stevens,
Whitney,
Plant Manager,
Unit 3
Manager;
Compliance
Engineer,
Compliance
Engineer,
Technical
Data
Supervisor, guality Audits
, Director, Engineering
Plant Manager,
Unit 2
Hanager,
equality Audits and Honitoring
Site Director, guality Assurance
(gA)
Plant Manager,
Unit
1
Manager,
Maintenance
Standards
Vice President,
Nuclear
Power Production
Director, Site Maintenance
& Hods
Site Director, Technical
Support
(STS)
Supervisor,
Compliance
Assistant Plant Manager,
Unit 2
Director, Nuclear Licensing
& Compliance
Technical Specialist II, guality Audits
Site
Re resentatives
- J
- M.
- R.
Draper,
Benac,
Henry,
Site Representative,
Southern California Edison
Hanager,
El Paso Electric (EPE)
Site Representative,
Salt River Project
Denotes
personnel
in attendance
at the Exit meeting held with the
NRC resident
inspectors
on March 5,
1992.
The inspectors
also talked with other licensee
and contractor
personnel
during the course of the inspection.
eview of Plant Activities
71707
and 93702
a 0
Unit
1
Unit
1 operated
at essentially
100X power until it began
a pre-
refueling power coastdown
on February
10,
1992.
The plant was
shutdown from 92K power on February
15,
1992, to commence
the
Cycle
4 refueling outage.
Cooldown to Mode
5 was promptly
completed,
and'ode
6 was entered
on February
24,
1992.
At the
end of the inspection period, the Unit was in Mode 6 with the head
removed but with no fuel removed
from the reactor vessel.
Unit 2
Unit 2 operated
at essentially
100X power throughout the
inspection period.
Jl~t 3
Unit 3 entered this inspection period in Hode
3 with a reactor
startup in progress,
and went critical at':04
AH (HST) on January
26,
1992.
A normal
powe'r ascension
followed, with 100X power
being achieved
on January
27.
On February 5,
a reactor
power
cutback to approximately
60X power was experienced
following the
manual tripping of the "A" main feedwater
pump (see
Paragraph
12).
Several
Core Operating Limit Supervisory System
(COLSS) failures
occurred following the installation of a
COLSS status
page display
on the plant computer
(see
Paragraph
13).
The software
change
had
been intentionally installed while at reduced
power to minimize
operational'mpact,
but had to be removed prior to returning the
plant to full power on February 6,
1992.
The plant operated
at
'essentially
100X power for the remainder of the inspection period.
ant Tour
The following plant areas
at Units 1, 2,
and
3 were toured
by the
inspector during the inspection:
Auxiliary Building
Control
Complex Building
Diesel Generator Building
Fuel Building
Hain Steam Support Structure
Radwaste Building
Technical
Support Center
Turbine Building
Yard Area and Perimeter
The following areas
were observed
during the tours:
(1)
0 erat'n
o s
and
ords - Records
were reviewed against
technical specifications
and administrative control
procedure
requirements.
The inspector
noted that
on February
20,
1992,
a Shift
Supervisor in Unit 2 did not log entry into Technical
Specification Action Statement
3.3.1
when reactor trip
breaker
"8" was removed for preventive maintenance.
On
February
29,
1992, the inspector
noted
a key in the "B"
train spray
pond spray
mode selector switch, with the spray
mode selected.
The key is normally placed in the switch
only during switch operation.
The inspector
was informed
that these
were inconsistent with management
expectations
and administrative control procedure
"Conduct of
- 2-
Shift Operations."
The individuals involved were
counselled.
At the exit the licensee
indicated that there
was no need to enter Action Statement
3.3. 1 when reactor
trip breakers
are opened
and
removed for maintenance
because
the removed breaker is fulfillingthe safety function.
The
inspector considers this to be
a consistency
issue since
Action Statement
3.3.1
was entered
when the "0" reactor trip
breaker
was removed for preventive maintenance
the next day
in Unit 2.
The licensee policy currently is to log all
breaker
removals
as action statement entries,
but is
evaluating this interpretation for possible
change.
onitori
nst
ume tatio
Process
instrument's
were
observed for correlation
between
channels
and for
conformance with technical specification requirements.
~hfdf
g
ff1
C t
I
d kfft t fff g
observed for conformance with 10
CFR Part 50.54.(k),
technical specifications,
and administrative procedures.
ttf
-II
I
I
d
I tf Ik
I
were verified to be in the position or condition required
by
technical
specifications
and administrative
procedures
for
the applicable plant mode.
On January
29,
1992, the inspector noted that the oil level
in the "A" AFW pump turbine was about 1/4" above the high
normal
mark on the placard
by the sightglass.
The Auxiliary
Operator
(AO) had checked
on the logs that the level
was
between the scribe marks,
and stated that the level
had
been
like that since the refueling,
and
was slightly higher in
the afternoons.
The level
was between the scribe
marks in
the sightglass
holder.
The inspector discussed
the recent
resolution of this issue
from Unit 3 observations
(see
Inspection
Report 528/91-40,
Paragraph
2.D and Inspection
Report 528/91-35,
Paragraph
2.d) with the Shift Supervisor,
who was also
unaware of the proper oil level
band.
A
mechanical
maintenance
foreman indicated that the level
had
been intentionally left high following the overhaul
during
the refueling to allow for air bubbles to settle out.
The
level
was well within the operability range.
In response
to
this observation,
the l.icensee initiated
a change to the
logs to show that the correct range is between the high
'normal
and low normal marks.
The inspector
concluded that
the licensee
had not fully implemented its program for
maintaining the correct oil level in the
pump turbine,
but
that the followup actions
taken
appeared
appropriate.
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)
dit'ons
Plant equipment
was
observed for indications of system leakage,
improper
lubrication, or other conditions that could prevent the
systems
from fulfillingtheir functional requirements.
'(1)
. ~f<<i
- f(
f(ghti g
8 Ip
t
d
t
observed for *conformance with technical specifications
and
administrative procedures.
(8) ~Ch
t
- th
I
I
ly I
It
I
d
for conformance with technical specifications
and
administrative control procedures.
(9)
~Secur t
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)
la t Housekee
in - Plant conditions
and material/equipment
storage
were observed to determine the general
state of
cleanliness
and housekeeping.
(ll)
adiation 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,
complianc'e with
radiation exposure
permits,
personnel
monitoring devices
being properly worn,
and personnel
frisking practices.
