ML17305B039
| ML17305B039 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 08/23/1990 |
| From: | Wong H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17305B038 | List: |
| References | |
| 50-528-90-23, 50-529-90-23, 50-530-90-23, NUDOCS 9009140160 | |
| Download: ML17305B039 (57) | |
See also: IR 05000528/1990023
Text
Re ort Nos.:
Docket Nos.:
License
Nos.:
Licensee:
Facilit
Name:
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION
V'0-528/90-23,50-529/90-23
and 50-530/90-23
50-528,
50-529,
50-530
Arizona Public Service
Company
P.
0.
Box 52034
Phoenix,
AZ. 85072-2034
Palo Verde Nuclear Generating Station Units
1, 263
Ins ection Conducted:
May 27 through July 14,
1990
Ins ectors:
A
roved
B
D.
Coe,
F. Ringwald,
J.
Sloan,
P. Narbut,
Senior Resident
Inspector
Resident
Inspector
Resident
Inspector
S nior Resident
Inspector (Diablo Canyon)
p gz/ea
~
ong,
a
e
cygne
Reactor Projects
Branch,Section II
Ins ection
Summar
Ins ection
on
Ma
27 throu
h Jul
14
1990
(Re ort- Numbers 50-528/
an
Areas Ins ected:
Routine, ons'ite, regular
and backshift inspection
by
e
ree ress
ent inspectors,
and an inspector
from the Region
V staff.
Areas inspected
included: previously identified items; review of plant
activities; engineered
safety feature
system walkdowns; monthly
surveillance testing;
monthly plant maintenance;
worker in a high
radiation area
(HRA) without proper dosimetry - Unit 1; plant startup
from refueling - Unit 1; confirmatory action letter followup - Unit 1;
over-dilution, excessive
power rate increase
- Unit 1; main steam
isolation due to restoring the steam
bypass
control
system with a large
demand - Unit 1; inoperable
safety injection tanks - Unit 1;
installation/testing of modifications - Unit 2; control
room controlled
document discrepancies
- Unit 2; pressurizer
heater
replacement
- Unit 2;
pump breaker trip - Unit 2; missed reactor coolant system
boron sample - Unit 2; reactor coolant system
reactor
(Rx) power cutback - Unit 3; cracked reactor trip breaker arc
chutes - Unit 3;
OSHA concern:
non-ionizing radiation - Units 1,
2 and
3; review of licensee
event reports,
Units 1,
2 and 3; and review of
periodic and special
reports - Units 1,
2 and 3.
-2-
During this inspection
the following Inspection
Procedures
were utilized:
30702,
30703,
37838,
61705,
61707,
61708,
61726,
62703,
71707,
71710,
71711,
72700,
72700,
92700,
92701,
92702,
92703,
93001,
and 93702.
Results:
Of the
23 areas
inspected,
2 violations were identified and are
besng csted.
The violations involve:
(1) the failure of a mechanic
foreman to comply with the applicable
Radiation
Exposure
Permit when
a
High Radiation Area was entered without the required alarming dosimeter,
and (2) the failure of an Auxiliary Operator to follow procedures
for the
manual
operation of an Atmospheric
Dump Valve.
Three non-cited violations involved:
(1) the inadvertant
powering of
Safety Injection Tank vent valves,
(2) the
use of "Information Only"
copies of the Unit 2 Core Data Book, (3) a missed Technical
Specifications
surveillance
test
due to an inadequate test procedure.
General
Conclusions
and
S ecific Findin
s
Si nificant Safet
Matters:
None
Summar
of Violations:
Summar
of Deviations:
0 en Items
Summar
2 Cited Violations and
3 Non-Cited Violations
None
11 items closed,
2 items left open,
and
6 new items
opened.
DETAILS
Persons
Contacted:
The below listed technical
and supervisory personnel
were
among
those contacted:
Arizona Nuclear
ney,
- J. Bai 1 ey,
¹T. Bradish,
P. Caudill,
W.
Conway,
E. Dotson,
- R. Flood,
¹J.
Fogarty,
¹*R.
Fullmer,'S.
Gross,
- K. Hall,
D. Hein>cke,
- R. Henry,
"P.
Hughes,
- W. Ide,
- A. Johnson,
¹0, Kanitz,
¹*S. Kanter,
¹A. Khanpour,
- J. Levine,
"W. Marsh,
"J. Napier,
- G. Overbeck,
¹M. Radoccia,
- V. Rhodes,
"R.
Rouse,
J. Scott,
- J. Sills,
E.
Simpson,
- D. Stover,
¹M. Winsor,
Power Pro 'ect
(ANPP)
an
anager,
n)
3
Vice President,
Nuclear Safety
and Licensing
Compliance
Manager
Site Services Director
Executive Vice President - Nuclear
Director Site Engineering
and Construction
Assistant Plant Manager,
Unit 2
Operations
Outage
Manager,
Unit 2
equality Assurance
and Monitoring Manager
El Paso Electric Engineer
El Paso Electric Engineer
Plant Manager, Unit 2
Salt River Project, Site Representative
Radiation Protection/General
Manager
Plant Manager,
Unit 1
Compliance Supervisor
Compliance
Engineer
Participant Services,
Senior Coordinator
Site Nuclear Engineering Supervisor
Vice President,
Nuclear
Power Production
Plant Operations
and Maintenance Director
Compliance
Technical
Support Director
SME Nuclear Engineering
Manager
Document Control Supervisor
Compliance Supervisor
General
Manager of Site Chemistry
Rad.
Protect)on
Tech/Sycs.
Acting Manager
Vice-Pres.
Nuclear Engineering
8 Construction
Nuclear Safety Manager
System Engineering Supervisor
The inspectors
also talked with other licensee
and contractor
personnel
during the course of the inspection.
¹Attended the Exit meeting held with NRC Inspector
Paul
Narbut
on June
29,
1990.
"Attended the Exit meeting held with NRC Resident
Inspectors
on
July 19,
1990.
/
2.
Previousl
Identified Items - Units 1
2
and
3 (92701
and 92702)
Unit
(Closed)
Enforcement
Item (528/89-16-03):
"Ino erable
mos
eric
um
a ve
o.
-
n)
The remaining actions
committed to by Arizona Public Service
Company
(APS) are to upgrade
operating procedures
and train
operators.
The operator training schedule
was discussed
in
Inspection
Report 50-528/90-03
and appeared
appropriate.
The
operating procedure
upgrade
schedule
was considered
inappropriate
and
has
been revised
and documented
in APS
memo
294-000144-JWD
from J.
W. Dennis to T.
R. Bradish.
The
schedule for upgrading operating procedures
is:
o
September
3,
1990 - December
20,
1991, - upgrade
Abnormal
Operating procedures.
o
January
6,
1992 - January
2, 1996, - upgrade
Normal
Operating
Procedures.
The inspector considered that the specific. actions
associated
with the procedure
changes
and operator training .relative to
Atmospheric
Dump Valve (ADV) operation is complete
and complies
with the licensee's
associated
independent verification and
locked valve/breaker
procedures.
The licensee's
large scope,
long range
upgrade
proqram is an
initiative well beyond the scope of the original violation.
The inspector questioned
the adequacy of the timeliness of the
larqe
scope
procedure
review relative to ensuring
independent
verification requirements
are met and will followup under
Followup Item (528/90-23-04).
This item is closed.
b.
(0 en) Followu
Item (528/90-03-02):
"Load Shed Potential
rans
ormer
as
ure
-
ns
C.
This event resulted in two root cause of failure Engineering
Evaluation
Requests
(EER) to evaluate
the Potential
Transformer
(PT) failures.
EER 89-NA-049 wa's closed stating that the
failure evaluation will be documented in EER 90-NA-002.
General Electric is performing the root cause
evaluation
and
the estimated
completion date is October 30, 1990.
This item
will remain
open until
EER 90-NA-002 is complete
and evaluated
by the inspector.
(0 en) Followu
Item (528/90-03-03):
"Fuel Buildin
Rollu
oor
ama
e
en i
a son
am er
um er
ns
a
a son
nl
This event resulted in Engineerinq Evaluation
Request
(EER)
90-ZF-009
and Incident Investigat)on
Report (IIR) 3-1-90-008.
IIR 3-1-90-008 is complete
and includes
a
Human Performance
d.
Unit
a.
Evaluation
System report.
The inspector
reviewed IIR
3-. 1-90-008
and
had
no further questions.
EER 900-ZF-009 is to
evaluate
the physical
equipment
consequences
of this event
and
is not yet complete.
This item wi 11 remain open until
90-ZF-009 is complete
and evaluated
by the inspector.
(Closed)
Enforcement
Item (528/89-30-01):
"Ex ired Flam-
ma
e
tora
e
erm>ts
-
nit
This item involved three expired flammable storage
permits
which were found on flammable storage
lockers.
The revision to
Procedure
Control of Transient
Combustibles,
was
approved
on July 5, 1990,
and effective
on July 13,
1990.
The
inspector
reviewed this revision and concluded that it appeared
to be appropriate.
The inspector
was provided documentation to
substantiate
that Site Modification 13-SM-ZZ-001 has
been
funded
and would add several
permanent
storage
locations for
safe, combustible
storage in the plant.
The implementation of
instruction change
requests
in work planning
and work control
procedures
appears
to be consistent with 14AC-OEP03
and is
scheduled for inclusion in a major rewrite by August 1990.
