ML17347B167
| ML17347B167 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 06/28/1989 |
| From: | Butcher R, Crlenjak R, Mcelhinney T, Schnebli G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17347B164 | List: |
| References | |
| 50-250-89-24, 50-251-89-24, NUDOCS 8907120302 | |
| Download: ML17347B167 (34) | |
See also: IR 05000250/1989024
Text
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UNITED STATES
NUCLEAR REGULATORY COMMISSION
'EGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323
Repor t Hos.:
50-250/89-24
and 50-251/89-24
Licensee:
Florida Power
and Light Company
9250 West Flagler Street
Niami,
FL
33102
Docket Nos.:
50-250
and 50-251
License Nos.:
and
Facility Name:
Turkey Point
3 and
4
Inspection
Conducted:
April 29,
1989 through
Nay 26,
1989
Inspectors:
L~Xt'
. ~M
R.
C. Butcher, Senior Resident
Inspector
~
.1c~
'
Da
e Signed
T.
F. Ncflhinney, Resident
Inspector
c.. P~
G. A.
Sc
neb i, Resident
Inspector
Approved by:
R
V. Crlenj
,
ection
Ch'
Division of Reactor Proje
s
Date Si
ned
Dat
Signed
at
Sig ed
SUNNARY
Scope:
This routine resident
inspector
inspection
entailed direct inspection at the
site in the
areas
of monthly surveillance
observations,
monthly maintenance
observations,
engineered
safety
features
walkdowns,
operational
safety
and
plant events.
Results:
One violation with two examples
was identified:
Failure to follow procedure
resulting in an inadvertent
drop of Rod N-8, paragraph
5.
Failure to follow
procedure resulting in a reactor trip during surveillance testing,
paragraph
10.
One non-cited violation was identified regarding
the use of the wrong calibra-
tion curves during
RTD calibration,
paragraph
10.
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Two unresolved
items** were identified:
Determine
the
cause of inadequate
clearance
control, paragraph
5.
Resolution of document control discrepancies,
paragraph
8.
Two Inspector
Followup Items
were identified:
Followup on concerns
with the
control
and
storage
.of hydrogen
on site,
paragraph
8.
Followup
on
the
resolution to correct the failure of MOV-4-751, paragraph
10.
.
- Unresolved items
are matters
about
which more information is required to
determine
whether they are acceptable
or may involve violations or deviations.
REPORT DETAILS
1.
Persons
Contacted
2,
Licensee
Employees
- J.
W. Anderson, guality Assurance
Supervisor
J. Arias, Assistant to Plant Manager
- L. W. Bladow, Plant guality Assurance
Superintendent
- J. E. Cross,
Plant Manager-Nuclear
- R. J. Earl, guality Control Supervisor
T. A. Finn, Training Supervisor
S. T. Hale, Engineering Project Supervisor
K. N. Harris, Site Vice President
- R. J. Gianfrancesco,
Maintenance
Superintendent
- V. A. Kaminskas,
Reactor
Engineering Supervisor
J.
A. Labarraque,
Senior Technical Advisor
R.
G. Mende, Operations
Supervisor
L. W. Pearce,
Operations
Superintendent
- S. guinn, Acting Radiochemist
- F. H. Southworth, Assistant to Site
- R. Steinke,
Chemistry Supervisor
J..C. Strong, Mechanical
Department
Supervisor
- K. Van Dyne, Acting Regulatory
and Compliance Supervisor
M. B. Wayland, Electrical
Department
Supervisor
J.
D. Webb, Operations
- Maintenance
Coordinator
~
~
Other
licensee
employees
contacted included
construct~on
craftsman,
engineers,
technicians,
operators,
mechanics,
and electricians.
- Attended exit interview on May 26,
1989.
Note
An Alphabetical
Tabulation of acronyms
used
in this report is
listed in paragraph
13.
Followup on Pr'evious
Inspection
Findings
{92702)
e followin
noncompliances
to assure
that
A review
was
conducted
of the
g
d
lted in conformance
if'i
f corrective aetio
wa
s were
ade uately implemented
an
resu
e
i
with regulatory
require ments.
Ver
ica
on
o
ion and discussions
with licensee
achieved
through record r'eviews, observat
on an
s
c
nnel.
Licensee
correspondence
was
evaluated
to ensure
a
e
d th t
rrective actions
were implemented within
responses
were timely an
a
corr
the time periods specified in the r'eply.
-251 83-39-04,
Failure to
remove old seal
1
d fl
t
'tt
transmitters.
This concern
invo ve
ow
drawing
5610-T-E-4503,
Reactor
Coolant
Pump
11
d
The licensee
generated
PC/M 84-104,
Details,
but were still insta
e
.
e
Seal
Leakoff No.
1 Instrumentation,
which removed
the flow trans-
mitters.
The
PC/M was
completed
and turned over to plant operations
on
September
5, 1986.
This item is closed.
Followup on Inspector
Followup Items
( IFIs)
(Closed)
IFI 50-250,251/85-37-03.
Contr'ol
Room Noise Level
Increase
due
to Ceiling Insulation
Removal.
The licensee
installed
a carpet in the
control
room to aid in noise reduction.
Engineering
recommended
a carpet
with specifications
on weight, height
and Noise. Reduction Coefficient.
However,
the
carpet
installed
did not
completely
meet
engineerings
specifications.
Therefore,
a noise reduction effect study
was
performed
in March
1988
by
a contractor.
The study determined
that the carpet
reduced
the
noise
level
by approximately
3 decibels
(db).