(18)
~SI I
1
gl ift.ht
8
P
I I
I t(
briefings were observed for effectiveness
and thoroughness.
No violations of NRC requirements
or deviations
were identified.
n ineered Safet
Featui e
S stem Walkdowns
Unit 2
71710
The Unit 2 train A and
B emergency diesel
generators
were walked down by
the inspector to confirm that the system
was aligned in accordance
with
plant procedures.
No violations .of NRC requirements
or deviations
were identified.
Surveillance Testin
Units
2 and
3
61726
Selected
surveillance tests
required to be performed
by the technical
specifications
(TS) were reviewed
on
a sampling basis to verify that:
1) The surveillance tests
were correctly included
on the facility
schedule;
2) A technically adequate
procedure
existed for performance of
the surveillance tests;
3) The surveillance tests
had
been
performed at
the frequency specified in the TS;
and 4) Test results satisfied
acceptance
criteria or were properly dispositioned.
Specifically, portions of the following surveillances
were observed
by
the inspector
during this inspection period:
Unit 2
J?rocedure
escr
tion
42ST-2AF01, "Auxiliary-Feedwater
Pump AFN-POl Operability 4.7. 1.2.A"
"Reactor Coolant System Mater Inventory Balance 4.4.5.2. 1.C"
"Containment
Hydrogen Monitoring System Calibration Test,
Channel
A"
~Un't 3
~roced
e
escri t o
"PASS Functional Test"
During the performance of TS Surveillance Test
(ST) 36ST-9HP03 in Unit
2,
on February ll, 1992, the hydrogen
span
gas that was being
used
as
a
calibration gas for the
ST had chemical
composition certification
documentation
attached to the gas bottle.
The inspector
reviewed the
chemical
composition documentation
and. noted the following:
, The documentation certified the gas to be 95.6
X N2 and 4.4X
The documentation
did not specify whether
the percentage
was
by volume or by weight.
TS 4.6.4. 1
requires that the surveillance
be performed using
a
sample
gas containing
a nominal four volume percent
hydrogen, with the balance nitrogen.
The chemical composition certificate was provided on
a vendor
letterhead
of a vendor that was not on the licensee's
approved
supplier list.
The certification was signed but the signature
was
illegible.
No title was provided for the certifier, ie.
gA, gC,
Chemist, etc.
Inspector
Followup Item 529/91-04-02 identified inspector
concerns
- regarding the quality of the calibration gas
used for the subject
surveillance test.
The inspector discussed
the above noted
documentation
observations
and the Inspector
Followup Item with the
system engineer,
the Unit 2 Maintenance
Manager,
Unit 2
IKC test
personnel,
and guality Engineering.
The inspector
was informed that
an
audit had
been performed
on
a prospective
vendor for the calibration gas
and that
gA was working with the vendor to resolve audit discrepancies
and to place the vendor
on the licensee's
approved suppliers list.
However, in the interim,
a sampling inspection of the calibration gasses
in stock had
been performed
and that sampling inspection
had determined
that the calibration gas in stock had chemical certification that could
be traced to the prospective
vendor to allow use of those calibration
gas bottles that were in stock. for ongoing surveillance tests.
The
subject
gas bottle however was determined to have chemical
composition
certification that could not be traced to the prospective
vendor.
The licensee
declared
Containment
Hydrogen Monitor .Channel
A, 2-J-HPA-
E02, inoperable for surveillance
and reperformed the surveillance
using
a calibration gas that had
a chemical
composition certification that
could be traced to the prospective
vendor.
The licensee
stated that the
reperformance
of the
ST resulted in little or no adjustment indicating
that the previously used calibration gas,
although lacking traceable,
certification,
was of the required chemical
composition.
The licensee
also promptly inspected all other span
gas bottles attached to all
Containment
Hydrogen Monitors in all three units and determined that one
monitor in Unit
1 and another in Unit 2 had similar chemical
composition
certification lack of traceability problems.
Similarly, the licensee
reperformed
the
ST on those monitors
and obtained similar results.
10 CFR 50, Appendix B, Criterion XII, requires that measures
be
established
to assure
that tools,
gages,
instruments,
and other
measuring
ahd testing devices
used in activities affecting quality are
properly controlled, calibrated,
and adjusted
at specified periods to
maintain accuracy within necessary
limits.
TS 6.8. l.a requires that
written procedures
be established
covering the procedures
recommended
in
Regulatory
Guide 1.33, Revision 2, February
1987.
Revision 2, Appendix A, Section 6.a. requires that procedures
of a type
appropriate to the circumstances
should
be provided to ensure that
tools, gauges,
instruments,
controls
and other measuring
and testing
devices
are properly controlled, calibrated
and adjusted
at specified
periods to maintain accuracy.
Surveillance Test Procedure
Revision 7, Containment
Hydrogen Monitoring System Calibration Test,
Channel
A, Paragraph
4.0, lists calibration gases
measuring
and test
equipment
used in performance of the
TS 4.6.4. 1 surveillance test.
Procedure
Revision 1,
ANPP METE Control Program,
provides
the licensee's
controls for measuring
and test equipment.
The use of calibration gas that did not have chemical
composition
certification that was traceable
to a national
standard,
for performance
of the subject
ST,
appeared
to be
a violation and was identified as
violation 528/92-05-03.
Inspector
Followup Item 529/91-04-02
was closed
and the item will be followed up as part of the identified violation.
One violation of NRC requirements
was identified.
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 quality assurance/quality
control department
involvement,
pr oper 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.
Specifically, the inspector witnessed
portions of the following
maintenance activities:
it
1
Troubleshoot flow interference
in letdown ion-exchanger
discharge
piping
Replacement of PKB and
PKD batteries
Placement of multi-stud tensioner
Incore instrument cable withdrawal
Control element drive mechanism
fan disassembly
Reinstallation of a missing stud in valve SIA-V476 yoke
Preventive
maintenance
of "B" reactor .trip switchgear breaker
The inspector noted that
a mechanical
maintenance
foreman in Unit 2
identified a stud
on the high pressure
safety injection pump discharge
isolation valve SIA-V476 that had loosened
and completely separated
from
the valve.
This stud is one of four. which secure
the manual
operator to
the valve yoke.
The System Engineer determined that the remaining three
studs
had sufficient strength to permit operation of the valve,
and
worked with mechanical
maintenance
to get the stud reinstalled promptly.
The inspector
observed
the reinstallation of the stud.
The licensee
could not determine the cause of the loosened
stud.