The
equality Assurance
Monitoring program
has completed
approximately twenty monitoring reports
and is planning to
continue to monitor. this area for at least three
months
beyond
July 13, 1990, the effective date for the revision to
The inspector
concluded that all corrective action
is either complete or scheduled
to be complete
on an
appropriate
schedule.
This 'item is closed.
2:
(Closed)
Followu
Item (529/89-30-04):
"Control of
a)n enance
ec
naca
anua
s
-
ns
This item resulted
from the use of a superseded
technical
manual for maintenance
when the current manual
was available
and approved for use.
The licensee
concluded that personnel
had not followed existing procedures,
which require work
planners to confirm that only current approved technical
manuals
are
used in work documents.
However, the licensee
chose to strengthen this area
by incorporating this specific
requirement into procedures
Work Planning
and
30AC-9ZZOl, Work Control.
These
changes
are complete.
The
licensee
also identified and initiated corrective action
on
other vendor technical
manual
program deficiencies.-
These
include enhancing
page level control for manual revisions,
and
restricting the
use of manuals
which have not received
review
and
comments
by licensee staff.
This item is closed.
(Closed)
Unresolved
Item (529/89-30-05):
"Safet
In'ection
c ua ion an
a>n
ee
um
uc ion
>
e
ver ressure
nl
This item involved two issues
resulting from the July'12,
1989,
reactor trip and subsequent
main feed
pump suction piping
overpressurization.
The first issue
involved the adequacy of
previous corrective actions
regarding excessive
pressurizer
spray valve seat
leakage.
The inspector
reviewed the work
history on these
valves in all units since startup.
The work
history shows approximately
60 Mork Orders
(MO) were issued in
Units 1 and
2 over the- three years prior to the event.
Host of
these
MOs were to address
calibration
and seat
leakage
problems.
Additionally, the inspector
observed current operational
parameters
to assess
the condition of the valves in Units 1 and
3, which were at normal operating pressure.
In Unit 3, the
proportional
heaters
control at about
50 percent output (or
150
KM) to maintain plant pressure
while compensating
for seat
leakage,
bypass
flow and ambient heat losses.
One set of
150
KM backup heaters
augment the proportional
heaters.
In
Unit 1, backup heater"
are also
used to augment the
proportional
heaters
for steady state conditions.
In both
units observed,
operators
indicated that substantially
more
heaters
were previously required
due to excessive
leakage
and
that current conditions were noticeably better.
Combustion
Engineerinq
Standard
Safety Analysis Report
(CESSAR), Section
5.4. 10.2, indicates that the proportional
heaters
are designed
to be adequate
to maintain pressure
and that the backup heaters
are normally deenergized.
The current conditions in Units 1
and
3 do not appear to meet this design standard,
in spite of
noted
improvements to the valves.
An analysis of the depressurization
event
was performed by
Combustion Engineering
and documented
in the Incident
Investigation
Rep'ort (IIR-2-2-89-001).
This analysis
concluded
that the excess
pressurizer
spray
and diminished reserve of
backup heaters
contributed only slightly to the extent of the
depressurization.
The performance
of the Steam
Bypass Control
Valves appears
to have
been the principal contributor to the
pressure
decrease.
The Engineering Evaluations
Department
(EED) has performed
an
evaluation of current conditions
and concluded that the spray
valves are not leaking excessively.
The use of backup heaters
is necessary
due to ambient losses
and normal
bypass
spray
flow.
The
CESSAR section referenced
above
assumes
a much
smaller bypass
spray flow rate than
has
been found necessary
to
achieve
a less
than
70 degree
F temperature
difference
between
spray line temperature
and pressurizer
temperature,
This
increased
flow rate,
in conjunction with longer than
anticipated piping runs,
has resulted in both greater
ambient
heat losses
than
assumed
and greater
heater
demand to offset
5
the spray effects
on pressure.
EEO has stated that these
CESSAR assumptions,
while no longer valid, do not impact on the
safety analysis.
However,
EED has
agreed that the
should
be updated to reflect actual plant conditions.
The inspector
concluded that the corrective actions
taken with
respect
to the spray valve leakage
were adequate
and there were
no further technical
concerns.
The second
issue
deals with adequacy
of corrective actions
following the main feedwater
pump suction piping
overpressurization
event.
The inspector
reviewed
IIR-2-2-89-001.
One of the corrective actions'dealt
with the
delay in troubleshooting
the feedwater suction pressure
switches
which were found to be deformed several
days before
the unit was restarted.
IIR-3-2-89-032 was performed to
evaluate
the circumstances
leading to this delay.
The
inspector
reviewed this IIR as well.
These reports
do not
address
the deficiencies
in the initial engineering
evaluation
of the overpressurization
identified by the inspector
and
reported in Inspection
Report 529/89-30.
However, the final
engineering evaluation,
as presented
in these
documents
and in
the "Condensate
Piping Overpressure
Evaluation" dated
August 16,
1989,
appears
to adequately
address
the technical
issues
associated
with the overpressurization
event.
The
corrective
and preventive actions
associated
with the delay in
troubleshooting
appear to be appropriate.
The licensee's
corrective actions following this reactor trip
event were discussed
during
a management
meeting held
September
1,
1989 (Inspection
Report 529/89-42).
The inspector
noted that although the licensee
acknowledged
the lessons,
learned
from this event,
the inadequacy of engineering
work was
not detailed in the investigation report.
The
NRC will
continue to monitor the licensee's
long range
improvement
efforts in this area.
This item is closed.
(Closed)
Enforcement
Item (529/89-43-03
- "Failure to
0
1
nl
This violation resulted
from the licensee's
failure to notify
the
NRC of the incapacitation
and removal
from licensed duties
of a licensed operator.
This issue is closely related to
issues
regarding licensed operators'edical
records
which will
be documented
in Inspection
Report 50-528/90-36.
The
evaluation of the licensee's
corrective actions to this item
(529/89-43-03) will be addressed
in that inspection report.
This item is closed.
(Closed)
Enforcement
Item (529/90-03-01):
"Use of
nre
>a
e
mer enc
>ese
enera
or
ue
>
ora
e
an 've
e er
or
urve>
ance
es
-
ni
-
2)
This violation resulted
from using
a meter with a
known
reliability deficiency to satisfy
a Technical Specification
surveillance
requirement.
The licensee
has provided guidance
to operations
personnel
to evaluate
such deficiencies
and
document justification for use of deficient indication
equipment in the surveillance test log.
Additionally, the
.
diesel
generator
surveillance
procedures
have
been modified to
allow use of alternate
indications of fuel oil tank level.
These actions
appear
adequate.
The inspector
has not
identified during routine inspections
any further
cases
of log
taking deficiencies
by AOs.
This item is closed.
3.
Review of Plant Activities (71707
and 93702
a.
b.
Unit 1
The unit began
the repor t period in Mode 5.
tube plugging was resolved with the installation of a
Combustion Engineering
tube sheet
plug and the discovery and
repair of several
other leaking tube plugs.
Mid-loop operation
was entered to support the removal of nozzle
dams.
The unit
entered
Mode 4 on June
13, 1990,
and
Mode
3 on June
14,
1990.
The Confirmatory Action Letter
(CAL) of December
24,
1989,
was
lifted on June
24,
1990,
and
Mode
2 followed immediately
thereafter.
A manual reactor trip test
was conducted
on
June
25,
1990,
and
Mode 2 was entered
again
on June
25, 1990.
A slipped
rod event during startup testing occurred
and was
evaluated
and resolved.
Mode 1 was entered
on June
30,
1990.
Main turbine control problems
were traced to incorrect orifices
in the turbine control oil system.
The Power Ascension Testing
Program
was nearing completion
and the unit was at 100 percent
power at the end of the report period.
Unit 2
Unit 2 entered this report period in Mode 6, with major
activities associated
with the refueling outage in progress.
Node
5 was entered
on June 3,
1990.
The plant entered
Mode 4
on July 2 and
Mode
3 on July 3.
The reactor
was brought to
criticality at 10:46
PM,
MST,
on July 14,
and the plant ended
the report period in Mode 2.
Unit 3
Unit 3 began this report period at 100 percent
power.
On
May 29
1990, the unit experienced
a reactor
power cutback when
the
"A
main feedwater
pump tripped
as
I8C Technicians
were
completing
a preventive
maintenance
check
on the discharge
pressure
switches
(see
paragraph
20).
Other than minor power
reductions for testing and/or maintenance,
the unit remained at
100 percent
power for the rest of the report period.
d.
Plant Tours
The
the
The
2.
3.
4.
5.
6.
7.
8,
following plant areas
at, Units 1,
2 and
3 were toured by
inspector during the inspection:
Auxiliary Building
Containment Building
Control
Complex Building
Diesel
Generator Building
Radwaste
Building
Technical
Support Center
Turbine Building
Yard Area and Perimeter
following areas
were observed
during the tours:
0 eratin
Lo
s and Records - Records
were reviewed against
ec naca
peer
>ca ions and administrative control
procedure
requirements.
Monitorin
Instrumentation - Process
instruments
were
o serve
or corre
a son
etween
channels
and for
conformance with Technical Specification requirements.
Shift Staffin
- Control
room and shift staffing were
o serve
or conformance with 10 CFR 50. 54.(k), Technical
Specifications,
and.administrative
procedures.
E ui ment Lineu
s - Various valves
and electrical
breakers
were vers le
o be in the position or condition required
by Technical Specifications
and administrative'rocedures
for the applicable plant mode.
