ML17223B037
| ML17223B037 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 12/18/1990 |
| From: | Crlenjak R, Elrod S, Michael Scott NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17223B038 | List: |
| References | |
| 50-335-90-28, 50-389-90-28, NUDOCS 9012270012 | |
| Download: ML17223B037 (29) | |
See also: IR 05000335/1990028
Text
~A,IA AEQUI
Wp0
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323
Report Nos:
50-335/90-28
AND 50-389/90-28
Licensee:
Florida Power
5 Light Co
9250 West Flagler Street
Niami,
FL
33102
Docket Nos.:
50-335
and 50-389
Facility Name:
St. Lucie
1 and
2
License Nos.:
and
Inspection
Conducte
.
Inspectors.
~
~/
AN. A.
Approved By;
R.
V. Cr
Divis.ion
ctober
23 - November
19,
1990.
/> /< f~
od,
Se
d'or
esi
t Inspector
Dat
Sig ed
P/8F~
t, Resi ent Ins
or
Date Signed
/z )8
FQ
enjak, Section Chief
Date
ign
of Reactor Projects
Scope:
SUMMARY
This routine resident
inspection
was
conducted
onsite in the
areas
of plant
operations
review, maintenance
observations,
surveillance
observations,
safety
system inspection,
review of special
reports,
review of nonroutine events,
and
followup of previous inspection findings.
Results:
No violations or deviations
were identified during the reporting period.
For
Unit 2, the licensee
conducted
part of a normal
outage this inspection period.
For the period,
Unit
1
had
a
normal
at-power
run with
a 'controlled
shut
down/restart for required Control
Element Assembly testing.
9012270012
901219
ADOCK 05000335
8
REPORT
DETAILS
Persons
Contacted
Licensee
Empl oyees
D. Sager,
St. Lucie Site Vice President
- G. Boissy, St. Lucie Plant Manager
J. Geiger,
Vice President,
Nuclear Assurance
B. Guilbeault, Director, Nuclear Materials
Management
- J. Barrow, Operations
Superintendent
J. Barrow, Fire Prevention
Coordinator
R. Church,
Independent
Safety Engineering
Group Chairman
- H. Buchanan,
Health Physics
Supervisor
C. Burton, Operations
Supervisor
- D. Culpepper, Site, Juno Engineering Supervisor
- R.
Dawson,
Maintenance
Superintendent
- J. Dyer, guality Control Supervisor
- R. Englmeier, Site guality Manager
R. Frechette,
Chemistry Supervisor
C. Leppla,
ISC Super visor
G. Madden, Licensing Engineer
- L. McLaughlin, Plant licensing Superintendent
- B. Parks, guality Control Superintendent
L. Rogers, Electrical Maintenance
Supervisor
N. Roos,
Services
Manager
C. Scott,
Outage Supervisor
D. West, Technical Staff Supervisor
J. West, Mechanical
Maintenance
Supervisor
W. White, Security Supervisor
- G. Wood, Reliability and Support Supervisor
E. Wunderlich, Reactor Engineering
Super visor
Other
1 icensee
employees
contacted
included
engineer s,
technicians,
operators,
mechanics,
security force members
and office personnel.
- Attended exit interview
and initialisms used
throughout this report are listed in the
last paragraph.
-2.
Review of Plant Operations
(71707)
Unit I began
the inspection
period at power.
The unit was shut
down
on
October
27 to test
20
.
While shutdown,
the licensee
investigated
potential
problems with TCBs
and the main turbine.
The unit was started
up
on October
29
and
ended
the inspection
period at
power - day
20
on
1 ine.
Unit 2 began
and ended the inspection period in a refueling outage.
'1
During this inspection" period,
NRC examiners
participated in the licensed
operator requalification testing
conducted
from October
29 to November 9.
a.
Plant Tours
b.
The
inspectors
periodically
conducted
plant tours to verify that
monitoring
equipment
was
recording
as
required,
apipment
was
properly tagged,
operations
personnel
were
aware of plant conditions,
and plant housekeeping
efforts were
adequate.
The inspectors
also
determined
that
appropriate
radiation
controls
mre
properly
established,
critical clean
areas
were being controlled in accordance
with procedures,
exc ss
equipment or material
was stored properly,
and combustible materials
and debris
were disposed of expeditiously.
During tours,
the irxpectors
looked for the existeme
of unusual
fluid leaks,
piping vibrations,
pipe hanger
and seisaic restraint
settings,
various
valve and breaker positions, equipaent caution
and
danger
tags,
comporent
positions,
adequacy
of fire fighting
equipment,
and
instrument
calibration
dates.
Soae
tours
were
conducted
on backshifts.
The frequency of plant tocrrs
and control
room visits by site aranagement
was noted to be adequate.
The inspectors routinely conducted partial
walkdowns of ESF,
and
support
systems.