The inspector
concluded that the licensee's
identification and corrective action were
appropriate.
Unit 3
~
"E" Charging
Pump Gear
Box Replacement
and Electrical
Retermination
~
Equipment gualification Protective Maintenance of SGA-UV-1135
No violations of NRC requirements
or deviations
were identified.
ncore Instrument
Cable Withdrawal - Un't
1
62703
During a containment tour on February
25,
1992, the inspector
observed
several
tasks in progress
in or around the reactor cavity, in
preparation for the reactor
head li.ft.
At the incore instrument (ICI)
holding platform, the inspector
observed
several
workers attempting to
manually raise fixed ICI ¹55 from the level of the seal table to the
holding platform.
The inspector
raised
a concern with the level of
control applied to this task.
Procedure
"Withdrawal of the Incore Instruments for Reactor
Refueling Operations," outlines precautions
to be used
when withdrawing
ICIs, including cleanliness
considerations,
limitations on withdrawal
force, protection of components,
avoidance of radiological
hazards,
limitations on axial bending
and
so forth.
Section 8.4.5 requires
ICI
-'7-
withdrawal to be accomplished
using the control element
assembly
(CEA)
hoist, which provides automatic controls for the withdrawal process.
Of 61 fixed ICIs, all but one
had already
been withdrawn several
days
earlier using the control element
assembly
(CEA) hoist, in accordance
with Procedure
At that time, fixed ICI 155 had
been
found
to be stuck.
The licensee
had written a special
work package
and
radiation exposure
permit
(REP) to cut the seal table closure
cap for
fixed ICI f55, in hopes of freeing the stuck instrument cable.
The
closure
cap
had
been cut out without incident.
At the time of the inspector's
observation,
the
CEA hoist was blocked
from the ICI area
by recently erected scaffolding.
This prevented
withdrawing of fixed ICI $55 in accordance
with procedure
Due to the additional effort and delay needed to move the scaffolding,
the work group supervisor verbally instructed the task shift leader to
attempt to withdraw the ICI by hand.
The procedure did not cover this
method of handling the ICI.
During initial efforts to free the stuck cable,
one worker pulled from
the ICI holding platform (using
a nylon rope
and shackle
attached
to the
ICI cable)
and
one worker pulled at the seal table, with an
technician standing
by at the seal table to monitor changing
radiological'onditions.
Several
attempts
were necessary
to free the
cable.
When, finally, the ICI pulled freely, the worker at the holding
table hauled the ICI hand-over-hand
approximately
20 feet to the level
of the holding platform.
The inspector
noted the following areas
of concern:
a.
Use of the
CEA hoist for ICI withdrawal automatically limits the
lifting force'o 500 pounds.
While manual withdrawal appeared
unlikely to over-tension
the cable,
no written precautions
existed
to limit the number of individuals pulling on the cable,
or to
prevent pulling in sudden,
forceful jerks to dislodge the-stuck
cable.
The inspector noted that breaking the cable at
a point
inaccessible
from the seal table could have resulted
in
significant engineering
challenges,
work delays,
and potentially
incurrence of considerable
radiation exposure.
b.
By using the hand-over-hand
method,
the ICI might easily have
been
dropped.
This could have resulted in rapid insertion of the ICI
into the core, or in possible
personal
injury to the individuals
at the seal table.
The inspector could find no evidence that
these or other hazards
had
been considered,
and .noted that the
absence
of a procedure
covering the methods
used left the workers
vulnerable to potentially unanalyzed,
unanticipated
contingencies.
, In response
to the inspector's
questions,
the licensee initiated
CRDR
1-2-0084 to assess
the appropriateness
of using
a method of ICI
withdrawal not covered
by the procedure.
During
a later discussion,
the
inspector
asked the Unit I Plant Manager what basic criteria supervisors
were expected to use
when determining whether departure
from a procedure
occasioned
a new, specific work instruction.
The Unit
1 Plant Manager
stated that management clearly expected all significant tasks carried
out on plant equipment to be performed according to a procedure.
The inspector concluded that the licensee's
failure to implement the
requi'rements of Procedure
36MT-9RI06 when withdrawing ICI Cable
855
constituted
a violation of Technical .Specification 6.8.1 (Violation
528/92-05-01).
One violation of NRC requirements
was identified.
ant
otectio
S stem
Set oint
correct
U 't
9
00
a
d
~)~70~1
On February 4,
1992, at 5:53
1 Assistant Shift
Supervisor
observed that
a computer printout on the
"demand typer" in
the Control
Room showed that the Plant Protection
System
(PPS)
channel
"B" number
(SG) low pressure
setpoint, for reactor
trip and main steam isolation actuation,
was lower than allowed by
technical specifications
following partial performance of the
surveillance test
(ST) 36ST-9SB02,
"PPS Bistable Trip Units Functional
Test."
The setpoint
was approximately
870 pounds per square
inch
absolute
(psia), while the technical specification
minimum allowed value
is 912 psia.
The channel
had previously been declared
operable at 4:27
PH,
and subsequently
Condition Report/Disposition
Request
(CRDR)
1-2-0045
was initiated to assess
the need for corrective actions.
The licensee
determined that the
ISC technician
had incorrectly
performed
a step. in the
ST when
he checked the restoration of the number
I SG setpnint instead of the number
2
SG setpoint
as specified in step
8.11.6.2 of the procedure.
This error was of particular concern
because
it resulted in a reactor trip setpoint
and
a main steam isolation
actuation setpoint
being nonconservative
with respect to the safety
analysis.
The
ST procedure
did not direct an independent verification of this
setpoint.
While licensee
procedures
do not require independent
verification of setpoints,
the licensee is considering placing
independent verification steps for these setpoints
in 36ST-9SB02.
This
evaluation is being documented
in CRDR 1-2-0045.
The inspector will
review the licensee's
evaluation
upon completion.
Corrective actions
completed include returning the setpoint to its
proper value
and completing the
ST performance
and administering
discipline for the
I&C technician.
Other corrective actions
were
recommended
by the licensee's
CRDR evaluator
and are being considered
for implementation.
These
include revisions to ST procedure
to have detailed action steps
required to determine the number
2
SG low
pressure
setpoint value
and
how to adjust it if necessary,
and to
include independent verification of as-left values of variable
setpoints.