E ui ment Ta
in
- Selected
equipment, for which tagging
reques
s
a
een initiated,
was observed to verify that
tags were in place
and the equipment
was in the condition
specified.
General
Plant
E ui ment Conditions - Plant equipment
was
o serve
or
>n >ca 1ons
o
sys
em leakage,'mproper
lubrication, or other conditions that would prevent the
systems
from fulfillingtheir functional requirements.
Fire Protection - Fire fighting equipment
and controls
f
Tthf ht
Specifications
and administrative procedures.
Plant Chemistr
- Chemical analysis results
were reviewed
or con ormance with Technical Specifications
and
administrative control procedures.
9.
Securit
- Activities observed for conformance with
regu
a ory requirements,
implementation of the site
security plan,
and administrative procedures
included
vehicle and personnel
access,
and protected
and vital area
integrity.
The Secondary
Alarm Station
was included in plant tours.
The inspector
observed
one instance
in which an escort
abandoned
his escort duties for a visitor in the Unit 2
auxiliary building for a period of about five minutes.
This incident was referred to Region
V personnel
and was
documented
in Inspection
Report 529/90-29.
10.
Plant Housekee
in
- Plant conditions
and
ma erma
equ>pmen
storage
were observed to determine the
general
state of cleanliness
and housekeeping.
ll.
Radiation Protection Controls - Areas observed
included
con ro
porn
opera ion, records of licensee's
surveys
within the radiological controlled areas,
postinq of
radiation
and high radiation areas,
compliance with
Radiation
Exposure Permits,
personnel
monitoring devices
being properly worn,
and personnel
frisking practices.
No violations of NRC requirements
or deviations
were identified.
4.
En ineered Safet
Features
S stem Walkdowns - Units 1
2 and
3
Selected
engineered
safety features
systems
(and systems
important
to safety)
were walked down by the inspector to confirm that the
systems
were aligned in accordance
with plant procedures.
During this inspection period the inspectors
walked
down accessible
portions of =-the following systems.
Unit 1
r
o
"A" and "B"
o
System
Unit 2
o
Emergency
Core Cooling System
(ECCS) Containment
Sumps - Trains
"A" and "B"
Unit 3
o
"A" and "B"
No violations of NRC requirements
or deviations
were identified.
5.
Monthl
Surveillance Testin
- Units
1
2 and
3 (61726)
Selected
surveillance
tests
required to be performed
by the
Technical Specifications
(TS) were reviewed
on a sampling basis
to verify that:
1) the surveillance
tests
were correctly
included
on the facility schedule;
2)
a technically adequate
procedure
existed for performance
of the surveillance tests;
3) the surveillance tests
had been performed at the frequency
specified in the TS;
and 4) test results satisfied
acceptance
criteria or were properly dispositioned.
b.
Specifically, portions of the following surveillances
were
observed
by the inspector during this inspection period:
Unit 1
Essential
Chilled Water System Inoperable
Action Surveillance
Testing Atmospheric
Dump Valves in Mode 3
Atmospheric
Dump Valves Nitrogen
Accumulator Drop Test
Core Protection Calculator
Channel
"B"
Functional Test
Unit 2
~0i U
Unit 3
~race
ere
Cleaning/Inspection
of ECCS
Control Element Drive Mechanism Circuit
Breaker Surveillance Test
Remote
Shutdown Disconnect Switch and
Control Circuit Operability
Integrated
Safeguards
Surveillance
Test
Train "A"
Section
XI Valve Stroke Timing for Steam
Generator
No.
2 Containment Isolation
Valves.
During the performance of
73ST-2XI02 for steam line drain valves,
communications
were noted
by the inspector.
to be formal
and control
room operators
exercised
good control of the evolution.
Descri tion
Engineered
Safety Features
Actuation System
Train "A" High Risk Subgroup
Relay Monthly
Functional
Test
Weekly Shutdown Electrical Distribution
Checks
No violations of NRC requirements
or deviations
were
identified.
10
6.
Monthl
Plant Maintenance
- Units
1
2 and
3 (62703)
a.
b.
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 equality Assurance/equality
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.
Specifically, the inspector witnessed portions of the
following ma>ntenance
activities:
Unit 1
Descri tion
o Steam
Bypass
Control
System Valve Dynamic Response'ime
Test
o Oil samplinq in LPSI "A" Pump Motor
o Repair Leaking Body to Bonnet Leak on LPSI "8" Suction
o Repair Auxiliary Building Ventilation Ducting
o Troubleshooting
ADV-178 Air/Nitrogen Leak
o Troubleshooting
Steam
Bypass Control Valve 1008 Timing
Problem
o Installation of gBN-001 Holophane
Emergency Light Unit
o Burn Test of gBN-003 Holophane
Emergency Light Unit
During the performance of a preventive maintenance
task to
add oil to the crankcase
of charging
pump CHA-P01,
mechanics
used approximately five-eights of a gallon of
the wrong oil.
After running the
pump for approximately
half an hour after the incorrect oil was added the error
was discovered
by the licensee
maintenance
person
who
added the oil.
The
pump was stopped,
declared
the system engineer
was contacted,
the oil taken out,
and
the proper oil was
added prior to the
pump being restored
to service,
The inspector
noted that the licensee's
identification of
the issue indicated
a willingness
on the part of craft
personnel
to identify their own errors.
Unit 2
Descri tion
o
Remove Isolation Valve 2SIB-UV-0676-"8" Containment
P
I,
l
t
11
o
Retest of 2-E-NGN-L1287 Load Center Main Feed Breaker
o
Atmospheric
Dump Valve Nitrogen Regulator
FCV-323
Troubleshooting
Unit 3
Descri tion
o
Troubleshooting
3-E-gDN-N02 Emergency Lights
o
Control Element Drive Mechanism Coil Traces
43TP-3S F01
During a review of Work Order
(WO) 423113 in Unit 3 for the
performance of 36MT-9SG01,
ADV Weekly Bonnet Pressure
Measurement
and Instrument Installation, the inspector
noted
that
no signature
was present
on the
WO cover sheet for
Releasing
Organization.
This signature constitutes
permission
to perform the work.
The Releasing
Organization in this
instance
was Operations
and the Assistant Shift Supervisor
had
signed
page
6 of 28 of the attached
copy of 36MT-9SG01, which
constituted
permission to perform the work.
The inspector
concluded that this represented
inattention to detail.
No violations of NRC requirements
or deviations
were
identified.
Worker in a Hi
h Radiation Area (HRA) Without Pro er Dosimetr
n)
On June
20, 1990, the inspector
noted that
a Mechanical
Maintenance
Foreman
was in a
HRA with only a 0-200
mi llirem
(mR) Self Indicating Dosimeter (SID), rather
than also with an
alarming dosimeter set at 50
mR as required
by the Radiation
Entry Permit (REP).
The inspector
questioned
the worker who
acknowledged that
he had forgotten that his work area
was
a
and
had not noticed the posting because
he backed
down the
ladder to the lower level of -the "A" Low Pressure
Safety
Injection pump
room.
This is a violation of NRC requirements
(528/90-23-01).
This was brought to the attention of licensee
management
who
took immediate corrective action.
The individual's radiation
exposure
was evaluated
and
no overexposure
occurred.
The
individual's work records
were reviewed
and
no other similar
incidents
have occurred with this individual.
The individual
asked to brief all the Unit 1 Maintenance
Department personnel
on the lessons
he learned
from the event.
Management
agreed
and these briefings will be complete
by July 19,
1990.
A Problem Resolution
sheet
was initiated and
a Radiological
Controls Problem Report
was completed.
The worker's access
to
the Radiological Controls Area
(RCA) was
removed until the
investigation
was complete.
The Radiological Protection
(RP)
Lead Technician at the
RP "Island" was
removed from Shift
12
Technician responsibilities
at the
RP "Island" until he
completed
an oral
knowledge review with the unit
RP Manager.
The day the
RP Technician
was to meet for this knowledge review
he resigned citing unrelated
personal
reasons.
The
department
concluded that the root cause of the event
was the
Lead Technician at the
RP Island failed to provide the
worker with proper service in that two separate
briefings
failed to identify the lower level of the "A" LPSI room as
a
HRA.
In addition, the Maintenance
Manager concluded that the
worker did not meet his expectations
regarding following the
requirements
of the
REP and
RP postings.
Several
actions
are
in progress
to prevent recurrence
of this event:
1)
The
RP department
is acceleratinq their plans to
change
the excessively
conservat>ve
posting policy of
post>ng
a larger area
than necessary
as
HRAs and
Locked
In the future the RP'department
plans to post only the immediate
area surrounding the
sources
of exposure requiring
HRA and
LHRA postings
rather than entire
rooms or levels.
This is a long
term effort which will involve establishing
dose rate
guidelines for the location of HRA and
boundaries,
procedure
changes
and training.
This
site effort will be complete
by September
30,
1990.
2)
Unit 1
RP department
created
an
RP Restart
Plan which
is a notebook containing survey and posting changes
which were required for the various
power levels with
required notifications for the Unit 1
RP Manager.
3)
The
RP department-
i.s acceleratinq
the plan to use
reverse
background posting sign )nserts.
The inspector
agrees
with the preliminary conclusions
reached
by the licensee.
One violation of NRC rquirements
was
identified.
8.
Plant Startu
From Refuel in
- Unit 1 (71711
72700)
The inspector evaluated
the Emergency Diesel Generators
and the
Motor Driven Auxiliary Feed
Pump AFB-P01 system for proper
restoration
from the refueling outage.