Vclve, breaker,
and switch lineups
and equipment
conditions
were
randomly verified both locally and in the control
room.
The followiog accessible-area
ESF system walkdowns were
made
to verify that
system
lineups
were in accordance
vith licensee
requirements
for operability
and equipment material conditions
were
satisfactory:
Unit 2
CCW platform, Unit
1 "A" and
B'DGs, Unit 2
pumps
(both aid-nozzle
and
SDC modes),
Unit I ECCS spaces,
and
Unit 1 cable spreading
rooms.
Plant Operations
Review
The
inspectors
periodically
reviewed shift logs
ard
operations
records,
including data
sheets,
instrument traces,
and records of
equipment malfunctions.
This review included contre1
room logs
and
auxiliary logs, operating
orders,
standing
orders, jmper logs
and
equipment tagout records.
The inspectors routinely observed operator
alertness
and
deoeanor
during plant tours.
They observed
and
evaluated
control
reom staffing, control
room access,
and operator
performance
during routine operations.
The inspectors
conducted
random off-hours iaspections
to assure
that operations
and security
performance
remained
at acceptable
levels.
Shift turnovers
were
observed
to verify that
they
were
conducted
in accordance
with
approved
licensee
procedures.
Control
room annunciator
status
was
verified.
Except as noted below,
no deficiencies
were observed.
'I
During this inspection
period,
the inspectors
reviewed the following
tagouts
(c'learances):
1-)0-98
Unit
1 TCB 7,
2-10-146
2B Bus Load Test Circuit Breaker,
and
2-10-327
breaker 2-93102,
2A CEA NG set.
Special
test
procedure
OP
2-0410026,
Rev 0, Differential Pressure
Testing of Notor Operated
Valves,
was partially performed
on Unit 2
on October
10.
The procedure satisfied certain
GL 89-10 requirements.
Appendix A of the procedure controlled the testing of SDC valves
3657
and
FCY 3306.
The procedure
required
no temporary
changes
to
correct errors
and functioned well in the
hands
of the operations
'taff.
The valves
operated
satisfactorily under
1B LPSI
pump full
flow operation.
The licensee
monitored
HCV 3657 characteristics
with
Novats test equipment.
On October
25, prior to taking the
)A startup
transformer
out of
service for PN, the licensee
conducted TS-required starts of the Unit
1
EDGs.
The
)A
EDG started
within 10
seconds
but the operator
thought that
1B
EDG took 12.6
seconds
to attain
60 Hertz.
Per the
applicable
TS,
EDG start timing for this condition was not required;
the
TS
had
been recently
changed
to
r equire
timed
EDG fast starts
twice
a year instead of monthly.
Prior to 1987,
the
)A
EDG frequency
meter in the control
room was
replaced with a meter dissimilar to those serving the other
EDGs.
No
similar meter
was available at the time.
The
1A EDG meter pointer
rest position
was at the low Hertz end of the scale.
The
1B
meter pointer rest position
was at the high Hertz end of the scale.
The remainder of the meters
in both units and the simulator were the
same
as the
1B meter.
EDG start timing was normally accomplished
by
the control
room operators
using these
meters
and
a stopwatch.
The operator first started
and timed the
1A EDG.
During the IB EDG
start,
the operator
simply forgot the meter difference
and waited an
extra overshoot to stop the stopwatch.
When timed by other utility
personnel,
the
1B
EDG performed correctly.
After the operators
determined
that
1B
was
operating
correctly,
the
lA startup
transformer
was taken out of service.
The
human factors
problem of frequency
meter
pointers
moving from
opposite directions only affects
the manual timing process.
When the
diesels
auto-start
due to
some
safety-related
signal,
the aeter
details
do not matter.
When timing is measured
by automatic timers,
these'eters
are
not used.
Part of the
human factors corrective
0
action
was to change
out the
1A meter in the control
room.
Since
no
meters
were available,
a
NPWO was written to exchange it with the
local
panel
meter.
At the
end of the inspection period, this action
was still pending.
During
a Unit
1
BAM station. tour, three
degraded
and rusted
pipe
hangers
were observed.
They were pointed out to, the operations staff
who issued
repair
NPWOs.
The hanger
condition did not jeopardize
safety-related
systems.
During
a Unit
1
ECCS area tour, several
indications of boric acid
leakage
were observed:
Boric acid build up was noted
on the shaft seal
area of the
1B
Containment
Spray
pump.
The spray
pump
had slight buildup
of acid during the last unit startup with no evident
leakage
during operation.
The acid
had yet to be cleaned
since that time
and
more
accreted
over the 'intervening
approximate
3 months.
The
buildup
was
due
to very slight leakage
at the'nitial
startup
of the
pump;
as
the
pump
came
up to
speed,
the
mechanical
pump seal
ceased
to leak.
A NPWO was existing from
the,startup
of the unit.