The noise
levels
measured
during
normal plant operation
were
found slightly below
the
NRC criterion of 65 db maximum.
This item is closed.
(Closed)
IFI 50-250,251/85-02-04.
Engineering
to Evaluate
the Monitoring
of Loss of Control Voltage at the Emergency
Diesel
Generators
(EDGs).
The
licensee
generated
Plant Change/Modification
(PC/H)86-185, Annunciation
In Hain Control
Room
On
Loss of
EDG Control
Power,
due to concerns
addressed
in
LER 50-250,251/85-02.
This
PC/M added
annunciation
in the
main control
room for the
A and
B
EDGs starting circuitry.
In order to
reduce
the probability of blowing fuses,
the non-resistored
indicating
lights were replaced
with resistored
indicating lights at the
A and
B
engine panels.
The
PC/M was
implemented
on March 14,
1989 and March 21,
1989, for A and
B EDGs respectively.
This item is closed.
Onsite
Followup
and
In-Office Review of Written Reports of Nonroutine
Events
(92700/90712)
The
Licensee
Event
reports
(LERs)
discussed
below
were
reviewed
and
closed.
The inspectors
verified that reporting requirements
had
been met,
root
cause
analysis
was
performed,
corrective
actions
appeared
appropriate,
and generic applicability had
been considered.
Additionally,
the
inspectors
verified that
the
licensee
had
reviewed
each
event,
corrective actions
were implemented, responsibility for corrective actions
not fully completed
was clearly assigned,
safety
questions
had
been
evaluated
and resolved,
and violations of regulations
or TS conditions
had
been identified.
When applicable,
the criteria of 10 CFR 2, Appendix C,
were applied.
(Closed)
LER 50-250/89-05,
Automatic
AFW Pump Actuation Following Attempt
to Start Steam Generator
Hain Feedwater
Pump.
This event
was discussed
in
detail in Inspection
Report 50-250,251/89-06
and the corrective actions
required are complete.
This
LER is closed.
(Closed)
LER 50-250/89-04,
Reactor Trip Due to Defective Procedure
During
Steam
Generator
Protection
Channel
Testing.
The event discussed
in this
LER was identified previously as Violation- 50-250,251/89-06-02
and will be
followed through closeout of the violation.
This
LER is closed.
5.,Monthly Surveillance Observations
(61726)
The inspectors
observed
TS required
surveillance
testing
and verified:
That the test
procedure
conformed to the requirements
of the TS, testing
was performed in accordance
with adequate
procedures,
test instrumentation
was calibrated,
limiting conditions for operation
(LCO) were met, test
results
met
acceptance
criteria
requirements
and
were
reviewed
by
personnel
other than the individual directing the test, deficiencies
were
identified,
as appropriate,
and were properly reviewed
and resolved
by
management
personnel
and that
system
restoration
was
adequate.
For
completed tests,
the inspectors verified that testing frequencies
were met
and tests
were performed
by, qualified individuals.
The
inspectors
witnessed/reviewed
portions
of
the
following test
activities:
4-PMI-028.3
RPI Hot Calibration,
CRDM Stepping Test,
and
Rod
Drop Test.
Unit 4 Alternate
Shutdown
Panel
Performance
Test.
0
4-0SP-075.1
Train
1 Operability
Verification.
On
May 7,
1989,
the licensee
experienced
an unexpected
drop of Rod
M-8.
The licensee
was performing 4-PMI-028.3,
RPI Hot Calibration,
CRDM Stepping Test and
Rod Drop Test, revision dated 3/30/89, Section
6.3,
CROM Stepping
Test for
Rod
H-12,
when
Rod
M-8 dropped.
Investigation
by the
ISC department
found that .the moveable coil fuse
for rod M-8 was pulled, while stepping
rod H-12, which caused
rod M-8
to drop unexpectedly.
A review of Section 6.3 did not identify any
provision for removing the moveable
gripper coil fuse for any
during the performance of this section.
However, the next section of
the procedure,
Section 6.4,
Rod Drop Test, did provide for removal of
these
fuses for the bank under test,
which included both rods M-8 and
H-12.
Discussion with personnel
involved in the test indicated that
miscommunication
between
personnel
in the Control
Room and the Motor
Control
Center
(where the fuses
were pulled) caused
the personnel
to
mistakenly
proceed
into the rod drop section of the procedure
which
caused
the event.
TS 6.8.1 requires
that written procedures
and
administrative
policies
shall
be
established,
implemented
and
maintained that meet or exceed
the requirements
and recommendations
of Appendix A of USNRC Regulatory
Guide 1.33
and Sections
5.1 and 5.3
of ANSI N18.7-1972,
'Contrary to the above,
licensee
personnel
failed
to follow procedure
4-PMI-028.3
by proceeding
to Section 6.4 of the
procedure,
prior to
completing
Section
6.3,
resulting
in
an
inadvertent
drop of Rod M-8.
This is identified as the first example
of Violation 50-250,251/89-.24-01.
b.
The inspectors
witnessed
the performance
of TP-522, Unit 4 Alternate
Shutdown
Panel
Performance
Check,
on May 24 and 25,
1989.
The test
was being performed to ensure
the unit could be shutdown from outside
the control
room utilizing the Alternate
Shutdown
Panel
and personnel
at various locations
throughout the plant to perform local operation
of various
components.
The test started
with T
AVG stable
between
545
and
550 degrees
F, being controlled
by control
room personnel.