No discrepancies
were
noted which would affect component or system operability.
The inspector
reviewed 410P-1ZZ03,
Reactor Startup,
and noted
that it contained revisions which addressed
concerns
the
inspector raised after observing
Reactor Startup,
used for a reactor
startup at Unit 2 on September
22,
1989,
and
described
in Inspection
Report 50-529/89-43,
paragraph
12.
The
inspector
observed
the Unit 1 reactor startup
on June 24, 1990,
and
had
no concerns.
The inspector
noted that after Reactor
Engineering told Operations
they were ready for Operations
to
perform the startup,
the Assistant Shift Supervisor
announced
that they were starting to pull regulating group control
rods
13'nd
then the Reactor
Engineer
asked Operations
to wait two more
minutes
so Reactor Engineering could get their paperwork ready.
The inspector particularly noted the Shift Supervisor's ability
to keep this confusion
from affecting his crew's performance.
The inspector
concluded that the unit appeared
ready for the
startup
and
power operations.
No violations of NRC requirements
or deviations
were
identified.
9.
Confirmator
Action Letter Followu
- Unit 1 (92703)
By a letter dated January
11, 1990,
the licensee
committed to
the
NRC to complete
190 action items associated
with Unit 1
prior to its restart following the
15 month outage which began
after the unit trip of March 5, 1989.
These
items included
lessons
learned
from the Unit 3 reactor trip event of March 3,
1989, in the areas
of Atmospheric
Dump Valves,
Emergency
Lighting, Steam
Bypass
Control System,
and Reactor Coolant
Pump
Power Supplies.
Seventy-two of the items
had been closed
by
the licensee
during previous efforts in the restart of Units 2
and
3.
The inspector selected
an initial sample of fifty-one
items for review, thirteen of which came from the category of
previously closed items.. All of the above listed systems
were
included in this sample
as well as the instrument air system,
operations
department training and performance,
and post
restart
commitment progress.
Ultimately, over seventy
items
were reviewed in that additional
items were sampled
based
on
questions
arising from the review of the initial sample.
Further,
the licensee's
Management
Review Committee
(MRC)
activities were reviewed.
The following observations
represent
licensee
weaknesses
as they related to restart preparations.
a.
Atmos heric
Dum
Valves
(ADVs
The inspector
reviewed the licensee's
actions with respect
to valve labeling, procedure
for manual operation,
operability tests,
preventive maintenance,
training,
and
subsystem
maintenance.
The following
observations
were
made:
1)
The licensee
implemented
a preventive maintenance
calibration check of the nitrogen regulators
on ADVs
(Item 664), but implemented it only when performance
problems
occurred during monthly 30 percent stroke
testing or quarterly accumulator
pressure
drop
testing.
The inspector
noted that the licensee
performs calibration checks
on pressure
regulators
in
nonsafety-related
systems
and questioned
why the
safety-related
ADV nitrogen system
was not routinely
checked.
The licensee
committed to evaluate
and
implement
a routine calibration.
14
The licensee
flushed the
ADV nitrogen
system to
assure
the cleanliness
quality of the'nitrogen
supply
(Item 670), but subsequently
found foreign
particulate matter in the pressure
regulator,
which
could have contributed to observed
performance
problems during testing.
Nore aggressive
flushes
were performed to achieve satisfactory
system
cleanliness.
However, the nitrogen supply to the
ADV
is not filtered and,
although the
licensee
plans to install filters (Post Restart
Item 800) by April 1992,
no cleanliness
monitoring of
the
ADV nitrogen
system
was planned.
The inspector
questioned this lack of monitoring in view of the
known problem with particulate matter,
the present
lack of filters in the supply line,
and the potential
impact on the performance
of the pressure
reducer
and
ADY positioner
components.
The licensee
committed to
evaluate
and implement nitrogen quality monitoring
checks until the permanent filters are installed.
The above
two items were further described
in NRC
Inspection
Report 528/90-20.
While attempting to evaluate
the problems with
getting
ADV nitrogen systems
to pass
surveillance
test 41ST-1SG05,
ADV Nitrogen Accumulator Drop Test,
the licensee
questioned
whether temperature
had an
effect on the outcome of the test.
System
Engineering's
preliminary calculations
suggested
that
a one degree
Fahrenheit
change during the test would
result in approximately
one psiq pressure
change in
the accumulator.
This calculation
was refined by the
Nuclear
Engineering
Department
(NED) in Engineering
Evaluation
Request
(EER) 90-SG-114
and
a formula was
provided to account for temperature
changes
from the
beginning to the
end of the test.
However, this
formula was identified by the inspector to provide
invalid results in some cases.
When the ADV-178 accumulator
was tested
on June
23,
1990, the pressure
drop was
30 psig per hour, the
upper limit of the acceptance
criteria; however,
the
,temperature
had increased
an average of 0. 15 degrees
Fahrenheit.
When the
NED formula in EER 90-SG-114
was
used with this data,
the results
suggested
that
"the ADV-178 accumulator
passed its acceptance
criteria.
These results
were documented
in EER
90-SG-136.
The inspector questioned
the validity of
this result since with a measured
pressure
drop of
exactly
30 psig per hour,
any temperature
increase
would represent
a non-conservative
effect on the
measured
pressure
drop and would suggest that the
acceptance
criteria had not been
met.
Discussions
between
the inspector
and System Engineering
supervision
and management
revealed that the
0
15
90-SG-114 formula was based
on
a two hour pressure
drop from 650 psig to 590 psig, rather than the
actual
documented
drop from 625 psig to 565 psig.
This difference
made the formula in EER-90-SG-114
inappropriate for the actual field conditions
and
produced results
which wer e invalid from an
engineering
standpoint.
EER 90-SG-136
was
subsequently
revised using the correct temperature
compensation
formula.
While a reevaluation of the formula and the test
results
by System Engineering resulted
in accepting
the drop test,
the inspector
concluded that the
initial formula in EER 90-SG-114
was inaccurate with
respect to actual field conditions
and that System
Engineering failed to identify this when these
results
were applied to the initial version of EER
90-SG-136.
b.
Emer enc
Li htin
The inspector
reviewed the licensee's
restart
commitments
to install and test
Although the
licensee's
specific restart
commitments
were met, further
review in this area is documented
in
NRC Inspection
Reports
528/90-02
and 528/90-25.
On June 22, 1990, during
a routine plant tour, the
inspector
noted that three
emergency lights indicated
an
existing high charge condition and brought this to the
attention of plant management.
One of these units,
gBN-004,
a Holophane unit located at the
100 foot
elevation in the auxiliary building, required
a cell
replacement
and retest.
The other two units were dual
light units in the
77 foot and 87 foot elevations of the
west mechanical
piping penetration
rooms.
One unit
required replacement
and the other
no longer indicated
a
high charge.
The unit which displayed
a high charge
when
the inspector
observed it but had returned to normal
when
the licensee
checked it, could merely have cycled briefly
"
to high charge during the inspector's
tour which would be
consistent with the-design of these units.
In addition to
these
problems,
the licensee
discovered that Control
Room
emergency light gDN-F01 failed its 8-hour test apparently
due to
a faulty circuit card.
The car d was replaced
and
gDN-FOl passed
the test successfully.
The inspector
expressed
the expectation that these
and all other
emergency lighting discrepancies
be included in the
ongoing evaluation of the reliability of emergency
lighting.
The licensee
agreed with this and stated that
these
evaluations
were ongoing.
16
0 erations
Restart
Item 454 addressed
the following NRC concern:
"Operations Supervision is not adequately
establishing,
communicating,
monitoring,
demanding
and enforcing
a
working environment that promotes professionalism,
formal>ty, accountability
and adherence
to high standards
of performance."
This issue
was addressed
and closed
by
the licensee
based
on issuing several
memos.
Two of these
memos
were from the Plant Director to the Plant Managers
with copies to other
management
personnel.
These
two
memos set the tone
and standards
of professionalism for
Palo Verde Nuclear Generating Station.
One
memo was to
all plant personnel
which promulgated the Standards
for
Personnel
Performance
and Plant Material Condition.
This
memo included the Expectations
For Operations
which
described
expectations
for professionalism,
formal
communication,
not proceeding in the face of uncertainty,
use of procedures,
being alert to changing plant
conditions, maintaining control
room decorum,
and
insisting on high quality, professional
performance
and
high standards
for all unit personnel.
During the two weeks before the restart of Unit 1, the
inspector
observed
several
occasions
in which control
room
operators
were not adhering to these
standards.
In one
case,
a control
room operator
pushed
another operator
sitting in a chair for several
feet during the control
board walkdown portion of shift turnover.
In another
case,
while in a discussion with the inspector,
an
operator silenced
an alarm, but did not know the nature of
the alarm which had been silenced
when questioned
by the
inspector.
In a third case,
the inspector
observed
a
control
room operator direct an Auxiliary Operator
(AO) to
go to a containment
purge valve inside containment
where
radio communication is poor,
"make
some noise" to signal
the Control
Room Operator to open the valve, then
"make
some
more noise" to signal the Control
Room Operator to
shut the valve, then telephone
the Control
Room Operator
to discuss
the results.
Mhile this troubleshooting
activity transpired,
the inspector
observed
the Control
Room Operator proceed
as planned
and then misunderstand
the
AO using the radio.
During these
same
two weeks,
three self-revealing
events
also indicated that operators
were not always adhering to the established
standards.