Additionally, the licensee
determined that the reactor operator
who
performed the hourly setpoint verification at 5:00
PH,
as required
by
"Control
Room Data Sheet Instructions,"
and
a by Unit
1
Night Order dated January
24,
1992, failed to notice that the setpoin't
was low.
This error was regarded
by the inspector
as particularly
significant because
of the weak performance of a licensed operator in
assessing
the value of -a
PPS setpoint.
The inspector
noted that the
diligence of the Assistant Shift Supervisor in identifying the condition
was in contrast to the performance of the Reactor Operator
who
apparently did not accurately
read the control board indication or
utilize the readily available computer printout to confirm the
indication.
The licensee
administered discipline to the reactor
operator
and revised the Control
Room Data Sheet Instructions to require
the operators to use the computer printout to determine the setpoint
value
and to take appropriate
action if the setpoint is less than
913
psia.
The error made
by the
IEC technician in restoring the channel
from the surveillance,
and the error made
by the Reactor Operator
when
checking the setpoint,
were individually not highly safety significant,
however considered collectively, this event represents
concurrent
failures to ensure that
a reactor trip setpoint
was correct, therefore
the two errors
are being cited
as
a single violation (Violation 528/92-
05-02).
One violation of'NRC requirements
was identified.
ssential
S ra
Pond
Pum
reaker Failed To Close
On Demand - Unit
~6703
On February
14,
1992, the "A" train
pump breaker failed to close
when the operator attempted to start the
pump from the control
room.
An
inspection of the breaker revealed that the closing springs
were not
charged,
and the
750G instantaneous
ground relay was flagged.
However,
the
786 lockout relay was not flagged, indicating that
a ground fault
was not present.
The Shift Supervisor directed electricians to
troubleshoot
the breaker.
The inspector
observed
a portion of the
troubleshooting
which involved removing the breaker
from the cabinet,
moving it to
a test fixture in the switchgear
room, testing the breaker;
and returning the breaker to the cabinet.
The inspector noted that this
troubleshooting
was performed without invoking any of the work control
process
and was not done according to any procedure or work document.-
)OR 92-0038
was written to evaluate
whether these activities should
have
been performed under the Work Control
Program.
The Root Cause of
Failure
(RCF) Condition Report/Disposition
Request
(CRDR) concluded that
the apparent
cause of the failure was dirty stabs
on the auxiliary
contact block, although this root cause
could not be confirmed.
Licensee
management
determined that
a more definitive,RCF evaluation
was
not warranted
due to the inability to further examine the breaker in its
failed state.
The inspector
noted that the
CRDR program provides for
non-confirmed
"apparent"
RCF analyses
to be trended for further
.-
evaluation.
The inspector determined that
some
RCF data
was lost as
-10-
soon
as the breaker
was racked
down and tested.
The electricians
performing this troubleshooting did not identify dirt on contact
stabs
which could be removed
and examined,
nor did they identify high contact
resistance.
The inspector
noted that the
CRDR evaluation did not
ascertain
the failure history of this class of breaker
on site, did not
ascertain
the recent racking and operating history of this breaker,
and
did not identify the loss of RCF data during troubleshooting.
Subsequent
discussions -with the System Engineer determined that of the
five known General Electric Hagneblast
breaker failures at Palo Verde,
the root cause
was not confirmed in three of the events.
The inspector
= further noted that while the maintenance
program for Magneblast.breakers
has
been significantly improved since
1990,
two of these failures
occurred since the program was improved.
The licensee
committed to
promulgating
an equipment list to each unit which identifies specific
equipment that would require early engineering
involvement in
troubleshooting to preserve
and examine conditions which might assist
in
. RCF analysis.
The inspector will review the licensee's
actions
and
evaluation of (DR 92-0038
upon completion
(Followup Item 529/92-05-04).
No violations of NRC requirements
or deviations
were identified.
er enc
iesel
Generator
n ineered Safet
Features
Walkdown
U it 2
7 710
The inspector
reviewed this program area
by performing detailed
walkdowns of the Unit 2 emergency diesel
generator
(EDG) equipment
rooms
and systems,
by verification of selected
subsystem
lineups
and
configurations with plant drawings,
by evaluation of annunciator
and
control panel status,
and by review of operator
logs.
Selected
walkdowns were also performed of the Unit 3
EDG systems for comparison.
The inspector
noted the following items:
'a ~
b.
Several air-to-oil booster relays,
used to provide remote
indication at the local control panel,
were continuously cycling.
The inspector
asked the system engineer whether frequent cycling
of the relays might not affect relay diaphragm performance
or
shorten
diaphragm life.
The system engineer
acknowledged that
continuous cycling did not reflect optimum relay performance,
but
stated that this condition posed
no significant safety risk, since
the relays performed
no control function,
and any significant
reduction in relay performance
would be effectively detected
during regular operator
rounds.
Duct tape
had
been placed beside the sightglass for the jacket
water cooling surge tank, with periodic handwritten markings to
indicate
a sightglass
level of 50 percent,
75 percent,
and
so
forth.
The inspector noted that auxiliary operators
logged
sightglass
level twice per shift,
and used these
informal markings
as
a measurement
aid.
In response
to the inspector's
questions,
the system engineer
stated that this apparent
lack of an effective
sightglass
level marker
had
been
noted
on December
10,
1991,
and
that CRDR,1-1-0170
had
been initiated to resolve the concern.
The
-11-
system engineer stated that
a more effective,
permanent
sightglass
level marker
was being designed for installation
on the tank.
The inspector concluded that none of the observations
made affected Unit
2
EDG operability,
and that the
EDG appeared fully capable of performing
its safety functions in all observed
respects.
No violations of NRC requirements
or deviations
were identified.
Sta t
stin
Units
d 3
700
The inspector
reviewed the data from core physics tests
associated
with
the Unit 2 Cycle 4 refueling and the Unit 3 Cycle
3 refueling to verify
that the results
met acceptance
criteria and that all deficiencies
were
resolved in a timely manner.