The
normal shift complement
was
to
remain
in the control
room
throughout .the test with instructions
to abort the test
and
resume
control
of the
plant if an
abnormal
situation
developed.
An
additional shift complement
dedicated
to the test
evacuated
the
control
room and proceeded
to their assigned
stations.
At this time
control of the systems'nd
components
required to place
the plant in
a cold shutdown condition was shifted to the Alternate
Shutdown
Panel
and
a cooldown
was
commenced.
The initial cooldown
was conducted
by
using
"8" "Auxiliary Feedwater
Pump
and
dumping
steam
to the
atmosphere.
When attempting to place
the plant on
RHR to cooldown to
less, than
300 degrees
F, MOV-4-751
(RHR suction isolation valve from
~
loop
"C" hot leg)
would not open.
The test
was
terminated
and
control
of the
plant
was
returned
to
the
control
room
where
conditions
were maintained
stable until the
problem with MOV-4-751
was
resolved
and testing
could
be
resumed.
See section 10,'Plant
Events,
for
a discussion
on 'this valve
problem
on
May 23,
1989.
Testing
was
resumed
on May 24,
1989,
and the plant was cooled
down to
less
than
300 degrees
F, using the
RHR system.
At that time the test
was completed satisfactorily
and control
was returned to the control
room.
The inspectors
consider that the test went very well with all
systems
and components
functioning as required, with the exception of
MOV-4-751.
Minor deficiencies
were noted
by the inspectors
and the
licensee
and were
documented
in PTN-OPS-89-154,
dated
May 30,
1989,
with the appropriate corrective actions to be taken
as assigned
to the
responsible
departments.
co
On
May 22,
1989,
the
licensee
performed
4-0SP-075.1,
Auxiliary
Train
1 Operability Verification Test, after repairs
were
made
on
Flow Control
Valves
(FCV)
2817
and
2818.
The test
was
unsatisfactory
due to
FCV-2818 failing the test.
The test
was
reperformed after
I&C worked
on the valve.
During the test the
C
Steam
Generator
(SG) did not receive
AFW flow.
Investigation
by the
licensee
revealed
clearance
4-89-5-149
was not released
by I&C.
This
clearance
isolated
FCV'-2818, which feeds
the
C SG.
The licensee
was
investigating
the
cause of this event at the
end of the inspection
period.
Therefore,
this
item will be tracked
as
Unresolved
Item
50-250,251/89-24-04.
-
6.
Engineered
Safety Features
Walkdown (71710)
The inspectors
performed
an inspection
designed
to verify the operability
of the
Emergency
Diesel
Generators
and the Safety Injection System to
support
reactor
startup.
The
following
cr iteria
were
used,
as
appropriate,
during this inspection:
~4 H.
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a.
System
lineup
procedures
matched
plant
drawings
and
as built
configuration.
b.
Housekeeping
was adequate
and-appropriate
levels of cleanliness
were
being maintained.
c.
Valves in the
system
were correctly installed
and did not exhibit
signs of gross
packing
leakage,
bent
stems,
missing
handwheels
or
improper 'labeling.
d.
e.
Hangers
and supports
were
made
up properly and aligned correctly.
Valves in the flow paths
were in the correct position
as required
by
the
applicable
procedures
with power available
and
valves
were
locked/lock wired as required.
Local
and
remote
position
indication- were
compared
and
remote
instrumentation
was functional.
7.
g.
Major system
components
were properly labeled.
No violations or deviations
were identified in the areas
inspected.
Monthly Maintenance
Observations
(62703)
Station
maintenance
activities
on safety related
systems
and
components
were
observed
and
reviewed
to ascertain
that
they were
conducted
in
accordance
with approved
procedures,
regulatory guides,
industry codes
and
standards,
and in conformance with TS.
The following items
were considered
during this review,
as appropriate:
That
LCOs were met while components
or systems
were
removed
from service;
approvals
were
obtained
prior to initiating work; activities
were
accomplished
using
approved
procedures
and were inspected
as applicable;
procedures
used
were
adequate
to control
the activity; troubleshooting
activities
were controlled
and repair records
accurately
reflected
the
maintenance
performed;
functional
testing
and/or
calibrations
were
performed prior to returning
components
or systems
to service;
gC records
were maintained;
activities
were
accomplished
by qualified personnel;
parts
and materials
used
were properly certified; radiological controls
were properly implemented;
gC hold points
were established
and observed
where
required;
fire prevention
controls
were
implemented;
outside
contractor
force activities
were controlled
in accordance
with the
approved
gA program;
and housekeeping
was actively pursued.
The inspectors
witnessed/reviewed
portions of the following maintenance
activities in progress:
Troubleshooting
LT-4-474 and LT-4-475, "A" Steam Generator
Level
Channels After Failure.
Troubleshooting
of
PCV-4-456,
to
determine
cause
of
spurious
opening.
Replacement
of
FCV-4-489
and
FCV-4-499,
"B" and
"C"
Steam
Generator
Bypass
Valves.
Troubleshooting
MOV-4-751 failure to open.
See
section
10,
Plant Events,
dated
May 23,
1989.
Troubleshooting
Unit 4
AFW Flow Control Valves.
No violations or deviations
were identified in the areas
inspected.
8.
Operational
Safety Verification (71707)
The inspectors
observed
control
room operations,
reviewed applicable logs,
conducted
discussions
with control
room
operators,
observed
shift
turnovers
and confirmed operability of instrumentation.
The inspectors
verified the operability of selected
emergency
systems,
verified that
maintenance
work orders
had
been
submitted
as required
and that followup
and prioritization of work was
accomplished.