The first event involved rendering all four Safety
Injection Tanks inoperable
by powerinq their vent valves
as discussed
in paragraph
13 of this inspection report.
The second
event involved restoring the Steam
Bypass
Control System
(SBCS) with a large
demand,
which resulted
in six steam
bypass
control valves opening rapidly,
thereby causing
swell from 50 percent to
at least
91 percent,
triggering
Line
Isolation initiation.
The Operators
followed the
17-
procedure,
but,
due in part to a procedural
deficiency and
the operators'ailure
to fully understand
the expected
plant response,
the operators
failed to compensate
adequately for the larqe
demand signal prior to restoring
the
SBCS.
This event )s detailed
in paragraph
12.
The
third event involving two Auxiliary Operators
who failed
to properly follow the procedure for manual
operation of
an Atmospheric
Dump Valve as described
in paragraph
10.
The inspector considered
each of the three inspector
observation
examples to be of relatively minor safety
significance.
However,
when these three
examples
are
taken
as
a whole, with the three self-revealing
events,
a
need for additional
management
attention into control
room
and operations activities was evident.
This was discussed
with the Unit 1 Operations
Manager
and Plant Manager.
In
addition,
Region
V management
discussed this with senior
licensee
management.
The Plant Manager prepared
a
briefing paper containing these six events
and management
guidelines
and philosophy to be given to all operators
at
shift turnover by the Shift Manager.
The inspector
observed
two of these briefings and noted that the
briefings were detailed, specific,
and clearly expressed
management's
concerns
and expectations.
The Plant Manager
implemented
a previously planned Shift Manager position to
provide 24 hour/day-7
day/week
management
coverage
onsite
for Unit 1 during the startup preparations
and
power.
ascension.
The
NRC inspector
concluded that the
licensee's
corrective actions
were appropriate
and that
these
issues
would not prevent the
NRC from lifting the
December
24,
1989 Confirmatory Action Letter.
d.
Preventive
Maintenance
(PH)
The licensee
committed to provide justification for waived
PM's which involved performinq all
PMs that could be
performed
and having Engineer)ng
Evaluation Requests
(EERs) for PMs which could not be performed (Restart
Item 9).
One of these
was
a
PH to calibrate fire
protection
pump oil pressure
switch AJFPNPSL0104,
which
could not be performed
due to the unavailability of parts.
The
EER to justify why the plant could be operated
safely
without this
PH complete
(90-FP-29)
was
vague
and did not
document
a complete evaluation of the impact on the plant.
The inspector
questioned this
EER and was provided
90-FP-030 which fully addressed
the impact of the
nonperformance
of this
PH on plant operation.
Mhile
completing
EER 90-FP-030
on June
24,
1990, the licensee
'lso
placed
a deficiency tag on the local alarm panel for
FPNP01A to warn operators that the low oil pressure
switch
is not within calibration.
The licensee
also committed to ensure
th'at there are
no
other waived PH's which could affect safe plant operation.
This was also documented
in Restart
Item 9.
The licensee
accomplished this by reviewing all
PHs since
commercial
operation,
identifying those which had been waived,
and
evaluating
each waiver for any current impact on plant
operation.
In many cases
Engineering identified rework
which was necessary
for safe plant operation.
The
evaluation of each waived
PM was
documented
on a form
which required the engineer
to document the basis for the
PH,
an evaluation
as to whether the lack of performance of
the
PH caused
or could have
caused
degradation,
whether
Engineering will now grant the existing waiver, whether
additional
requirements
need to be imposed
as
a result of
the waiver,
and when the
PM is next scheduled
to be
performed.
The inspector evaluated
a sampling'f these
PH
review forms for safety-related
systems.
The majority of-
those
reviewed were properly filled out and contained
apparently
adequate justification for the determinations
made.
A significant number,
however,
contained
only a
"No" or "None" answer to some questions
without additional
d>scuss>on.
The inspector
questioned this during discussions
with the
.
Systems
Engineering
Manager
who agreed that the
documentation
of these evaluations
were, in many, cases,
inadequate.
The licensee
committed to re-review all
reviews to select
those with inadequate
documentation of
the justification.
Each
PM review which is inadequately
just>fied will be re-reviewed
and the justification will
be adequately
documented.
Any new add)tional
requirements
to be performed
as
a result of not performing the
PH will
be brought to the inspector's
attention immediately
and
all re-reviews will be complete
and available for the
inspector's
review by November 1,
1990.
This will remain
an open item until the re-review,
documentation
and
inspector's
review is complete
(528/90-23-02).
Mana ement
Review Committee
(MRC)
The
MRC functioned essentially
the
same
as during the
previous review of the Unit 3 restart
program.
The
MRC at
the outset recognized
the importance of demonstrating that
APS was capable of managing three operating units.
As a
result,
the
MRC paid considerable
attention to various
backlogs.
The stated criteria was to maintain
a
decreasing
backlog in Units
2 and
3 while preparing to
startup Unit l.
An additional
suggestion
was first
proposed that the
MRC review any incidents that occur
(site-wide) for evidence of management
weakness.
This
suggestion
was apparently
not formally or comprehensively
undertaken,
even though
a number of events
occurred since
December,
some of which are
documented
in NRC Inspection
Reports.
19
Finally, the
MRC recognized that the toughest
issue which
needed
to be overcome in the restart of Unit
1 would be
personnel
readiness.
As
a result,
the
MRC maintained,a
continued interest in 'training, proficiency watches,
and
management
observations
of operators
in simulator training
and during plant operations.
However,
as noted elsewhere
in this report section,
the inspector
observed
occasions
where operator
performance either failed to meet
established
standards
or caused
an operational
problem.
The inspector
noted that although maintenance
and
engineering
backlogs
appeared
to be getting under control,
personnel
performance
continues to require additional
management
attention.
It appears
that the
successfully
served its purpose
in the management
overview
of restart activities.
Post-Restart
Comnitments
g.
The inspector
reviewed several
of the licensee's
closed
post-restart
action items.
One of these
(Item 616)
was 'a
commitment to evaluate
the
need for a chemistry post-trip
checklist.
The inspector
noted that the licensee
closed
the item by referencing
the evaluation which determined
the
need for such
a checklist in July 1989
and
recommended
implementation
by December
1989.
In June
1990, the
inspector determined that the checklist
had not been
implemented
because
of an assigned
low priority in the
procedure
change
backlog.
The inspector noted that the
licensee
met the letter of the commitment by performing
the evaluation,
but had not followed it through to
completion in a timely manner.
Subsequently,
the licensee
upgraded
the priority and expects
to issue the checklist
by August 31,
1990.
The inspector will continue to
periodically review completed post-restart
items.
~Summa r
The inspector
concluded that although the licensee
ultimately met their restart
commitments,
several
items
as
noted
above required additional actions
subsequent
to
NRC
identification of discrepancies.
This appears
to reflect
the
need for a continued
and heightened attitude of self-
criticism and
an insistence
on timely, final, and
sustained
corrective actions
by all licensee
employees.
No violations of NRC requirements
or deviations
were
identified.
10.
Mis-o eration of Atmos heric
Dum
Valve
ADV
in Manual-
Unst
1
93 02
On July 21,
1990, the
NRC inspector
observed testing of
ADV-178, which required the manual
operation of the
ADV in
20
accordance
with procedure
Manual Operation of Air
Operated
Valves.
Steps
8.7 through B.9 in 41DP-10P01
required
the Auxiliary Operator
(AO) to lower the manual override shaft,
insert the clevis onto the actuator shaft,
then manipulate
the
valve using the handwheel.
The AO's difficulties in manually
operating
ADV-178 indicated
a lack of familiarity of the proper
operation of the
ADVs and resulted in the failure to perform an
action required
by the procedure.
These difficulties are
particularly noteworthy in light of the attention
on the manual
operation of ADVs based
on the March 1989 reactor trip event
and restart
commitments in this area.
When the
AO attempted
to lower the manual override shaft
as
specified
by Step B.7, the
AO rotated the handwheel
in the
counter-clockwise direction.
When the
AO encountered
resistance,
a second
AO was consulted
and the first AO
continued trying to rotate the handle counter-clockwise.
After
further discussion with the second
AO, both
AOs together tried
to turn the handwheel
counter-clockwise.
At this point,
an
assigned
to supervise this activity interrupted
and reminded
the
AOs that they had to engage
the clevis first.
At this
point, the first AO turned the handwheel
clockwise,
lowered the
manual override shaft,
engaged
the clevis,
and operated
the
valve.
Step B.8 required the set
screw to be tightened
when
the clevis was
engaged
to secure
the clevis to the actuator
shaft.
This was not accomplished
and
when the inspector
questioned
the
AO immediately after this evolution the
acknowledged that the set
screw
had
been forgotten.
This
failure to follow the procedure is
a violation of NRC
requirements
(Enforcement
Item 528/90-23-03).
The inspector
noted that the procedure
requirement for
tightening the set screw was
one of several
actions in Step B.8
for engaging
the clevis
on the actuator shaft.
A revision of
procedure
dated July 5, 1990, separated
the actions
by creating
separate
steps for sliding the clevis onto the
actuator shaft, fully seating
the clevis,
and tightening the
set screw.
The inspector considers this change to be
an
improvement to the procedure.
To ascertain
whether other
AOs had adequate
knowledge of the
proper manual
operation of ADVs, the licensee
chose
two AOs
from Unit 2 and two from Unit 3 and asked
them to demonstrate
manual
operation of an
ADV on short notice.