When questioned
about about the leak
rate,
Operations
re-opened its dialogue with the engineering
group regarding acceptable
leak rates for such mechanical
seals,
had the
seal
area
cleaned
of boric acid,
and ran the
pump to
verify the above observed
leakage
phenomena.
Boric acid buildup and standing moisture were noted in the drip
pan
beneath
the
1C
pump.
Operations
had the drip pan
cleaned
of boric acid residue
and
was to monitor the area for
points of leakage.
Mechanical
maintenance
had
a
NPWO
on
a
suspect
valve,
V 3867,
that
would
be
pursued
on
a higher
priority basis.
1R 335,389/90-18
discussed
impeller-cavitation-induced
erosion of the
1A
CCW pump.
A proposed
corrective action in a licensee evaluation
report
was to review operating
procedures
for any needed
changes
to
preclude
pump run out.
One
pump supplying two
CCW trains,
as during
an outage,
was of prime interest.
During a Unit 2
CCW platform area tour
on October 25, the 2A CCW pump
discharge
pressure
was
60 to
65 psig
vice the
110-psig
normal
operating
pressure.
At the time, the
pump was supplying both A and
B
trains.
The
inspector
discussed
this
near
run
out condition with the
operations
staff.
The
ANPS in charge
of the unit had previously
throttled
pump flow to 9,000
gpm to stay
below
a
known
CCW heat
0
'5
exchanger
design
flow limit of 10,500
gpm.
He was
unaware of any
other
imposed limits.
Neither -engineering
nor the technical
support
staff had yet provided operations
a not-to-exceed
pump flow value to
prevent
pump
run out or impeller cavitation.
On October
27, the
operations
department
issued
a night order indicating that
CCW flic
should
be limited to 10,000
gpm until the flow question
was resolved.
Subsequently,
technical
support
personnel
considered
that the
CCM
heat
exchanger
limiting flow of 10,500
gpm
would probably
be
sufficient to prevent impeller damage.
They planned to transmit
a
formal answer to the operations staff.
According to FPL drawing 2998-4182,
the
pump head curve,
pump run cut
occurred
during
a vendor's test at 11,000
gpm
pump flow with 65 feet
NPSH,
135 feet discharge
head
(approximately
58 psig),
and
75
F water
temperature.
The inspector
concluded that the 10,500
gpm limit waald
preclude
pump run out.
Unit
1
was
shut
down
on October
27 to conduct
NRC-.required
testing.
Hajor procedures
in use for the shutdown were:
OP 1-0030128,
Rev 7, Reactor
shutdown,
and
OP 1-0030125,
Rev 22, Turbine Shutdown - Full Load to Zero Load.
Trainees
from the ongoing operator licensing class
performed reactor
and t'urbine control duties
under the close supervision of licensed
operators.
The
shutdown
was
performed
smoothly.
Following the
shutdown,
several
surveillance
procedures
and minor
SNOW repairs mre
performed prior to the
CEA test.
The
20
suspect
CEAs were tested
during full-length withdrawal
at@
insertion per
NPWO 17969/61
and LOI-0-40, Rev 0, Testing of "Origisal
Design" Type 81 Control Element Assembly.=-
Additionally, coil current,
traces
were recorded.
The test results
were satisfactory.
During the
CEA testing,
a
new computer-controlled
device,
a "sticky
gripper monitor", developed
by the site
18C department
was plugged
into
the circuit for first time
evaluation
of its
sensing
capabilities.
Its output controls
were not attached
to the
controls.
This device will function,
on
a per
CEA basis, similar to
the Unit 2 ACTM circuits that detect
CEA drive upper gripper sticking
and lock the lower gripper,
thus reducing the occurrence
of dropped
CEAs during startups.
The
new device's
sensing circuits
seemed to
function well.
While attempting to return Unit
1 to power operation
on October 28,
the
main turbine high pressure
end vibration probe indicated higher
than
normal vibration at
the
number
one
bearing.
The licensee
removed
covers
from the area
around
the bearing
and took main shaft
runout
readings
while operating
the turning
gear
to verify an
instrumentation malfunction..Power
ascension
was
resumed
on the 29th
and full power was attained
on the 31th.
The posting of required notices to workers
was reviewed
by the
NRC
staff during this inspection period with no adverse findings.
During the
inspection
period,
Unit
2 was to enter
a reduced
inventory condition to support
the
nozzle
dam
removal while
returning from the refueling outage.
The evolution was scheduled for
October
31 at 5:30 a.m.
The following items were checked. for this
evolution:
J
Containment
Closure Capability - Instructions
were
issued
to
accomplish this; personnel
and tools were stationed.
RCS Temperature
Indication - Cables
were connected
to four CETs
for temperature
display in the control
room.
Level Indication - Independent
RCS wide
and
narrow range
level
instruments
were
operating~ and providing control
room
indication.
The Tygon tube loop level
gage in the containment
was
manned
during level
changes
and
checked
every
two hours
during static conditions.