Specifically, the data from the following
procedures
were. reviewed
~Unit
72TI-,9RI01,
Unit 3
"Core Reloading"
,
"Excore Linear Subchannel
Gain Adjustments"
"CPC/COLSS Input Intercomparison"
"Reload
Power Ascension Test"
"Reload Criticality and
Low Power Physics Testing"
"Reactivity Computer Checkout"
"Fixed Incore Detector Data Collection"
"Determination of Anticipated Critical Position"
"Power Calibration" (Reviewed
1 of 4 performances)
"Excore Linear Subchannel
Gain Adjustments"
"Secondary Calorimetric Power Yerification"
"CPC/COLSS Input Intercomparison"
"Reload
Power Ascension Test"
"Reload Criticality and
Low Power Physics Testing"
72PY-9RX31, "Reactivity Computer Checkout"
72TI-9RI01, "Fixed Incore Detector Data Collection"
72TI-9RX02, "Spent
Fuel Inspection"
These procedures
document the calibration of nuclear instrumentation,
the determination of isothermal
and moderator temperature
coefficients,
the determination of group and total control rod worth, the
determination of shutdown margin, the evaluation of core thermal
power,
the calculation of inverse
boron worth', the determination of Core
Operating Limits Supervisory
System
(COLSS)
and Core Protection
Calculator addressable
constant
values,
and the verification of the
secondary calorimetric calculation in COLSS.
The inspector
noted that the peaking factor values
(predicted,
actual,
minimum,
and maximum) for Unit 3 were incorrectly recorded in Appendix A
of 72PA-9ZZ07.
The data form had preprinted
a factor of "x 10 ," but
-12-
the test performer inadvertently duplicated this factor when the data
were transposed
from other sections of the procedure,
such that the
values recorded in Appendix A appeared
with a net factor of "x 10 '
10 '."
The correct values
were within the correct acceptance
criteria,
and the inspector concluded that this was
an administrative oversight.
The licensee
acknowledged
the inspector's
observation.
The inspector
determined that 72PA-9ZZ07 had
been revised 'to eliminate the preprinted
factor before this error was identified.
The inspector found that all the acceptance criteria were met and that
other discrepancies
and questions identified during the performance of
the procedures
were clearly identified and promptly resolved.
No violations of NRC requirements
or deviations
were identified.
uxiliar
um
Plant
Com uter
PC
Alarms - Un ts
2 and
~37 l~0
On February
25,
1992, the inspector noted that several
PC points were in .
alarm on a group display for AFW pump bearing temperatures
in Units 2
and 3.
The inspector determined that the temperatures
were normal
however the computer alarm points were always in alarm and appeared
to
be in alarm at all temperatures
below 190 degrees
F and
above
200
degrees
F.
The inspector
reviewed control
room deficiency logs
and
noted that this problem was not logged.
The inspector further
determined that Engineering
Evaluation Request
(EER) 87-AF-48, initiated
in November
1986
and completed in October
1988, contained
an
identification of this problem
and resolution.
The resolution
was to
reset the alarm setpoi'nts to those specified in the
EER and referenced
a
Plant
Change
Request
(PCR) written to effect this change.
The licensee
was unable to find any work document written to carry out this intended
resolution.
.The inspector concluded that this deficiency
had not been
tracked for corrective action.
The licensee initiated Condition
Report/Disposition
Request
(CRDR) 9-2-0171 to ensure corrective action
is taken
and to assess
the need for further review of plant computer
alarm setpoint discrepancies.
The inspector will review the licensee's
CRDR evaluation
when completed
(-Inspector Followup Item 529/92-05-05).
No violations of NRC requirements
or deviations
were identified.
Reactor
Power Cutback
RPCB
- Unit 3
93702
On February
5,
1992, at 5:27
PH (NST), while the unit was 'operating at
100 percent
power,
a
RPCB to approximately
60 percent
was experienced
due to the loss of the "B" main feedwater
pump.
The feedwater
pump was
manually tripped by the operators
because
of low feedwater
pump suction
pressure
after the "A" condensate
pump tripped.
The condensate
pump
tripped because
.a circuit card for the condensate
pump flow transmitter
failed.
The inspector
responded
to the control
room and confirmed that the plant
was stable.
The inspector noted that the operators'rompt
action to
- 13-
trip the main feedwater
pump was in accordance
with licensee
procedures.
The inspector concluded that licensee's
actions
were. appropriate.
No violations of NRC requirements
or deviations
were identified.
o e 0
mit
erv'so
ste
C
Soft
't'o
leme t t on
U t 3
92 00
On February 5-6,
1992, while Unit 3 was at approximately
60X power
following a reactor
power cutback
(see paragraph
12), several
failures occurred
as
a result of a
COLSS software modification
implemented following the power reduction.
The modification had been
intentionally implemented while at reduced
power to preclude
power
reductions
which potential
COLSS failures
may require.
However,
as the
same software
had
been successfully
implemented in Unit 2,
no problems
were expected
during the Unit 3 implementation.
The operators
considered
COLSS to be in service .following the
implementation,
and
made appropriate entries in the Unit Log following
each failure.
No other operational
impact of the failures was observed.
As a result of the unexplained failures, Condition Report/Disposition
Request
(CRDR) 3-2-0046
and guality Deficiency Report
((DR) 91-0034 were
initiated.
The
CRDR evaluation determined that the failures occurred
because
insufficient memory was available in the computer for a function
involving the "data-logger" routine, which is accessed
hourly by 'COLSS
-as
a result of the modification.
The memory was unavailable
as the
result of a unrelated
December
1991 software modification following
which the memory had inadvertently not been restored for use
by other
programs.
While the
COLSS softwar'e modification was tested
in the
computer lab, the post-implementation
testing did not address
the memory
requirements
or the potential for the unexpected
interaction with the
previous unrelated modification.
The inspector
concluded that this modification implementation
problem
represents
another
example of ineffective control over modifications to
plant computers
and COLSS-related
software.
'Inspector Followup Item
529/90-28-02 is currently open to address
software configuration
controls following other COLSS-related errors.
COLSS errors
are
potentially safety-significant
because
COLSS determines
the Technical
Specification operating
power limit for the plant and because
COLSS is
used to calibrate safety-related
excore nuclear instrumentation.
The
inspector noted that the licensee currently considers
as "not
quality related."
The inspector will review the licensee's
actions in
this area
under the above followup item.
No violations of NRC requirements
or deviations
were identified.
-14-
'
14.
t
ss ra c
nd A dit Pro ram Review -
U its
2
and
3
35701
nd
0702
The licensee
had previously proposed to implement
a new Oper ations
Quality Assurance
Plan
(OQAP).
The new-plan
was found by NRC Region
V
to describe
a
QA program that,
when implemented properly, will meet the
requirements of Appendix 8 to 10
CFR Part
50 and is therefore
acceptable.
This conclusion
was concurred with by the
NRC Office of
Nuclear Reactor Regulation
and was transmitted to the licensee
by letter
dated January
30,
1992.