The AOs were able
to properly operate
the
ADVs in manual
and
on this basis
the
licensee
determined that the observed
ADV manual mis-operation
was
a performance
issue
on the part of the operators
involved
, and not
a training issue.
The
NRC inspector
agreed with this
conclusion.
The licensee
responded
to this concern
along with other
operator
performance
concerns
described
in this report by
immediately implementing the planned Shift Manager position for
the restart activities, addressing
the operator
performance
issues with the operators, involved, and conducting
management
21
briefings of'l 1 Operators,
licensed
and non- 1 icensed,
to
discuss'anagement
expectations
regarding operator
performance.
Over-Dilution
Excessive
Power
Rate Increase
- Unit 1 (93702)
On July 8, 1990, while diluting the reactor coolant system to
increase
power, the reactor operator permitted power to
increase
from 50 percent to approximately 54.5 percent in one
hour.
This exceeded
the Combustion Engineering
(CE) fuel
preconditioning guidelines of 3 percent
per hour.
The
operators
reduced
the power increase
rate to within CE's
guidelines
and notified management.
The licensee
has
determined that this is an operator
performance
issue
and
has
addressed
this with the operator involved.
The inspector
considers this to be another
example which suqgests
that
operator
performance
continues to require add>tional
management
and supervisory attention.
No violations of NRC requirements
or deviations
were
identified.
Main Steam Isolation
Due to Restorin
Steam
B
ass Control
s
em
wi
a
ar
e
eman
-
ni
On July 20, 1990, while restoring
from 36MT-9SF09,
Steam
Bypass
Control System Valve Dynamic Response
Time Test, the operators
moved the Emergency Off/Reset handswitch
from Emergency Off to
Re'set with a large
demand signal,
which caused six Steam
Bypass
Control Valves
(SBCV) to open rapidly.
This rapid increase
in
steam
demand
caused
a large swell in both steam generators.
Number
swelled from 50 percent to 94 percent
level, triggerinq a Main Steam Isolation Signal
(MSIS).
The
operators
stabilized the plant using 41A0-1ZZ31, Inadvertent
MSIS, verified the MSIS actuation,
stopped
SBCV work and
notified Compliance
and the System Engineer.
A Category
2
investigation
was initiated and
a Licensee
Event Report
(LER)
will be issued.
The inspector
concluded that this event
was
an
example in which operator performance
and procedures
needed to
be improved and that increased
management
and supervisory
attention
appears
warranted.
The inspector will evaluate
the
.
licensee's
conclusions
during the review of the
LER for this
event.
No violations of NRC requirements
or deviations
were
identified.
22
Ino erable Safet
In'ection Ta'nks - Unit 1 (93702)
On June
17,
1990, all four Safety Injection Tank (SIT) vent
valves
were discovered
by the oncoming Assistant Shift
Supervisor to have
power available. 'his
was contrary to
Technical, Specification 3.5. 1.(a)
and rendered all four SITs
technically inoperable.
This licensee identified violation is
not being cited because
the criteria specified in Section
V.G.
of the Enforcement Policy were satisfied.
Power was provided to the SIT vent valves
on June
16, 1990,
approximately
25 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br /> earlier, to facilitate draining of SIT
1A to permit disassembly
and repair of valve SI-235, the SIT 1A
discharge
Subsequent
to the identification of
this situation,
the licensee
immediately
removed
power from the
vent valves,
which restored
three of the four SITs to an
operable status,
and initiated
a Problem Resolution
Sheet
and
a
Category
3 investigation.
The inspector
noted that the
management briefing given to the operations staff on this event
appeared
appropriate.
Further
review of licensee
actions to
improve operator
performance will be conducted
during rev'iew of
the required
LER.
Installation/Testin
of Modifications - Unit 2 (37828)
The inspector
examined the activities
and hardware associated
with the plant modification to install
a Refueling Mater Level
Indication System
(RMLIS).
The system
was installed in Units 1
and
2 and was in response
to Generic Letter 88-17 regarding
mid-loop operations.
The physical installation was examined in the Unit 2
Containment,
including instrumentation
tubing runs
and
connections
to the pressurizer
and the shutdown cooling loop.
The inspector verified anchorages,
tubing slopes
and runs,
and
labeling.
The inspector also examined
records of the installation
including the design
change
package
implementing work orders
and completed construction inspection plans
and testing
documentation.
The inspector
observed
the added control
room
indication in Unit 1 and discussed
the
new system operation
with the Unit 1 operations
personnel
who had actually used the
system during recent
work.
The inspector
also
discussed
modification management
and testing with
construction,
planning
and system engineering
personnel.
Further,
the inspector
requested
that the licensee reverify the
physical elevation location of the
RMLIS differential pressure
indication LT-752A, 752B,
753A and 753B.
The level indicators
were subsequently
verified to be at the proper elevation.
No violations or deviations
were observed
during the
inspection.
However, several
observations,
summarized in the
following paragraphs,
were
made by the inspector
which were
23
related to the licensee
at
an. exit interview held on June
29,
1990.
o
Desi
n
En ineerin
Methods of Communicatin
Information
o
e
le
ons ruc
son
ersonne
The inspector,
in examining the paperwork which documented
>the design
change
noted that the elevation tolerance for
locating the
RMI.I( level transmitter
was communicated
by
means of a relatively obscure
note in the Design
Change
Package
and limited the elevation deviation to plus or
minus one-half inch, which is much tighter than the
licensee's
normal field installation tolerance of plus or
minus
5 inches for instrumentation
location.
Also any
substantial
height deviation would lead to a corresponding
error in indicated level which could cause
inadvertent
reactor coolant vortexing in mid-loop operations.
The
inspector requested
the height of the transmitters
be
reverified, which was
done
and was found to be
satisfactory.
The inspector
noted to licensee
design
engineering
personnel
the type of documents field
personnel
take to the field to perform such
an
installation, specifically work orders
and installation
drawings.
These field documents
would appear to be the
more appropriate
means of communication.
o
Stren th of Construction
Ins ection
Plans'he
inspector
noted that the licensee's
system of using
pre-estabished
Construction Inspection
Plans
(CIPs)
appeared
to be
a sound method to ensure
important
inspection attributes
in specialized
areas
were examined
and signed off.
The methodology also provides
a location
to capture
any "lessons
learned 'hen recurring
installation problems might be encountered.
o
Stren th of Modification Turnover Process
The inspector
noted that the licensee's
modification
turnover process
included
a walkdown and acceptance
by the
user organizations,
e. g. Maintenance
and Operations.
In
the case of the
RMLIS modification, the walkdown resulted
in a change to the nomenclature
of the labeled valves (to
suit Operations
needs)
and change in the scaling of
control
room indicators to reflect specific plant
elevations
vice relative heights (to suit operator
preference
and for clarity and consistency with
procedures).
Mhile good observations
were being
made in the turnover
process,
the inspector
commuted that the licensee
should
continue to emphasize
the importance of the turnover
process
to plant'ersonnel.
The inspector
noted that the
two gage glass installations (for direct visual
1.
24
observation of mid-loop level) were not labelled to
differentiate which gage
was reading which hotleg.
This
situation might lead to operator confusion since the
hotlegs will have different levels depending
on which
shutdown cooling train is being run.
The inspector also
pointed out that engineering
stated
they were surprised
the gage glasses
were not labeled since their "Note xi" to
DCP 2FJ-151 stated that all instruments
should
be "tagged"
if not already "tagged."
The inspector again pointed out
that general
design
change
notes
were not a good way to
communicate to the field and in this case
was not
implemented
as expected
by engineering.
Secondly,
the
inspector
noted that the changes
identified by the
walkdowns could have
been anticipated if a closer design
engineering/plant
user interface
had been established
in
the design planning stages.
o
Formalit
of Test Reviews
b
Desi
n
En ineerin
The inspector
noted that design engineering
had formally
documented their review, rationale
and acceptance
for a
special test of the
RWLIS system.
The inspector
considered this
a good practice.
o
Potential Installation Weaknesses
The inspector
observed
two design features that could
cause potential
problems in the future.
Specifically,
long tubinq runs
used
many swagelock mechanical fittings
which provide the opportunity for leaks,
whereas
welded
fittings would have eliminated the potential
maintenance
problems.
Secondly,
the final connection to plant
systems,
e.g. to the pressurizer
gas
space,
were
done
without the addition of RWLIS vent valves.
Other plants
have found frequent draining and venting of the
RWLIS to
be necessary
and have provided valves for such operations.
While Arizona Public Service
Company's current system
configuration will allow for such venting by disconnecting
swaqelock fittings at the high points, this may lead to
additional
maintenance.
On the other hand,
the licensee's
use of the system in Unit 1 did not indicate that frequent
venting was required at Palo Verde.
o
Lack of Detailed
0 erator
S stem Information
The inspector
observed that design engineering
had not
provided
an operating
diagram of the
RWLIS system for
operator
use.
Licensee
personnel
in standards
had
produced
a diagram in the operating procedure for the
system,
but the inspector
noted that the diagram
was not
complete
nor accurate.
Specifically high side
and low
side drain valves for the level transmitters
were not
shown
on the diagram although they were installed.
Additionally, the diagram (Appendix I of procedure
25
410P-1ZZ16) did not show the label
nomenclature
associated
with the valves in the field.
The inspector explained that other sites
had eventually
found it necessary
to number
and label all valves,
including those
operated
by I8C,
and to position and
ver ify those valves
by specific valve line up sheets.