A licensed
operator
was assigned
to
monitor control
room indication throughout mid-nozzle operation.
K
RCS Level Perturbations
- When
RCS level
was altered,
additional
operational
controls
were
invoked.
At plant daily meetings,
operations
routinely made
announcements
to not
even consider
performing
work that might effect
RCS level
or shut
down
cooling.
RCS Inventory Volume Addition Capability -
One HPSI
pump and
a
second
pump were available for RCS addition.
No charging
pumps
were to be available for this mid- nozzle evolution.
RCS Nozzle
Dams - Instructions were issued for their removal.
Vital Electrical
Bus Availability, - All required vital busses
were available for the evolution.
No vital bus work was to be
performed during the reduced
inventory condition.
Non-vital bus
2Bl was repaired during mid-nozzle.
That this bus did not power
anything associated
with the evolution had
been
checked
by three
.separate
SROs.
On
November ll, Unit 2 was in mode
5 following refueling.
While
performing
safeguards
time
response
testing, 'n
I8C technician
depressed
the group
5 pushbutton
instead of the group
3 pushbutton.
This actuated
equipment
and alarms not anticipated
by the operators.
The operating
crew immediately notified the
I&C personnel
of the
unexpected
actuations
and verified that shutdown cooling had not been
affected.
All the erroneously
selected
equipment actuated
properly
unless
out of service or already operating.
Testing
was terminated,
safeguards
was reset,
and
the
equipment
restored
to its pre-test
condition.
No plant equipment
damage
had occurred
and the licensee
promptly notified the
NRC.
The licensee
plans to issue
an
LER
concerning
the event.
c.
Technical Specification
Compliance
Licensee
compliance with selected
TS
LCOs was verified. This included
the
review
of
selected
surveillance
test
'results.
These
verifications were accomplished
by direct observation of monitoring
instrumentation,
valve positions,
and switch positions,
and by review
of completed
logs
and records.
Instrumentation
and recorder traces
were observed for abnormalities.
The licensee's
compliance with LCO
action
statements
was
reviewed
on
selected
occurrences
as
they
happened.
The inspectors
verified that related plant procedures
in
use
were adequate,
complete,
and included the most recent revisions.
d.
Physical
Protection
The,.inspectors
verified by observation during routine activities that
security program plans were being implemented
as evidenced
by: proper
display of picture badges;
searching
of packages
and personnel
at the
plant entrance;
and vital area portals being locked and alarmed.
Overall,
the licensee
supported
the Unit 2 outage activities well
and
maintained Unit 1 in an operational
condition.
)
3.
Surveillance Observations
(61726)
Various
plant
operations
were verified to
comply with selected
TS
requirements.
Typical of these
were confirmation of TS compliance for
reactor
coolant chemistry,
RWT conditions,
containment
pressure,
control
room ventilation
and
AC and
OC electrical
sources.
The
inspectors
verified that
testing
was
performed
in
accordance
with
adequate
procedures,
test instrumentation
was calibrated,
LCOs were met,
removal
and restoration
of the affected
components
were accomplished
properly,
test results
met requirements
and were reviewed
by personnel
other than
the individual directing the test,
and that any deficiencies
identified
during the testing
were properly reviewed
and
resolved
by appropriate
management
personnel.
The following surveillance tests
were observed:
OP 2-0410050,
Rev 16,
HPSI/LPSI Periodic Test,
was performed
on the
2A
pump.
It was
being returned
to service following system drain,
multiple system entries into other parts of the system,
and system refill.
System venting, which had recently
been
a problem on Unit 1, successfully
eliminated trapped-air-related
water
hammer
problems.
Pump operation
was
satisfactory.
Several
control
room flow meters for this system indicated
erratically and were flagged for additional
sensor venting.
MP 2-0960152,
Rev 4,
2B Safety Battery Performance
Test,
was performed
on
October
23 under
NPWO 8336/62
using the three-hour rating of 637 A.
The
procedure,
which had
been significantly modified by TC following a recent
field evaluation,
worked quite well.
The computer-controlled
load bank
and data recorder,
and the
2B battery its'elf, also functioned well.
The
test concluded with the performance of MP 0960164,
Rev 5,
125
VDC System
Monthly Maintenance.
Following The Unit
1
shutdown
on October
27,
operators
were
observed
performing
OP
1-1210051,
Rev
10,
Wide
Range
Nuclear
Instrumentation
Channels
Functional Test.
The functional test
was satisfactory.
Prior to conducting
CEA tests
on October
28,
operators
conducted
testing
per
OP
1-1400059,
Rev
17, Reactor
Protection
System - Periodic
Logic Matrix Test.
Due to its nature, this test also required tripping of
the
TCBs numerous
times.
Conduct of testing
was satisfactory,
however
TCB
3 tripped
open
unexpectedly
and
TCB
7 failed to close.