The inspectors
reviewed
tagout records,
verified compliance with TS
LCOs and verified the return
to service of affected
components.
By observation
and direct interviews, verification was
made that
the
physical security plan
was being implemented.
Plant
housekeeping/cleanliness
conditions
and
implementation
of
radiological controls were observed.
Tours of the intake structure
and diesel, auxiliary, control'nd turbine
buildings were
conducted
to observe
plant equipment conditions
including
potential fire hazards, fluid leaks
and excessive vibrations.
The inspectors
walked
down accessible
portions of the following safety
related
systems
to verify operability and proper valve/switch alignment:
A and
B Emergency Diesel
Generators
Control
Room Vertical Panels
and Safeguards
Racks
Intake Cooling Water Structure
4160 Volt Buses
and 480 Volt Load and Motor Control Centers
Unit 3 and
Platforms
Unit 3 and
4 Condensate
Storage
Tank Area
Area
Unit 3 and
4 Main Steam Platforms
a ~
In response
to
Hydrogen Storage
on the
Roof 'of the .Control
Room,
the resident
inspectors
were requested
to
canvass their facilities to determine:
Distance
from the
storage facility to the nearest
safety-related
structure or air intake.
Maximum volume of gaseous
or liquid hydrogen
stored
on site in
standard
cubic feet or gallons respectively.
The residents
obtained
the
above
information from the licensee
and
forwarded it to the region
as requested.
Based
on the information
collected
and
concerns
previously
expressed
to the licensee,
the
following concerns
with hydrogen
storage
and control of hydrogen
on
site will be followed up for resolution
as Inspector
Followup Item
50-250,251/89-24-02.
( 1)
Administrative controls
or limits have
not
been
established
on the
amount of hydrogen that could
be located in the identi-
fied hydrogen storage
areas.
(2)
The
back-up
storage trailer location is within 5 feet
of the Unit
3
RWST and about
55 feet from the Unit 4
RWST.
Based
on the resident
inspectors
concerns,
the back-up hydrogen
storage
trailer
was
previously
removed
from this location.
However,
there
were
no administrative
controls
to
prevent
locating the hydrogen trailer in this location.
(3)
The
Gas
House,
which stores
gas cylinders, is within 14
feet of the safety injection
pump suction line from the
RWST for
both Unit 3 and Unit 4.
The
Gas
House is also about
15 feet
from the Unit 3
RWST and
45 feet from the Unit 4
RWST.
(4)
An administrative limit on the quantity of hydrogen that could
be brought
on site
has not been established.
b.
While preparing'o
inspect controlled
documents for completeness
and
the latest revision, the inspectors
determined
there
was insufficient
information available
from document control to identify the drawings
required
at
a
given location
and their latest
revision
number.
Subsequently,
document control
developed
a list of drawings required
at controlled drawing stations
with the latest revision number.
The
inspectors
checked
various
procedures
and
drawings
at
the
TSC,
Control
Room,
and
IKC Department
to determine if.they
were complete
and
up to date.
The following results
were -found:
(1)
The following discrepancies
were found at the TSC.
AP 0103.18
and
AP 0103.36 were missing.
OP-0204.2
had revisions
dated July 26,
1988
and April 26,
1989 in the file.
HP 11550.70
was in the file but has
been superseded.
(2)
The
following discrepancies
were
found
in drawing
control
document
No.
10 in the control
room.
Drawing 5610-T-E-4062,
sheet
3,
had revisions
57
and
58
filed, in the book.
Drawing
5610-T-E-4062/R18,
sheet
5,
revision
1,
and
5610-T-E-4534,
sheet
1, revision
39 were missing.
The following obsolete
red line drawings
were still in the book
along with the current drawing.
5610-T-E-4501/R74,
sheet
1, Rev. 0;
5610-T-E-4505/R25,
sheet
1, Rev. 0.
5610-T-E-4505/R3,
sheet
5, Rev. 0.
5610-T-E-4512/R68,
sheet
1, Rev. 2.
5610-T-E-4512/R25,
Sheet 2, Rev.
1.
5610-T-E-4531/R48,
sheet
1, Rev. 0.
5610-T-E-4534/R18,
sheet
2, Rev.O.
5610-T-E-4535/Rll, sheet
1, Rev.O.
Drawing 5610-T-E-4532,
sheet
1,
had revision
7 and
8 filed
in the book.
(3)
The inspector
examined
the
back log of unfiled documents
in the
ISC Department
and found documents
dating back to February
1989
that
had not been filed nor had the cover sheet
been returned to
document control.
Administrative
Procedure
(AP)
0190.86,
Document
Control,
dated
October 27,
1988,
provides instructions for the control of documents
(drawings
and
procedures).
AP 0190.86,
paragraph
5.5,
states
the
holder of
a controlled
document
is responsible
for the
proper
updating
and maintenance
of controlled
documents
in their custody,
the
prompt return of dated
and signed receipt
acknowledgement
cover
letters,
and
superseded
controlled documents.
Paragraph
8.1.7 of AP
0190.86
requires
the
document
holder complete
the cover letter
and
return it to Document Control within 30 days
along with superseded
documents.
The findings
noted
above
indicate this is not being
accomplished.
guality Instruction (gI) 6-PTN-1,
Document Control, dated
March 22,
1988,
applies
to all
controlled
documents
except
drawings.
f16-PTN-2, is for dr'awing control but has not been
issued
to date.