The
inspector explained that other sites
found these
valve
line up actions
necessary
after they experienced
continuing valve line up errors especially in the
I8C/Operations
interface area.
o
Conclusion
At the exit interview on June
29,
1990, the ins'pector
concluded that the licensee's
installation and testing of
the
RWLIS system
appeared
to have
been properly performed.
Specific observations
were related
as detailed
above.
The
inspector also
made the qeneral
comment that it appeared
that the design engineering
interface with the site could
be strengthened
as exemplified by the changes
required to
the
RWLIS system after installation which could have
been
identified prior to the design
package
issuance,
and as
exemplified by the designers
expectation that general
package
notes
would be an effective way to communicate
detailed installation requirements.
Additionally, the inspector
noted
some of the licensee's
strengths
in modification control
as exemplified by the
Construction Inspection
Plans
(CIPs).
No violations of NRC requirements
or deviations
were
identified.
15.
Control
Room Controlled Document Discre ancies - Unit 2 (71707)
During a review of the performance
of a surveillance
test
on
June
26, 1990, which utilized information from the Unit 2-
Cycle
3 Core Data Book (CDB) to calculate Keff, the inspector
identified the fact that the copy of the
CDB utilized by
control
room operators
was marked "Information Only" instead of
"Controlled Document."
The inspector determined that the
licensee
Document Distribution Center
IODC) issued
e Revision
0
of the
CDB on April 30, 1990,
stamped 'nformation Only" on all
pages,
which was the copy in use
by Control
Room operators
in
Unct 2.
Then,
on May 10, 1990,
a revision (Rev.
1) was issued
which was marked "Controlled Document"
and several
revised
pages
were inserted
by
DDC in the
CDB in place of the old
pages.
The inspector
concluded that an inappropriately
marked
CDB was in use in the control
room and that
DDC had revised it
with an appropriately
marked revision but failed to notice the
discrepancy,
and operators
had utilized the
CDB at least weekly
to meet Technical Specification surveillance
requirements
without questioning the appropriateness
of the 'nformation
26
Only" markings.
The inspector
noted that over two months all
five operations
crews would have .had the opportunity to detect
and correct this discrepancy,
but did not.
The licensee's
immediate corrective action was to issue
a
controlled document
CDB to the Unit 2 control
room and to
verify that all controlled pages
matched
the information copy.
The licensee
concluded that the copies
were identical'nd
therefore
no technical
discrepancy
would have resulted
from the
use of the "Information Only" copy.
The licensee
checked all
other controlled copies of the
CDB's and found
no other
discrepancies.
In addition, the licensee
issued
a Night Order
to the operations staff stressing
the need to ensure
"Information Only" copies of documents
are not used in the
control
room.
On July ll, 1990,
a Unit 2 Shift Supervisor,
while answering
an
inspector's
question,
identified a controlled procedure,
Gaseous
Maste
System Sampling,
which had been
revised with a change
intended for 74ST-9SS03,
Post Accident
Sampling System Surveillance Test,
and
had been placed in the
location for 74ST-9SS03.
However, the correct
and updated
was in the location for 74ST-9ZZ03, Liquid Holdup
Tank Surveillance Test.
. Thus,
on July 10 the Unit 2 controlled
document set
had the following discrepancies:
'1)
was missing
2)
A correct
was mis-located to 74ST-9ZZ03
3)
was incorrectly revised with a change
intended for 74ST-9SS03,
The licensee
indicated that they had identified discrepancy
3
above
and
had re-issued
on June
7, 1990, but that it
had been mis-filed in Unit 2 to the 74ST-9ZZ03 location.
The
inspector
acknowledged that although the licensee
had
identified this problem,
the corrective action
had not been
completely effective.
The licensee
took immediate action to
correct these deficiencies
and verified these controlled
document procedures
were correctly located in all other
controlled locations.
In addition,
DDC performed
a 100 percent
audit of the Unit 2 controlled document set.
Finally, the
DDC
Supervisor
issued
a
memo to all
DDC personnel
regarding
attention to detail.
Document distribution also preformed
a
complete audit of .all Unit 2 controlled documents.
At the
end
of the audit, Licensing management
evaluated
the results
and
determined that out of 2,229 procedures,
23 deficiencies
were
noted,
but that these
had
no impact on plant operations.
The inspector
concluded that although the requirements
of
10 CFR Part 50, Appendix
8< Criterion VI, Document Control,
had
not been
met
the licensee
s actions
were prompt, thorough
and
appeared
to be appropriate.
Thus, this violation is not being
cited because
the criteria in Section V.A. of the Enforcement
P
27
Policy were satisfied.
The licensee
management
acknowledged
these
.comments.
Pressurizer
Heater
Re lacement - Unit 2 (93702)
A faulty pressurizer
heater
was identified during Cycle 2
operation
and was successfully
replaced .during this refueling
outage.
Another heater
had failed during Cycle 1 operation
which could not be extracted
and replaced.
In that case,
the
heater
element
had been cut off below the lower support plate
and the penetration
sealed with a welded plug.
The inspector
reviewed several
Engineerinq Evaluation
Requests
(EERs)
providing resolution of var>ous
c'oncerns
as efforts to extract
that heater
proceeded.
EER 88-RC-083
and Site Modification
2-SM-RC-011 document the acceptability of leaving portions of
the heater in the pressurizer.
The fai lure mechanism of the Cycle 1 failed heater,
documented
in EER 88-RC-123, is similar to that found in Arkansas Unit 2.
The heater
expands after water intrusion through the heater
sheath
wets the surrounding
oxide with sufficient
force on the inner diameter of the heater
sheath to split the
sheath.
The crack thus
formed will propagate
in either
direction and allow further wetting of the magnesium
oxide and
further splitting.
This could have resulted
sn an unisolable
loss of coolant
as the sheath splits into the weld area.
In
this case,
the split extended to about 1/4 inch into the upper
end of a sleeve,
but no weld area deformation
was observed.
These conditions
were evaluated
and determined
by the licensee
to be satisfactory to support the continued
use of the
penetration with a welded plug and the remaining portion of the
heater
in the pressurizer.
The inspector
noted that the heater
sheath
remaining in the pressurizer
is not in contact with the
pressure
boundary
such that potential for boundary
leakage
could occur'.
No violations of NRC requirements
or -deviations
were
identified.
Reactor
Coolant
Pum
Breaker Tri
- Unit 2
93702
On July 12,
1990, while rolling the circulating water
pump
breaker into the cubicle adjacent to the
Pump
(RCP) breaker,
the electricians jarred the side of the
cubicle.
The vibration caused protective relays
on the front
-of RCP
1B to shift, which tripped the
1B
RCP breaker.
The
reactor
was
shutdown at the time and there
was
no operational
impact.
This event is similar to the April 15,
1990 event in
Unit 1 described
in Inspection
Report 528/90-20,
paragraph
14.
The inspector
noted that the evaluation of this event is not
complete
and that the only document tracking the evaluation is
EER 90-NA-009, which was issued
as
a result of the April 15,
1990 event at Unit 1 and is still, open.
The inspector
concluded that the corrective action taken
as
a result of the
4'
28
Unit 1 event
was inadequate
to prevent recurrence.
The
inspector will track the licensee's
resolution of EER 90-NA-009
with an Inspector
Followup Item (529/90-23-01).
No violations of NRC requirements
or deviations
were
identified.
Missed Reactor Coolant
S stem Boron
Sam le - Unit 2 (93702)
On July 4, 1990,
a Reactor
Coolant System
sample
was not obtained
when, required.
During the
RCS heatup with the
plant in Mode
3 with charging
pump
CHA-P01 running,
a second
charging
pump,
CHE-P01,
was started. at 1:22
PM,
MST, resulting
in an increase
in the required
monitoring frequency,
from 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> to 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />,
in accordance
with Technical Specification
(TS) 3. 1.2.7.a
and Table 3. 1-5.
A
sample
had been taken at 1:20
PM and another
was required
by
3:52
PM.
However, another
sample
was not obtained until 4:20
PM.
The sample results
confirmed that
no unacceptable
dilution had occurred.
The licensee's
investigation of interim corrective actions
and
actions to prevent recurrence
is being documented
in Incident
Investigation Report (IIR) 3-2-90-026.
The licensee will.be
submitting an
LER for this issue
and the licensee's
corrective
actions will be reviewed at that time.
Reactor
Coolant
S stem
(RCS)
S ill - Unit 2 (93702)
On July 12,
1990,
a 30-gallon
from an
overpressurization
of a tygon tube which was
used to test the
newly installed Refuelinq Water Level Indication System
(RWLIS).
The
RCS was being pressurized
to 100 psia
when the
tygon tube ruptured.
The System Engineer
who discovered
the
source
shut valve 2RC-V204 to isolate the
RWLIS from the
RCS,
stopping the spill.
The spill was cleaned
up promptly.
Air
samples
confirmed
no airborne radiological problem developed
from the event.
The
RWLIS had been recently installed
and
had not been turned
over to operations
at the time of the event.
In this
condition, the operations
procedures
and plant drawings
had not
yet been
updated to reflect the plant modification.
The licensee
is documenting its investigation into this event
in Incident Investigation Report (IIR) 3-2-90-017.
This
investigation will address
the apparent
programmatic
weakness
regarding control of the implementation/retest
phase of
modifications.
This issue will be examined
by the inspector
after the licensee's
investigation is complete
(529/90-23-02).