The operator
properly stopped
the test until
TCB performance
was resolved.
Following
TCB evaluation,
the test
was
completed satisfactorily.
Specific
TCB
problems are discussed
in paragraph
4 below.
Prior to conducting Unit 2
ATWS tests
on November 18, operators
conducted
RPS testing
per
OP 2-1400059,
Rev 13, Reactor Protection
System - Periodic
Logic Matrix Test.
Conduct of testing
was satisfactory
and the
TCBs
functioned properly.
Re-performance
of portions of the
18-month
ESF test,
per
OP 2-0400050,
Rev. 8, Periodic Integrated
Test of the
Engineered
Safety Features,
was
observed
on
November
10-11.
This test contained
several
sub-tests
and
verified plant
response
to
a
loss of offsite power followed by
-actuation;
load tested
the
EDGs; and tested
a number of specific equipment
interactions,
some
during the loss-of-offsite-power test
and
some under
other conditions.
The test
had been routinely conducted at the beginning
of refueling
outages
so that
unexpected
failures
could
be efficiently
evaluated
and corrected prior to
post-outage
unit restart.
The retest
was scheduled
as
a
more efficient maintenance
post-test
than individual
equipment tests.
At the
end of the 24-hour
EDG test run, the
EDGs were required to be
restarted within 5 minutes to demonstrate
hot start capability.
During
the October
2-3 test,
the
had run well during the 24-hour test
run
but were still at post-run idle speed
vice stopped
when restarted.
They
responded
proper ly for the condition
by accelerating
to operating
speed
and then loading, but the surveillance
requirement
was not satisfied.
The
EDGs were subsequently
overhauled
as
planned.
The 24-hour test run and
hot restart
were repeated
during the November
10-11 safeguards
test.
The
EDGs ran wel'l again
and restarted
properly.
IR 389/90-24,
paragraph
7, discussed
being installed
in certain
ECCS control valves.
If throttled after
an
ESF actuation,
the
valves
would re-open
when the control
was
released.
Since the
A train
relays
had
been
restored
to design,
valve throttle function for A train
valves
was tested
and confirmed during the
safeguards
retest.
B train
valve relays
were scheduled for replacement
when plant conditions allowed.
They will be individually retested.
The
surveillance
program
observations
were
satisfactory
for this
inspection
period with the licensee
responding
appropriately to various
test results.
4.
Maintenance
Observation
(62703)
Station maintenance'activities
involving selected
safety-related
systems
and
components
were
observed/reviewed
to
ascertain
that
they
were
conducted
in accordance
with requirements.
The following items
wet e
considered
during this review:
LCOs were, met; activities were accomplished
using
approved
procedures;
functional
tests
and/or calibrations
were
performed prior to returning
components
or systems
to service; quality
control records
were maintained; activities were accomplished
by qualified
personnel;
parts
and
materials
used
were
properly certified;
and
radiological controls
were
implemented
as
required.
Mork requests
were
reviewed to determine
the status of outstanding
jobs
and to assure
that
priority was
assigned
to safety-related
equipment.
Portions
of the
following maintenance activities were observed:
NPNO 7165/61
required
replacement
of type
AGC fuses
on
CEDM coil power
programners
for all Unit
1
CEDHs. It also required marking of the fuse
holder
caps with a paint stripe to allow visual verification of the cap
being fully shut.
had reported multiple drops of a
because
of a loose fuse holder cap.
The work was performed
on October
28
prior to the
special
CEA tests.
The
new fuse holder
cap markings
indicated
cap status quite effectively.
Troubleshooting
and repair of Unit
1 TCBs
3 and
7 was observed following
their failure during the
RPS logic matrix test
on October 27.
The
TCB 3 undervoltage trip coil had
burned out, which occasionally
occurs to normally-energized
equipment.
That accounted for the
TCB
tripping.
The undervoltage trip unit was replaced
per
NPNO 5027/61.
Post
replacement
adjustment
and
testing
was
accomplished
per
EHP-63.01,
Rev 2, Periodic Haintenance
of Reactor Trip Switchgear
and
Breakers,
section
8.2,
the quarterly
TCB inspection.
Several
required
gC witness points addressed
critical performance
elements.
'1
10
TCB
7 was troubl.eshot,
replaced,
and the
new breaker
inspected
per
NPWO 5028/61.
One of two TCB 7 closing latch springs
had
come loose
from the
two bars it normally attached
to.
These
springs
held the
latch in tension
arid provided
the
energy to
snap
open
the
main
contacts
when the
TCB tripped open.
Since that portion of the
TCB
would be repaired- only by the vendor,
a replacement
TCB was obtained
from stores,
tested,
and installed
per
1-EMP-63.01,
Rev 2, section
8.3, the
18-month
TCB inspection.
This section also included all the
steps
and required
QC witness points of section 8.2 mentioned
above.