QI6-PTN-1,
paragraph
5.3.5,
states if the
document
cover letter is
not received
by document control within 30 days,
and if the followup
letter is not received
by document control within 10 days,
document
control
shall
retrieve
the holder's
document
and
remove it from
distribution list if not updated
immediately.
This action
has
not
been
implemented.
QI6-PTN-1,
paragraph
5.4,
states
document control shall
prepare
a
quarterly status
report of controlled documents
specifying the latest
revision
to
be
sent
to
each
holder.
Holders shall verify the
currentness
of their documents
and request
updates.
This action
has
not been
implemented.
'I6-PTN-. 1, paragraph
5.7, states
that document control shall perform
an annual
review of all controlled
documents
(that have their master
maintained
in document control) and problem areas
shall
be corrected,
documented,
and reported to the holders
manager.
This action
has not
been
implemented.
The Quali'ty Assurance
(QA)
group
has
an audit in progress,
Audit
QAO-PTN-89-988, that covers
the
areas
of document control in which
discrepancies
were noted
by the inspectors.
The resolution of Document
Control
discrepancies
will
be
followed
as
Unresolved
Item
50-250,251/89-24-03,
pending completion of the
QA audit.
No violations or deviations
were identified in the areas
inspected.
9.
Plant Startup from Refueling
(71711)
(61709) '(61710)
The
inspectors
witnessed/reviewed
selected, activities
related
to the
Unit 4 Startup
From Refueling Cycle XII.
These
reviews
were
performed
to verify that
the
licensee
properly restored
systems
effected
during
the
outage
and
to ascertain
whether
plant startup
and
core
physics
tests
were conducted
in accordance
with approved plant procedures.
a ~
The
inspectors
performed
a walkthrough of the
Emergency
Diesel
- Generators
(EDG)
and
the
Safety
Injection
System
(SIS).
The
following completed
procedures
were
reviewed to verify that these
systems
were restored
properly:
O-OSP-023.1
Diesel
Generator
Flowpath Verification.
4-OP-062
Safety Injection.
The
inspectors
did not identify any discrepancies
in .the
areas
reviewed.
b.
The inspectors
witnessed
the licensee's
approach
to initial criti-
cality on
May 19,
1989.
Operating
Procedure
(OP) 0204.3, Initial
Criticality After Refueling,
dated
March 24,
1989,
contained
the
instructions
for achieving initial criticality, establishing
the
upper limit of the neutron flux level for zero
power testing
and to
verify proper operation of the reactivity computer.
10
Based
on this determination,
in order to ensure
the reactor
was operated
below nuclear
heating,
the test
range
was established
in the next lower
decade. 'he
reactivity computer
was
then
checked
and calibrated
in
accordance
with Appendix
B of the procedure
and the acceptance
criteria
was successfully
met for the positive and negative
period checks.
Test
personnel
performed
a statistical
check
of the
source
range
instruments
in accordance
with Appendix
D of OP 0204.3.
The licensee
used
the Chi-Squared
method with an acceptance
criteria of between
16 and 45.7.
The results for Source
Range
Nuclear Instruments
(SRNIs)
31 and
32 were
35.68
and 39.735 respectively.
The testing
was
commenced
by withdrawing the control
rods until Control
Bank
(CB)
D was at
160 steps.
The
was then diluted at
100
gpm until
the reactor
was approximately
2X shutdown.
Thereafter,
the dilution rate
was
decreased
to 50
gpm.
The Inverse
Count Rate Ratio
( ICRR) was plotted
versus
the primary 'water added until the
ICRR was approximately 0. 10.
The
dilution was terminated at this time.
Criticality was not achieved
during
the subsequent
mixing, therefore,
the operators
withdrew control
bank
D in
15 step
increments.
The r'eactor
went critical at 3:50 p.m.
on
May 19,
1989 with
D bank at
190 steps
and boron concentration at 1520
ppm.
Test personnel
next established
the upper limit of neutron flux level for
all
zero
power physics testing.
Appendix
A of the procedure
provided
instructions for the determination
of the nuclear
heating
range.
The
results
were as follows:
Reactivity Computer
Intermediate
Range
Channel
N-35
Intermediate
Range
Channel
N-36
3.4lx10-7
amps
4.54x10-7
amps
4.77xl0-7
amps
C.
Operating
procedure
0204.5,
Nuclear Design Check Tests
During Startup
Sequence
After Refueling,
dated
March 24,
1989, specified
the Refuel-
ing
Outage
Test
Sequence
from initial criticality to full power
operation.
The inspectors
witnessed/reviewed
the
low power tests
which were completed prior to the end of this inspection period.
The
remaining tests will be reviewed during .escalation
of power.
The
tests
reviewed included:
Determination of All Rods Out
(ARO) Critical Boron Concentration.
Determination of the Isothermal
Temperature Coefficient.
Determination of Control
Rod Group Worths.
Determi nati on of Differenti al
Boron Worth.
(a)
The
boron endpoint
on
Bank
D was performed in accordance
with
Appendix
A of
the
procedure.
The
ARO critical
concentration
was
measured
at
1538
ppm,
which
was
34
ppm
different
from the
design
value.
This
met
the
acceptance
criteria of +50
ppm difference.
(b)
The
Isothermal
Moderator
Temperature
Coefficient
(ITC)
was
determined
in accordance
with Appendix
B of the procedure.
The
measured
ITC was -.880
pcm/degrees
F which met the acceptance
criteria of +2 pcm/degrees
F of the
design
value -1.7
pcm/
degrees
F.