The licensee
expects to implement the
OQAP on
April 29,
1992.
The most significant organizational
change in the
QA organization during
the past year was the selection of a new
QA Director in November
1991.
The inspector
reviewed the Director's qualifications against the Palo
Verde
UFSAR section
17.2. 1.1.5.
The experience
and qualifications were
found to meet or exceed
the minimum requirements
specified.
However,
the inspector noted the licensee
had no documentation
to support that
the Director or other
QA manager qualifications
had been
reviewed
against
UFSAR requirements.
The licensee
acknowledged this comment
and
agreed to consider documenting this review as part of their selection
process.
The inspector
reviewed several
1991
QA audits in the areas of refueling
operations
(Audit 91-06), corrective action (Audit 91-08),
maintenance
and inspection
(Audit 91-12),
and operations/technical
specifications
(Audit 91-16).
The audit scope
and purpose
are documented
in each
report,
and the executive
summary provides
a meaningful
overview of
audit findings.
The report format also includes
a section of results
relative to management
expectations
given to the audit team at the
beginning of the audit by senior
and mid-level management
in the audited
organization.
The inspector considered that answering
these
management
questions
enhanced
the audit results
because
several
important issues
were identified as
a result.
This included the fact that over fifty
percent of questionnaire
survey respondents
during audit 91-08 had
received,
but had not been personally briefed by their supervision or
management,
on the Executive Vice President's
1991 letter on Standards
and Expectations.
The inspector reviewed the audits for indications of
degraded
independence
due to the influence of these
management
questions
on the audit and concluded that audit results
remained
independent
and
appropriate
in scope
and depth.
The inspector
reviewed the
1991
and
1992 audit schedule
and concluded that technical specification
requirements
for audit periodicity were being met.
With respect to the audit findings in the maintenance
and refueling
operations
areas
which preceded
the Unit 3 loss of power event
due to
crane operation
and the Unit 2 core alteration without an
SRO present,
for which escalated
enforcement
was issued in January
1992, the
inspector
concluded the following:
a.
Audit findings appeared
in general
to be performance
based
and
focused
in areas of relative importance.
The findings of
-15-
~
~
0
b.
deficiencies
in areas
such
as
SRO control of refueling activities
and maintenance
performed without procedures
or instructions
indicate that the audit teams
are properly sensitive to the type
of potentially significant performance
problems that
became
apparent
during the above noted events.
The maintenance
audit was
noted to be particularly performance
based.
In the case of findings noted in (a), the
gA audits did not
identify programmatic
issues
related to these deficiencies
which
contributed to the events in Units 2 and 3.
For example the
refueling operations
audit noted weak procedural
control of SRO
responsibilities
and the maintenance
audit noted technicians
working beyond their work order.
Both areas of weakness
were
identified in NRC findings related to the escalated
enforcement
issues.
The inspector concluded that
gA audits found indications
of weakness
in these
areas,
but did not develop programmatic
issues.
c ~
Line management
response
to the audit findings appeared
to be weak
in that these specific deficiencies,
although not presented
as
programmatic
problems,
were not dealt with as indicators of
potentially significant weakness.
Thus, similar deficiencies of
maintenance
practices
and refueling procedures
became
apparent
during
NRC review, of the above noted events.
The inspector further noted that in audits
91-08
and 91-12,
gA
identified that line management
response
to previously identified
programmatic
problems
was not effective.
In one case,
the previous
issue
had
been closed
by gA based
on line management
commitments to
complete
documenting regulatory commitments within procedures
(Corrective Action Report 89-12), which was then not completed.
The
other case
involved lack of preventive maintenance
tasks for warehouse
stored
items (Corrective Action Report 90-01).
This issue
had
been
closed
by gA based
on the promulgation of procedure
requirements
and
required tasks for applicable stored items.
However,
gA subsequently
found numerous
examples of improper program implementation.
The
inspector concluded that line management
response
to gA findings was not
always effective and that
gA appropriately identified these
examples.
Overall the inspector concluded that within the areas
reviewed,
the
gA
program meets regulatory requirements
and that audits
are appropriately
stressing
issues of importance.
The inspector
encouraged
the licensee
to improve auditing effectiveness
at identifying programmatic
weakness,
and for line management
to more carefully examine
gA audit findings of
deficiencies for underlying weaknesses,
to encourage line supervision
and 'management
to increase their attention to such findings in their
area of responsibility,
and
when programmatic
weakness
is identified to
ensure it is resolved without reliance
on further gA auditing.
The licensee
acknowledged
the inspectors
observations,
stressing their
commitment to use
gA findings as
a means of effecting improvement.
In
addition, senior licensee
management
stressed
'that the use of other
I
-16-
indicators,
such
as the Condition Report/Disposition
Request
(CRDR)
program,
were used to inform management
of adverse
trends
which could
signal underlying weaknesses.
The inspector
encouraged
the use of such
programs
as potentially valuable line management
tools, which could
complement
gA program efforts.
No violations or deviations
from NRC requirements
were identified.
15.
ollowu
on
rev ous
de t
ied
tems
92701
and 92702
a.
UUQ~
(1)
C osed
'at
o
5
90-36-0
.
" 'ed
0 erator
ed'cal
cords" -
t
The following three procedures
were implemented
by the licensee
to
manage the licensed operator medical records,
medical
examinations,
and requalification program requirements
for license
renewal.
01PROLC01
-, "Operator Medical
Program"
15ACOLC01 - "Obtaining, Updgrading,
and Maintaining Operator
Licenses"
01DPOLC01 - "Operator Medical Examinations"
The inspector
examined
these
procedures
to determine that the
licensee's
corrective actions
were implemented.
The procedures
addressed
all of the identified concerns
from the Notice of
Violation.
The concerns
included ensuring that the medical
examinations
met the applicable standard.
Further,
the operators
would be examined every two years
as required for maintaining
licensed status.
This'item is closed.
b.
Unit 2
(1)
Closed
Foll owu
Item
529 91-29-03:
"Main Steam Isolation
give
Inadvertent Closure" - Unit 2
92701
This item involved an inadvertent closure of MSIV 181 while the
unit was at
100 percent
power.
This item was left open
because
Engineering Evaluation
Request
(EER) 90-SG-221,
which was written
following a previous similar event,
recommended
that the solenoid
which failed during the earlier event
be replaced
every other
refueling outage
and yet the licensee's
work control database
still showed
a replacement
interval of 93 months.