It was
observed
that the springs for the failed TCB were wound alike
but those for the
replacement
were
counter-wound.
Licensee root
cause investigation
developed initial verbal information that the two
springs
should
be counter-wound for electrically-operated
TCBs
and
that the two springs
must
be installed in a specific configuration.
Approved
vendor
manual
8770-3561
did not discuss
this but it was
confirmed in
a vendor letter dated
November 2, 1990.
The licensee
promptly
determined
that all
TCBs
in
use for both units
had
counter-wound
spr ings except Unit
1
TCBs 2, 6, and newly-installed
7
which had reversed
springs.
A vendor representative
restored
these
three
TCBs to design
on November
12 per
NPWOs 5047/61,
5048/61,
and
5049/61.
The
licensee
was
auditing
GE's facility to'etter
understand
the root cause.
Initial licensee
review determined
that
TCB spring failure was not a
safety
concern at St.
Lucie because
the failure would occur only
while the
TCB was opening
and would not prevent proper opening - the
safety function of St. Lucie TCBs was to open upon
demand.
Following
the
inspection
period,
the
vendor
documented
in letter
JMA90130,
dated
November
27,
1990, that if one spring were to come off, the
other would also
come off and the breaker would no longer close.
The
inspector
concluded that this spring failure mode is self-identifying
prior to the
TCBs being relied upon for reactor protection.
NPMO 8330/62
provided, work control for the
PM inspection
and
bearing
replacement
of the
2A HPSI motor.
During post-maintenance
functional
motor testing,
the licensee
discovered
a potential vibrational
problem.
NPMO 5467/62
permitted
the reliability group to conduct
more extensive
vibrational testing,
which indicated that the replacement
bearings
were
less
than optimum.
The babbitt type bearings
were replaced
a second
time
at the end of the inspection period.
Other maintenance
items are discussed
in the paragraph
below.
5.
Outage Activities (62703)
The inspector
observed
the following overhaul activity during the ongoing
Unit 2 outage:
NPbS 3638/62
provided
work control for repairs
to
V 3227,
the
2A1 loop
injection check valve,
per
GMP-Ol,
Rev 0, Disasseahly,
Inspection,
and
11
.
Reassembly
of Plant
Check
Valves.
The inspectors
observed
valve disk
sanding.
The contractor
involved
was
" utilizin'g 'a
FPL-provided
Dexter
machine for the work.
The valve
and
a sufficient adj'acent
area
had
been
tented for ALARA considerations
during the sanding.
The health physics
aspects
and
overall
job control
were
good.
The
licensee
provided
machinist support in the manufacture
of sanding
caps
used
on the machine.
FPL mechanical
maintenance 'provided
continuous
engineering
supervisory
coverage for this
as well as other valve repairs
being performed
by this
contractor.
The observed
work was satisfactory.
This particular valve
had
a minor leak (approximately 0.2
gpm, ref.
IR
335,389/89-16,
paragraph
10) during the entire previous fuel cycle.
The
leakage
had
caused
the
operational
staff
to
log
and
trend this
information.
Following identification
as
a leakage
source
during the
previous refueling outage,
'minor valve machining
had reduced
but had not
halted the leakage.
NPWO 3617/62 controlled
work on
V 1202,
one of three pressurizer
safety
reliefs.
During past
outages,
all three relief valves
had
been
removed
for testing or overhaul,
but this -outage
the licensee
only removed the
ASME Code
recoomended
sample
size of one.
The remaining
two valves
had
exhibited
no leakage
during the last
power operation
period.
V 1202 was
bench tested with zero
leakage
and the lift pres'sure
was within limits
during pressure
testing.
The valve was reinstalled after testing without
disassembly.
Procedure
Rev
22,
Pressurizer
Valve Safety
Maintenance,
Appendix
C,
replacement,
was utilized to
reinstall.
the valve.
The initial pipe-flange-to-valve-flange
alignment
was slightly off after
snugging
of the
flange bolts;
the
procedure
requirements
were followed to measure
and correct the misalignment,
a lack
of parallelism, prior to torque application.
The parallelism between
the
piping and valve inlet flange
was required to attain proper spiral-wound
gasket crush
between
the flanges.
Health Physics
aspects
of this job were. good.
A HP technician monitoring
the contract
mechanics
performing
the
work was directing
changes
to
anti-contamination
dress.
Sufficient shielding
was installed to keep the
dose rate low.
The mechanics
were applying proper
HP practices.
An FPL
technical
support
engineer
was
present for at least part of the initial
makeup.
Contractor
crew changes
occurred primarily due to heat
stress
reasons
rather than radiation exposure limit reasons'.
Turn over at
crew changes
was good.
NPWO 8045/62 controlled
work on the reactor incore instrumentation that
penetrates
the reactor
vessel
head.
Procedure
ISC 1400023,
Rev 1, Incore
Instrumentation
(ICI) Outage
Tasks,
was the instruction used during the
instrumentation
work.