Other related
comments
regarding
adequacy of system
documentation for operations
is found in paragraph
14 of this
report.
1
29
20.
21.
No violations of NRC requirements
or deviations
were
identified.
Reactor
Power Cutback - Unit 3 (93702)
On May 29,
1990, at 3:56
PM,
MST, Unit 3 was at 100 percent
reactor
power,
when the "A" Main Feedwater
Pump Turbine
(MFWPT)
tripped resulting in a Reactor
Power Cutback
(RPCB).
The
Reactor
Power Cutback caused
the selected
Control
Element
Assembly
(CEA) regulating groups
4 and
5 to fully insert in the
core
and setback
the Main Turbine to 60 percent,
per design.
After the insertion of the CEA's and the run back of the
Turbine, the CEA's were placed in Manual Sequential
control to
maintain temperature
and to stabilize
power in accordance
with
43A0-3ZZ43, Reactor
Power
Cutback (Loss of Feedpump).
Power
was s'tabi lized at approximately
52 percent.
The event
was initiated during calibration of the "A" MFWPT
high discharge
pressure
switches,
but was determined
by the
licensee
not to be
a
human performance deficiency.
Troubleshooting indicated that pressure
spikes
were induced in
the pressure
sensing lines during instrument valve
manipulation.
Engineering Evaluation
Request
EER 90-FT-007
was
generated
to evaluate
the pressure
spike
phenomena
and provide
recommendations.
The inspector
reviewed the licensee's
Incident Investigation
Report (IIR) 3-3-90-007
and followed up on several
issues
not
brought to closure in the report.
While troubleshooting is
still incomplete for two minor problems identified in the
report,
the licensee's
response
and corrective actions
appear
adequate
and it appears
that the open issues
are being
prudently addressed.
No violations of NRC requirements
or deviations
were
identified.
Cracked Reactor Tri
Breaker Arc Chutes - Unit 3 (93702)
While performing semi-annual
preventive
maintenance
on
a
reactor trip breaker,
the electricians
discovered
damage to two of the three arc chutes.
The electricians
who
initially removed the arc chutes
were certain that the chutes
were not damaged
when the breaker
was
removed from service,
however the foreman
has not been able to establish
when and
how
they were
damaged.
The system engineer told the inspector that
the
damage is what would be expected if the screws
securing the
were over-tightened.
The inspector
looked at the
damaged
and agreed with this conclusion.
Based
on
the electricians
assurance
that the arc chutes
were not damaged
when the breaker
was
removed
from service,
the system engineer
concluded that the arc chutes
did not fai 1 in service
and
an
evaluation of the
damage
on the operability of the breaker
was
not necessary.
The inspector
concluded that this event
30
suggests
a need for better control of maintenance
practices for
these
and similar breakers.
No violations of NRC requirements
or deviations
were
identified.
22.
OSHA Concern:
Non-ionizin
Radiation - Units
1
2 and
3 (93001)
A licensee
contractor raised
a concern
regarding non-ionizing
radiation effects associated
with Electro-Magnetic Fields
(ENF)
on personnel
occupying the Unit 2 Operations
Support Building
(OSB).
The inspector
passed this concern to the licensee.
The
licensee
asserted
that the location of the
OSB met
OSHA and
licensee
guidelines for stand off distances
from the nearby
high voltage lines.
The contractor also questioned
the effects of Radio Frequency
(RF) radiation
on workers in the vicinity of a microwave
transmitter.
This issue
was also passed
on to the licensee.
The licensee
determined that
RF power and energy densities
were
well within ANSI guide lines
and that
no health hazard exists.
No violations of NRC requirements
or deviations
were
identified.
23.
Review of Licensee
Event
Re orts - Units 1
2 and
3 (92700)
The following LERs were reviewed
by the Resident
Inspectors.
Unit 1:
a.
528/90-01-LO/Ll (Closed)
"En ineered Safet
Feature Actuation
ause
a
sa
son
one or
i
e
The licensee
event discussed
in this report was previously
discussed
in Inspection
Report 528/90-03,
paragraph
13.
This
LER is closed.
b.
528/90-03-LO (Closed) "Ino erabilit
Of All Lo
Power Channels
aces
an
>n
on i ion
o
e ine
ec naca
eci
1-
ca ions
C.
This licensee
event discussed
in this report was
previously discussed
in Inspection
Report 528/90-12,
paragraph
11.
This
LER is closed.
528/90-04-LO (Closed) "Technical
S ecification Surveillance
e u>remen
>sse
ue
o
roce ure
rror
This licensee
event involved surveillance testing
procedures
which test the remote
shutdown disconnect
switch and control circuit operability of Units 1,
2 and 3.
However, these
procedures
did not test the
remote
shutdown panel control of valve SIB-UV-659.
At the
II
31
time of discovery this surveillance
requirement only
applied to Unit 3 since Units
1 and
2 were in operational
modes to which this surveillance
did not apply.
The
licensee
entered
Action (b) of Technical Specification
(TS) 3. 3, 3. 5, immediately revised the surveillance
procedure,
performed the surveillance
on valve SIB-UV-659,
declared
the remote
shutdown
system operable,
and exited
Action (b) of TS 3.3.3.5.
Procedure
changes
were issued
for Units 1 and
2 and
TS component
change
record entries
were
made to ensure that completing this surveillance
would be
a Mode
2 restraint.
A 100 percent
review of the
TS 4. 3. 3. 5. b required equipment
was
made with the
surveillance
procedures
to ensure that
no other
components
were missed in the surveillance
test procedures.
This
LER
is closed.
The inspector
concluded that although Technical
Specifications
requirements
had
been violated, the
licensee's
actions
were prompt and considered
appropriate.
Thus, this violation is not being cited because
the
criteria of Section
V.G. 1 of the Enforcement Policy were
satisfied.
Unit
a.
2:
529/89-09-LO/Ll (Closed)
"Reactor Tri
Due to Partial
Loss of
orce
ow
This
LER reports
the reactor trip and safety injection
which occurred
on July 12,
1989.
This event
was also
documented
in Inspection
Report 529/89-30,
Paragraphs
11
and 12.
The
LER appears
to adequately identify the root
causes
of the plant response
problems,
though the root
cause of failure of the potential transformer
fuse failure
which resulted in the trip was not conclusively determined
due to insufficient data.
The corrective actions
and actions to prevent recurrence
were reviewed
and confirmed to have
been
implemented.
These actions
appear to adequately
address
the
known root
causes
of the event
and plant response
problems.
Unresolved
item 89-30-05,
concerning
adequacy of previous
corrective actions for problems with pressurizer
spray
valves
and steam
bypass control valves, is addressed
separately
in paragraph
2 of this inspection report,
This
item resulted
from the inspectors
questions
related to
these
system
responses
following the reactor trip and
which were not addressed
in the
LER.
This
LER is closed.
e
32
b.
529/89-10-LO (Closed)
"Reactor Tri
Due to Erroneous
Power
eve
s
na
This event
was previously inspected
and reported in
Inspection
Report 89-49,
Paragraph
10.
Three faults
resulted in the plant trip: 1)
a grounded
Pump
(RCP) speed
sensor,
2)
a faulty cable connector for
excore nuclear instrumentation
(NI), and 3) a failed
excore
NI linear calibrate switch.
The corrective
actions
described
in the
LER appear
adequate
to address
the deficiencies
and prevent
recurrence.
The temporary modification to the NI linear calibrate
switch was installed in all three. units.
Permanent
replacement
switches
have
been procured
and were installed
in Unit 2 during the current refueling outage.
Two preventive
maintenance
tasks
have
been developed for
the
RCP speed
sensors
for each unit,
as described
in the
LER.
The licensee
committed to performing an evaluation of
methods to ensure continuity of NI detector cables
and
associated
connectors
following maintenance
or test
activities.
Accordinq to the Engineering Evaluations
Department
System Engineer,
the evaluation is incomplete.
No method
has
been identified which will check continuity
when the reactor is at very low power levels.
Work orders
are in place to confirm that the signal strength is too
weak to detect while the reactor is shutdown.
However,
continuity can
be confirmed at low power levels during
reactor startup early enough to identify problems before
challenging safety systems.
Additionally, channel
. deviations result in alarms
even if the discontinuities
are not detected earlier.
The
sole purpose of this corrective action was to enable
the
licensee to repair deficiencies without affecting the
'plant startup
schedule.
This is not a safety concern.
This
LER is closed.
24.
Review of Periodic
and
S ecial
Re orts - Units 1
2 and
3
Periodic
and special
reports
submitted
by the licensee
pursuant
to Technical Specifications (TS) 6.9. 1 and 6.9.2 were reviewed
by the inspector.
This review included the following considerations:
the report
contained the information required to be reported by
NRC
requirements;
test results and/or supporting information were
consistent with design predictions
and performance
specifications;
and the validity of the reported information.
V )
'
33
Within the scope of the above,
the following reports
were
reviewed
by the inspector.
Unit 1
o
Monthly Operating
Report for May and June
1990.
Unit 2
o
Monthly Operating
Report for May and June
1990.
Unit 3
o
Monthly Operating
Report for May and June
1990.
No violations of NRC requirements
or deviations
were
i'dentified.
25.
Exit Meetin
(30703)
The inspector
met with licensee
management
representatives
periodically during the inspection
and held an exit meeting
on
July 19,
1990.
Additionally, a separate
exit meeting
was held
on June
29,
1990, regarding the inspection findings documented
in Paragraph
14 of this report.