The Moderator
Temperature
Coefficient
(MTC)
was
determined
to
be +.92
pcm/degrees
F which met the
acceptance
criteria of +5 pcm/degres
F.
(c)
The rod worths
were determined
in accordance
with Appendix
D,
Rod Worth Verification by
Rod
Swap Method.
The design report
determined
Control
Bank
(CB)
C
had
the
greatest
worth,
'herefore,
this bank was the reference
bank.
The integral worth
of
CB
C
was
measured
as
1329
pcm which met the
acceptance
criteria of +10 percent difference from the predicted
integral
worth.
The integral worths of each
bank were measured
and the
acceptance
criteria of +15 percent difference from the. predicted
integral worth was met.
The
sum of all the control rod worths
was
measured
as
5861
pcm/degrees
F, which met the acceptance
criteria of +10 percent of the predicted value.
(d)
The Hot 2ero
Power
(H2P) Differential Boron Worth was calculated
using
Control
Bank
C
as
recommended
by
Step
8.7 of the
procedure.
The differential
boron worth was
measured
at 9.6
pcm/ppm which was the
same
as the predicted value.
No violations or deviations
were identified in the areas
inspected.
10.
Plant Events
(93702)
The following plant events
were reviewed to determine facility status
and
the
need for further followup action.
Plant
parameters
were evaluated
during transient
response.
The significance of the event
was evaluated
along with the 'performance
of the appropriate
safety
systems
and
the
actions
taken
by the licensee.
The inspectors
verified that required
notifications were
made to the
NRC.
Evaluations
were performed relative
to the
need for additional
NRC response
to the event.
Additionally, the
following issues
were
examined,
as
appropriate:
details
regarding
the
cause of the event;
event chronology; safety
system performance;
licensee
compliance
with approved
procedures;
radiological
consequences, if any;
and proposed corrective actions.
12
On May 3,
1989, at 1:45 p.m., with Unit 3 in Mode
5 and Unit 4 in Mode 3,
a
loss
of the
Emergency Notification System
(ENS)
communications
was
identified.
The licensee notified the
NRC in accordance
with 10 CFR 50.72
(b)( 1)(v).
The local
phone
company
was contacted
concerning
the failure
and the required
communications
were re-established
at 2:45 p.m.
On May 4, 1989, at 4:50 p.m., with Unit 4 in Mode 3,
PORV PCV-4-456 opened
momentarily then reclosed
causing
a
45 psig reduction
in
RCS pressure.
RCS pressure
was at 2235 psig which was well below the
PORV setpoint of
2335 psig.
The
RCO closed
the
PORV block valve
(MOV-4-535) and
removed
power to it as
directed
by ONOP-1208.1.
Subsequent
troubleshooting
determined
the
spurious
valve actuation
was
caused
by
a failure. of
PC-4-445A,
a setpoint
comparator
in the
PORV's control loop.
The faulty
comparator
was
replaced
and
the valve
was
returned
to service.
The
licensee
is currently conducting
root cause
analysis
to determine
the
cause of the failure..
On
May 5,
1989,
at
1:52 a.m., with Unit 4 in Mode 3,
and with control
banks
C
8
D withdrawn,
a Reactor Protection
System
(RPS) trip occurred.
While performing 4-SMI-071.4,
Steam
Generator
Protection
Set III Analog
Channel
Test,
the
Reactor
Trip .Breakers
(RTBs)
open'ed
when bistable
BS-4-446-1
was placed in the Test position in accordance
with step 6.2.3.1
of the
procedure.
This
simulated
a reactor
power greater
than
10K
enabling the
P7 trips.
The
RTBs opened
due to the presence
of the Turbine
Stop Valves Closed signal
which was introduced
due to leads
being lifted
to the
Stop
Valve limit switches.
All systems
functioned
as
designed.
The
sequence
of events
was repeated
and the
same results- were obtained.
The procedure
was
stopped,
notification was
completed
per
(b)(2)(ii),,and
an
Event
Response
Team
(ERT)
was
convened
to review the
incident.
Although the turbine
stop
valves
were
open
as required
by
procedure
4-SMI-071.4,
the lifted leads
(4T10
and 4Tll) prevented
the
"Turbine Stop
Valve Closed" contacts
in the
RPS= circuitry from closing.
This in turn gave
th'e
a false signal indicating that the turbine stop
valves
were closed.
When bistable
BS-4-446-1
was placed in the tripped
position,
indicating
power
greater
than
10K, with the
stop
valves
indicating closed,
a reactor trip occurred.
The
ERT formed
a task
team to
determine.
the
root
cause
for the li.fted leads
not
being
relanded.
However,
the
team could find no documentation
or information identifying
that the leads
were lifted. 'S 6.8. 1 requires that written procedures
and
administrative policies shall
be established,
implemented
and maintained
that meet or exceed
the requirements
and'econmendations.
of Appendix A of
USNRC Regulatory
Guide 1.33
and Sections
5.1
and 5.3 'of 'ANSI N18.7-'1972.
O-GME-102.1, Troubleshooting
and Repair Guidelines,
step 3. 1 requires that
a
PWO shall
be
issue'd prior to commencing
work and step 6.2.7 requires
that all lifted leads
be
documented
and
independently verified.
Steps
6.2.9
and 6.3 .8 require all lifted leads
be reconnected
and independently
verified.