The inspector
observed
removal of the bullet noses
and part of the clean
up of flanged joints connecting the cabling through
the vessel
head.
The flanges
were cleaned
and inspected
to ensure that
a
good seal
was attained at these
pressure
boundary joints.
The work, which
was performed in air fed hoods,
proceeded
smoothly with highly visible and
supportive supervisors
and
HP.
12
The ten bullet noses
were guides installed syometrically around the vessel
head to aid in the removal
and installation of the upper guide structure
on the vessel
head;
the
noses
were installed prior to the removal of the
UGS after reactor
shutdown.
The bullet noses
were not used during power
operation..
ADY MV 08-18B
had both its actuator
and its valve overhauled
during the
outage.
NPWOs
8532/62
and
1089/62 controlled
the work evolutions.
At
val've disassembly,
the inspector
inspected
the disassembled
valve parts
and
reviewed
the mechanic's
inspection findings.
The intended repair
actions
were appropriate
and conservative.
The disassembled
actuator
showed
no signs of wear and the overhaul activi.ty was well controlled.
Work process
sheet
5033
provided
work control for site construction
service
personnel
during retubing of the
2B
CCW heat'xchanger.
The
inspectors
observed
aspects
of the entire job, which took approximately
three
weeks.
The effort
was
well controlled with'isible
gC
and
supervisory
involvement.
The retubed
heat
exchanger
hydrostatic test failed.
No problems
were
found with the
new
tube
bundle.
However,
the test
identified
a
through-wall, weld defect in an existing bimetallic weld between the outer
shell
and the
ICW outlet tube sheet.
By the end of the inspection period,
the licensee
had evaluated
and repaired
the defect with the aid of the
heat
exchanger
manufacturer
and corporate
NDE specialist.
The
NCR 2-428
response
provided repair directions.
Hydrostatic, retesting
was planned.
The
above
outage
work was
performed with good
HP coverage,
visible
supervisor oversight,
and excellent work performance.
Design,
Design
Changes,
and Modifications (37700)
Installation of new or modified systems
were reviewed to verify that the
changes
were reviewed
and
approved in accordance
with 10 CFR 50.59, that
the
changes
were
performed in accordance
with technically
adequate
and
approved
procedures,
and that
subsequent
testing
and test results
met
acceptance criteria or deviations
were resolved in an acceptable
manner.
This review included selected
observations
of modifications
and testing in
progress
relating to
PCM 103-289,
which provided for installation of a
Unit 2
DSS to comply with 10 CFR 50.62
ATWS requirements.
The
PCM added
electronic circuit boards
to the existing safety-related
ESFAS cabinets.
These circuits will monitor
RCS pressure
and, if needed,
provide an action
signal to open newly-installed
load contactors
in series with each
set output circuit breaker.
This system
was designed to be independent 'of
and redundant
to the
and
was designed
to be diverse at the component
level.
Different manufacturers
or principles of operation
were used,
i.e.,
a contactor vice
a circuit breaker.
The
MG set output circuit
breakers
were
interlocked
to the
new load
such
that the
must
be
shut
before
the circuit breaker
could shut.
This
13
ensured
synchronizing
and loading functions
would
be
performed only by
circuit breakers.
The
inspector
reviewed
ongoing
modification
and
quality control
activities,
sampled
wiring installations,
and
witnessed
several
post-installation
system tests.
Observations
included portions of:
Preoperational
Test
2-1400200,
Rev
0,
ASS
Preoperational
Test,
sections
12.2, 12.3,
12.4,
12.6,
and 12.7;
and
IAC 2-1400052,
Rev
17,
Engineered
Safeguards
Actuation System-
Channel
Functional Test.
Testing
personnel
consistently
discussed
the test
with control
room
operators,
including alarms that might be received.
Testing
was conducted
strictly per
approved written procedures.
A test
change specifically
demonstrating
that
each
combination of two input signals
could cause
both
train's outputs to the contactor
was approved prior to performance.
Test
personnel
found that
CIS
Group
B did not actuate
from containment
high
radiation.
This was traced
to a mislabeled wire, which was corrected
and
retested.
The design contractor will address
this issue to ensure that it
was not
a design error.
On
November l,.a
number of jumpers previously
installed to support this modification were remved.
At that time, the
existing
systems
were
retested
per
18C
2-1400052
to
demonstrate
operability.
On November
18, both
A and
B train were
shown to trip the
respective
load contactor
and circuit breaker from the
ESFAS cabinet in
the control
room.
7.
Evaluation of Licensee
Self-Assessment
Capability (40500)
The
inspectors
evaluated
the
licensee's
self-assessment
programs
to
determine
whether
they contributed
to the
prevention
of problems
by
monitoring and'valuating
plant performance,
providing assessments
arid
findings,
and
communicating
and
following
up
on corrective
action
recommendations.