Since this
event,
administrative control procedure
"Engineering
Evaluation Request,"
has
been revised.
Step 3. 1.7 now requires
that
a Condition Report/Disposition
Request
(CRDR) be initiated to
track
EER disposition actions.
In addition, the inspector
was
informed that
EER 90-SG-221
had
been provided to the Preventive
- 17-
'L
(2)
Haintenance
(PH) Task Force
and this
PM task will be revised to
incorporate
EER 90-SG-221
recommendations
when the
SG system
PHs
are reviewed.
The, inspector concluded that the above actions
appeared
appropriate.
This item is closed.
.
C osed
V olatio
5 9 9 -40-01
" ot
a
c
t
e ic e c'es"
Unit
92 0
This violation addresses
two examples of hot particle control
deficiencies
observed
by inspectors
during the Unit 2 refueling
outage.
(a)
One example involved personnel
who crossed
a Hot Particle
Control Area
(HPCA) going to and from the refueling bridge,
which was
a contaminated
area but not an
HPCA.
Mhen
returning from the refueling bridge, the.personnel
were not
wearing the additional set of rubber gloves specified in the
Radiation
Exposure
Permit
(REP) pre-job briefing.
The
licensee
determined that this occurred
because
of a lack of
understanding
of the special
requirements for this
REP by
the roving Radiation Protection
(RP) technician in
containment
who supported this job,
and due to the personnel
involved not recognizing that they needed
enough gloves for
two transits through the
HPCA.
The licensee's
corrective actions
included reviewing the job
to confirm the appropriateness
of the
REP pre-job briefing
requirements,
briefing the personnel
involved,
and posting
a
copy of the pre-job briefing at the
HPCA entrance
so that
, all
RP technicians
would be aware of the specific provisions
made for this job.
(b)
The second
example involved the failure of RP technicians
to
monitor workers inside
an
HPCA for hot particles at least
every 30 minutes
as required
by the
REP.
Upon
identification of this condition, the workers were monitored
and
no hot particles
were found.
The licensee
counseled
the
RP technicians
involved and reviewed the monitoring
requirements
with other
RP technicians
in Unit 2.
The
Radiological Controls
Problem Report describing the incident
was forwarded to the
RP managers
in Units
1 and 3.
The inspector
reviewed the licensee's
corrective
actions
and
considered
them adequate.
Further inspections
during the Unit 2
refueling outage did not identify additional hot particle control
problems.
Based
on the above, this it'em is closed.
(3)
Closed
Followu
Item
529 91-04-02
"Test
Gas Concentration
ccurac
" Unit 2
92701
This item is addressed
in paragraph
4 of this report.
18 -'
c ~
gnit 3
ol
ow
t
m
30
9 -35-0
" oca
e Test
This item address
the determination of the Root Cause of Failure
(RCF) of the October 7,
1991,
LLRT of 42-inch diameter
Containment
Purge
(CP) valve CPA-UV-2A in Unit 3.
The test pressure
was not
able to be achieved or maintained in this valve,
even though it
had not been manipulated
since its previous
LLRT.
The inspector reviewed Condition Report/Disposition
Request
(CRDR)
3-1-0141,
which documents
the licensee's
evaluation
and
determination.
The licensee
determined that there
have
been eight
previous
LLRT failures of 42-inch
CP valves installed in the three
units.
Plant
Change
Request
(PCR) 91-13-001
had
been generated
to enable installation of a blind flange
on the discharge of each
on the basis of these failures, but had not been
implemented.
As a result of this failure and one subsequent
failure, the
PCR has
been
approved
and the design is scheduled
to
be complete
by May 15,
1992.
Installation has not yet been
scheduled.
The licensee
determined that seven
hand-wheel
turns
(HWT) of the
manual. operator
were required before disk motion was observed
in
this valve,
and the closing limit switch in the motor operator
was
set at seven
HWT from closed to allow for the valve to coast
closed after limit switch actuation.
The licensee
noted that the
lack of a visual inspection prior to valve manipulation
eliminated'aluable
"as-found" information.
(2)
The licensee determined that the failures most likely occur
because
the disk slips off the tapered
seat if the disk is not
squarely centered
on the seating
surface.
As
a corrective action, the
CRDR recommends that, until the
PCR is
implemented,
a visual inspection of the valve disk position
on the
seat
be performed following valve cycling to ensure it is square
on the valve seat.
This action is being tracked
by the licensee.
The inspector concluded that the licensee
was slow to recognize
and take corrective action =for the many
LLRT failures of the 42-
inch
CP valves,
but that the current corrective actions
appear to
be appropriate.
Based
on the above review and the licensee's
planned actions, this item is closed.
Closed
V'olation
530 91-40-02
"Reactor Startu
Procedure
Not
Followed" - Unit 3
92702
This violation occurred
when Unit 3 operators
withdrew Control
Element Assemblies
(CEAs) in a manner that violated procedure
-19-
"Reactor Startup."
This condition was identified by
the inspector at the time of the event.
Upon identification of the incorrect action, the licensee
reinserted
the
CEAs to the
ECRP 500 pcm.position
and performed
the required evaluations,
which revealed
no unexpected
or unsafe
conditions.
The control
room personnel
reviewed the procedure
and
determined that the intent of the procedure
was to stop
withdrawal at the
ECRP
500 pcm position.
The Assistant Shift
Supervisor directing the startup
was counseled.
Subsequently,
the
reactor startup procedures for all,three units were revised to
more clearly delineate
the required actions.
The inspector
reviewed the procedure revisions.
The procedure
in
effect at the time of the event
was clear to the inspector, =but
'the enhanced clarity of the revised procedure. appears
to reduce
the possibility of misinterpretation
or misunderstanding.
This item is closed
based
on the above review.
0 en
Followu
Item
530 91-50-02
Low
ressure
eactor Tri
Set o'nt Shift" - Unit 3
9 701
This item addresses
a condition observed
several
times in Unit 3,
and
now in Unit 2, in which the steam generator
(SG) low pressure
reactor trip (and main steam isolation actuation)
setpoints
in the
Plant Protection
System
(PPS)
have shifted without explanation to
a value below the Technical Specification
minimum allowed value of
912 pounds per square
inch absolute
(psia).
In each
case,
the
shift was to approximately
200 pounds
per square
inch (psi) below
the steam generator
pressure
at the estimated
time of the shift,
consistent with the function of the setpoint
manual
reset
pushbutton.
Only one channel
has
been
observed to shift at
a
time.