O-ADM-715, Maintenance
Procedure
Usage,
steps- 5.5.2
and 5.5.3,
provide instructions for independent. verification of lifting and relanding
13
Contrary to the
above,
to the turbine stop valve limit
switches
were lifted without adequate
controls which resulted
in a reactor
trip during surveillance'esting.
This is identified
as
the
second
example of Violation 50-25,251/89-24-01.
On May 8,
1989, at 6:00 p.m., with Unit 4 in Mode 3, the unit was placed
in Technical Specification 3.0. 1 due to both the "B" and
"C" loop
T AVG
Resistance
Temperature
Detectors
(RTDs)
being
out of service.
The
elements
(TE-422
and
TE-432)
were
placed
out of service
when the
IKC
department
discovered
that
the
wrong calibration
data
was
used
to
calibrate
the
RTDs.
The Plant Supervisor-Nuclear
placed
the unit in TS 3.0. 1
as required
by Table 3.5-2,
item 1.5, which requires
the High Steam
Flow in two-out-of-three
steam lines with Low T
AVG or Low Steam
Line
Pressure
channels
be functional.
The bistables for TE-422 and TE-432 were
tripped in accordance
with ONOP-208. 14
and
the
NRC
was notified of the
event
as required
by 10 CFR 50.72(b)(l)(i)(A).
The licensee's
investiga-
tion into the
event
determined
that
PC/M 88-234,
performed
during the
current Unit 4 outage,
required that the
RCS temperature
be replaced.
When the
new
RTDs were received
on site,
the
new response
curves for the
RTDs to be installed in Unit 4 were obtained
and included into procedures
to assure
the data
was readily available
when required for testing after
installation.
During pre-installation
testing
of the
RTDs it was
determined'hat
three of them did not meet the acceptance
criteria and
89-0250
was initiated to document
the deficiency.
The
NCR was disposi-
tioned
by allowing the
use of three
RTDs that were to be used in Unit 3.
.However,
the calibration
curves for the Unit 3
RTDs that were
used
in
place of the defective Unit 4 RTDs were not included into the calibration
procedures.
Therefore,
when
the
were calibrated,
they
were
calibrated
to the
wrong curves.
The licensee
took prompt corrective
action
when
the discrepancy
was identified
and corrected
the affected
procedures.
verified that the
new curves
contained
in the
updated
procedures
were for the. specific
RTDs installed
and the circuitry
was
recalibrated
to the
new curves.
has
reviewed
the
assumptions
contained
in the Safety Analysis against-the
calibration data
of the installed
RTDs.
This review concluded
that the installation
correction
values for the
RTDs were within the assumptions
contai.ned
in
the Safety Analysis.
Therefore,
the "8" and
"C" loop
T AVG indication
was
not Out-of-Service
due to being Out-of-Calibration.
Based
on this
information it was
concluded
no Technical
Specification
(TS) violation
existed
and
need
not to
have
been
entered.
The evolution
described
above constitutes
a violation of TS 6.8.1 in that
procedures
were not adequately
implemented
or maintained to ensure
that the correct
RTD calibration
curves
were
included
in the appropriate
procedures.
It was determined this violation meets
the criteria of 10 CFR 2, Appendix
C, therefore,
no notice of violation will be issued,
This item is identi-
fied as non-cited violation (NCV) 250,251/89-24-06.
14
On
May 9,
1989, with Unit 4 in Mode 3, the unit experienced
isolation which was reported to the
NRC under
The
unit was in the process
of cooling
down from Mode
3 to Mode 4 with one
level
channel
(LT-4-475) for the
"A" steam generator
out of service, with
its bistables
tripped,
due to
a level deviation of greater
than
10'K.
During the
cooldown
an additional
channel
for the
"A" steam
generator
(LT-4-474) failed high which made
up the necessary
two out of three .logic
to
cause
a
isolation signal for steam
generator
"A".
All
systems
functioned
as required.
Subsequent
troubleshooting of the level
transmitters
indicated the sensing
lines contained
some sludge which was
flushed
from
the
lines
and
the
transmitters
were
successfully
recalibrated.
The licensee
considers
the
sludge
was
caused
by 'sludge-
lancing of the
steam
generators
during the outage
and not performing
a
flush of lines
coming
from the
steam
generator.
The licensee
stated
future sludge-lancing
evolutions
would require
an adequate
flush of the
lines.
On May 11,
1989,
the licensee
conducted
a cooldown of Unit 4 from Mode 3
to
Mode 4, to facilitate repair of FCV-4-489
8 and
C,
steam
generator
bypass
valves.
During operation
in Mode
3 the operators
noted
that seat
leakage
past the valves
was excessive
and they felt it would be
impossible
to control temperature
within the narrow band required during
the
upcoming
post refueling
low power physics testing.
Therefore,
the
licensee
cooled
down the unit to less
than
350 degrees
F and replaced
the
valves.
The valves
were
replaced
due to
damaged
internal
valve
body
threads
which retain
the internal throttling cage
assembly.
These
same
internal
threads
were previously repaired
by weld buildup and remachining
in accordance
with NCR 86-083 in March of 1986.
On
May 14,
1989,
the
licensee
experienced
another
loss of Emergency
Notification System
(ENS)
communications.
The event
occurred
at
1:32
a.m.,
when
a
4A Primary Water
Pump Motor fault occurred which tripped the
"D" MCC Breaker
Number 0832,
removing incoming power from the
MCC.
This
in turn caused
a loss of power to lighting panel
Number 33A de-energizing
Breaker
Number 9, which removed
power
from the
ENS phone.
The licensee
reported
the event in accordan'ce
with 10 CFR 50.72(b)(l)(v) upon discovery
of the loss of ENS.
On
May 23,
1989,
during the
performance
of TP-522,
Unit 4 Alternate
Shutdown
Panel
Performance
Check,
MOV-4-751
(RHR suction isolation valve)
failed to
open.
The
licensee
made
a significant event report in
accordance
with 10 CFR 50.72(b)(2)(ii'i)(B).
After the valve failed to
open
due to the
breaker tripping
on thermal
overload,
two additional
attempts
were
made with identical
results.
The licensee
then
shut
MOV-4-750 (the
upstream
isolation
valve to
MOV-4-751) to
reduce
the
differential pressure
across
MOV-4-751.
A final attempt
was
made to open
the valve and it again tripped on thermal overload.
Maintenance
personnel
then partially opened
the valve manually,
which was very hard to operate
until the valve disc partially cleared
the seats,
indicating the valve was
15
binding during the inital porti'on of travel.
The valve
was then
MOVATS
tested
successfully
and
cycled
several
times with
no
problems
being
identified.
The inital indication is that
the valve
may
have
been
"pressure
bound",
a
phenomenon
by which pressure
is induced
between
the
discs of the valve.
This, in turn,
causes
the discs
to exert greater
pressure
against
the seats.
This causes
the valve to bind until the discs
partially clear
the
seat
area
during opening.
This would allow the
internal
pressure
between
the discs
to be relieved thus eliminating the
"pressure
binding".
The licensee
is currently performing tests
on the
valve
and discussing
the event with the
vendor
and other utilities to
determine
the root cause
of the failure and possible corrective actions to
be taken.
The resolution to correct the failure of MOV-4-751 will be
tracked
as Inspector
Followup Item 50-250,251/89-24-05.
Management
Meeting (94702)
On May 10,
1989,
the bi-monthly NRC/FPL Management
Meeting
was conducted
at the site.
This meeting
was
the eleventh
in
a series
of management
meetings
following issuance
of Confirmatory Order 87-85 in October
1987.
The meeting
was attended
by
NRC Regional
and Headquarters
Management
and
FPL Site
and
Corporate
Management.
The topics of discussion
included
overall plant status,
recent operational
events,
engineering,
maintenance,
and security initiatives.
Exit Interview (30703)
The
inspection
scope
and
findings
were
summarized
during
management'nterviews
held throughout the reporting period with the Plant
Manager
Nuclear
and selected
members of his staff.
An exit meeting
was conducted
on
May 26,
1989.
The areas
requiring management
attention
were reviewed.
No proprietary
information
was
provided to the inspectors
during the
reporting period.
The inspectors
had the following findings:
50-250,251/89-24-01,
Violation.
Failure to meet the requirements
of TS 6.8.1,
two
examples:
Failure
to follow procedure
resulting
in
an
inadvertent
drop of Rod M-8; and failure to follow procedure resulting in
a reactor trip during surveillance testing.
(paragraph
5 and 10).
50-250,251/89-24-02,
Inspector
Followup
Item.
Followup
on
concerns
identified with the storage
and control of hydrogen
on site
(paragraph 8).
50-250,251/89-24-03,
Unresolved
Item.
Resolution of document
control
discrepancies.
(paragraph 8).
50-250,251/89-24-04,
Unresolved
Item.
Determine
the cause
of inadequate
clearance
control.
(paragraph
5).
50-250,251/89-24-05,
Inspector .Followup Item.
Followup on the resolution
to correct the failure of MOV-4-751,
(paragraph
10).
16
5O-250,251/89-24-06,
non-cited
violation with
no written notice
of
violation regarding
the
use
of the
wrong
RTD calibration
curves.
{paragraph 10).
Acronyms and Abbreviations
ADM
ANSI
ARO
CB
CFR
DP
ERT
ICRR
ICW
!EB
IFI
LCO
LER
LIV
MTC
NRC
ONOP
OP
OTSC
PC/M
pcm
ppm
PNSC
gA
Administrative
American National Standards Institute
Administrative Procedures
all rods out
American Society of Mechanical
Engineers
Control
Bank
Component Cooling Water
Closed Circuit Television
Code of Federal
Regulations
Containment
Spray
Differential Pressure
Emergency Notification System
Event Response
Team
Florida Power
5 Light
Final Safety Analysis Report
High Head Safety Injection
Inverse
Count Rate Ratio
Intake Cooling Water
Inspection
and Enforcement Bulletin
Inspector
Followup Item
Isothermal
Temperature
Coefficient
Limiting Condition for Operation
Licensee
Event Report
L'icensee Identified Violation
Loss of Coolant Accident
Maintenance
Procedures
Moderator Temperature Coefficient
Non-conformance
Report
Net Positive Suction
Head
Nuclear Regulatory
Commission
Off Normal Operating
Procedure
Out of. Service
Operating
Procedure
On the Spot
Change
Protected
Area
Plant Change/Modification
Percent Millirho
Parts
Per Million
Plant Nuclear Safety Committee
Plant Supervisor
Nuclear
Physical Security Procedures
guality Assurance
17
QC:
RCO
RTB
SRNI
T AVG
TS
Quality Control
Reactor Control Operator
Reactor
Coolant'Pump
Residual
Heat
Removal
Reactor Protection
System
Resistance
Temperature
Detectors
Reactor Trip Breaker
Source
Range Nuclear Instrument
Senior Reactor Operator
Average Reactor. Coolant Temperature
Technical Specification
Temporary System Alteration
Unresolved
Item