The protection
system is required,to
have
3 to 4 channels
therefore the occurrences
have not resulted .in an unsafe
condition.
The history of this issue
was outlined in inspection report 50-
528/91-50.
Additional information reviewed since that report is
provided below:
On July 20,
1990, in Unit 1, during restoration
from the
partial
performance of a monthly surveillance test
(ST)
(test
PPS channel for one
SG only), technicians
noted that
the setpoint for the second
SG does not get reset.
The
licensee
reset the setpoint
and discussed
the condition with
the vendor.
The monthly ST was revised
and
a change to the
control
room daily midnight surveillance
was submitted to
verify the setpoints
during the daily channel
checks.
-20-
k
.4
On November 8,
1991, the
PPS channel
"B" as-found pretrip
setpoints for both
SGs were found low in Unit 3 during
monthly surveillance testing.
=The trip setpoints
were
unaffected.
CRDR 3-1-0197
was initiated.
A failed diode
was found in the setpoint circuit, and the circuit was
repaired
and retested.
On February 4,
1992, at 5:53
PH (HST), the Unit
1 Assistant
Shift Supervisor
found the
PPS channel
"B" number
2
setpoint low following partial performance of surveillance
procedure
"PPS Bistable Trip Units Functional
Test," due to the failure to correctly perform a procedural
step.
This event is further discussed
in Paragraph
7 of
this inspection rep'ort.
On February
5,
1992, Unit 2 operators
found the
PPS channel
"B" setpoints
low for both
SGs during the hourly
verification.
At the time,
PHS monitoring had
been
installed in Units
1 and 3, but only in channels
"A" and
"D"
in Unit 2,
so the exact event time was not able to be
determined.
A CRDR was initiated for trending.
The
licensee
completed the
PHS monitoring implementation.
Troubleshooting -of the
PPS did not identify any problems.
Licensee
management
asked the vendor for further analysis of
the condition.
On February 8,
1992,
both SG=-setpoints for PPS channel
"B"
in Unit 2 were detected
low by the
PHS.
A CRDR was
initiated for trending.
The channel
was left in bypass
and
a recorder
was connected to the channel
to monitor the
setpoint
more precisely.
On February 9,
1992,
both
"B"
in Unit 2 were detected
low by the
PHS.
The recorder did
not capture the event
because it had tripped
on signal noise
before the event occurred;
A CRDR was initiated
for'rending.
The channel
was left in bypass.
The security
access
logs for the remote
shutdown
panel
area
were reviewed
for both this event
and the February
8 event,
and the
licensee
determined that there
was
no basis for further
consideration of any individual intentionally or
accidentally resetting the setpoints
from the remote
shutdown panel.
The licensee
looked unsuccessfully for
potential electromagnetic
or radio frequency interference
(EHI/RFI) sources
around the event time,
and confirmed that
the process
instrumentation
cable shield were grounded
as
designed.
The licensee
determined that the identically designed
pressurizer
low pressure
reset circuit would not show
a setpoint shift if
reset at normally operating pressure,
since the reset
changes
the
setpoint to 400 psi below the current pressurizer
pressure
-21-
,r
(normally 2250 psia),
but the maximum setpoint possible is 1837
psia.
Therefore, if that circuit is vulnerable to the
same type
of problem, the setpoint would remain unchanged
and the problem is
not being observed.
The licensee
does not believe that grounds
are causing the
problem, since grounds
are only known to have occurred nearly
coincident with one of the unexplained
events.
Grounds less
than
the alarm threshold
have not been considered.
The licensee
has discounted
the possibility of EHI/RFI as
a cause
on the basis of its evaluation of the circuit and the statements
of people in the area of the instrumentation
at the time of the
most recent
two events.
In reviewing the Night Order and Control
Room Data Sheet
directing'ourly
verification of the setpoint,
the inspector noted that the
-acceptance
criteria is vague.
The operators
are instructed to
check setpoints
hourly on Control
Board
B05 at "approximately
919
psia" for Modes
1 and 2.
The licensee modified the hourly
verification acceptance criteria to use the alarm typer printout,
which is
a digital representation
of the setpoint.
This item will remain
open pending completion of the licensee's
evaluation of these setpoint
changes.
Units
2
and
3
Closed
Violation
528 529 530 91-4 -0
"Fa'lu
e to
ollow
rocedures"
Units
2
and
9 70
This item involved three examples of failure to follow procedures.
The first two examples
involved the failure of licensed operators
to verify that no trip inputs were present
when the
BOP-ESFAS
channel
was removed from bypass resulting in a Control
Room
Essential
Filtration Actuation Signal
(CREFAS).
The operators
responsible for the first two events
were temporarily removed
from
shift and disciplined.'n addition,
a letter written discussing
the first event,
was sent to all licensed
personnel
in Unit 3 and
to supervisory
and management
personnel
in Units
1 and 2.
Shift
Supervisors
in Units
1 and
2 discussed this event with their
operating
crews.
The inspector reviewed Licensee
Event Reports
530/91-009-00
and 528/91-012-00,
which were written as
a result of
the first two events
and
had
no further questions.
Following the
second
event the licensee verified that the operator
involved was
aware of the first event
and the Vice President of Nuclear
Production discussed
the second
event with the involved operators.
The third example involved
a licensed operator allowing the
(RCS) level to 'rise enough to overflow the
reactor vessel
The operator
involved was disciplined,
the
on-shift crew was briefed
on the evolution
and the consequences
of
-22-
C
y
~ ~
C
not maintaining constant vigilance of RCS level.
Subsequent
operating
crews were directed to assign
a dedicated control
room
operator to maintain the required
RCS level until normal automatic.
level control
was restored.
As a result of these
and other personnel
errors,
APS has
instituted additional
management
oversight of operations with
particular emphasis
on coamunications,
command
and control,
and
adherence
to procedures.
In addition,
a special
evaluation of
personnel
performance
issues is being conducted to better
understand
the root causes.
The inspector
has observed
this'dditional
management
presence
in the field and has determined
that this has provided management
with more information regarding
practices
in the field and
a better understanding
by personnel
in
the field of management
expectations.
The inspector will continue
to evaluate
personnel
performance with particular emphasis
on the
use of procedures.
The inspector concluded that the above actions
appeared
appropriate.
This item is closed.
No violations of NRC
requirements
or deviations
were identified.
16.
~Ei
Exit meeting
was held on March 5,
1992, 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.
-23-