Portions of this evaluation
were previously accoaplished
in several
IRs:
IR 335,389/90-04,
paragraphs
3 and 4, discussing
Engineering
Response
and Effectiveness
of the Nonconformance
Reporting Program;
IR 335,389/90-09,
paragraph
4, discussing
the
ISEG, the
FRG,
and the
Industry Operating Experience
Program;
IR 335,389/90-18,
paragraph
2, discussing Quality Assurance
Audits of
the Corrective Action Program;
and
IR 335,389/90-22,
paragraph
2,
discussing
Quality Verification
Activities, Performance Monitoring, And Quality Assurance Audits; and
Paragraph
3, discussing
Engineering
Self-Assessments.
14
These reports
discussed
several
improvements that could be implemented but
found
no serious
problems.
IR 335,389/90-04
also
closed
a
1988 IFI
concerning
inconsistent
root cause
analysis
of failures.
This closeout
reported
completion of a spectrum of corrective actions for the identified
weakness.
IFIs 335,389/90-09-07
and 90-09-08 were promptly addressed
by
the licensee.
Corrective action status for these
items is discussed
in
paragraph
8 below.
The corrective actions for a number of minor items
previously identified by the resident inspectors
were also considered
as
a
'easure
of sensitivity.
It was
concluded
that the licensee
has
had
an
aggressive
corrective action
program in most cases
and the licensee
has
conducted
audits
in the area,
identified enhancements,
and
implemented
them.
The inspectors
had
no further questions
at this time.
8.
Followup (Units
1 and 2) (92701)
a.
Followup of Inspection Identified Items
(Closed - Units
1
8
2) IFI 335,389/88-07-02,
Establish
a Program to
Trend Valve Stroke Items.
This IFI concerned
the
ASME Code Section
11 valve stroke time test
program controlled
by procedure
AP 0010132,
ASME Code Testing of
Pumps
and Valves.
This
item
was
discussed
in
IR 335,389/89-26,
paragraph
6.a.
Changes
to overall
program
represented
by
a
new
revision
12 to the above procedure
and
AP 0010125A, Surveillance
Data
Sheets
(Rev
18 for Unit
1 and
Rev
19 for Unit 2), provided sufficient
direction and control for closure of this item.
Per discussion
and
demonstration
with operations
and
technical
support staff, valve
stroke information was
been
tracked appropriately.
IR 335,389/90-15
had been issued in this inspection
area with no outstanding
items.
(Open - Units
1
5 2) IFI 335,389/90-09-07,'eaknesses
in the
ISEG
Corrective Action System.
Weaknesses
primarily consisted
of not having
a formal, aggressive
corrective action
system that required written responses
and tracked
the corrective actions.
This item was addressed
on site in completed
Open Item Notice 90-00500,
dated 7-3-90.
Completion
was signed off
on August 6,
1990.
Final reinspection will occur at a later time.
This item remains
open.
(Open - Units
1
5
2)
IFI 335,389/90-09-08,
Weaknesses
in
FRG
Administration.
Weaknesses
included
abbreviated
minutes,
minutes not signed
by the
person
chairing that meeting,
and untimely distribution of minutes.
This
item
was
addressed
on site
by completed
Open
Item Notice
90-00501,
dated
7-3-90.
Completion
was signed off on September
7,
1990.
Final reinspection will occur at
a later time.
This item
remains
open.
0
I
15
b.
Followup of Headquarters
and Regional
Requests
(Closed Units
1
& 2)
P2188-03,
Gamma-Metrics
Cable Assemblies
in the
Post Accident Neutron Monitoring System
May Leak.
This condition was reported
by Gamma-Metrics
to the
NRC on February
19,
1988
as
a potential
cable
assembly leak, at elevated
temperature,
'n metal
hose solder joints.
This might allow moisture to enter the
cable
and contact cable connectors - causing signal interference.
For Unit 1, tests
in
1988
showed that
both
A and
B train cable
assemblies
leaked but no authorized repair
had been developed.
NPWOs
'899/61
and
7056/61,
along with Gamma-Metrics certification letters
dated
March 8,
1990,
showed that the Unit
1 cable
assemblies
were
replaced
then the replacements
repaired
in February
and March, 1990.
Zero power adjustments
were subsequently
performed.
I&C Procedure
1-1240065,
Excore Neutron Flux Monitor quarterly,
demonstrated
power
calibration
on May 16,
1990, following Unit 1 restart from refueling.
For Unit 2, this
item is closed
as
Not Applicable.
Unit 2 used
General
Atomic Brand post accident
neutron monitors.
9.
Exit Interview (30703)
The inspection
scope
and findings were
summarized
on November 21,
1990,
with those
persons
indicated
in paragraph
1
above.
The inspector
described
the
areas
inspected
and
discussed
in detail
the inspection
findings listed
below.
Proprietary material is not contained
in this
report.
Dissenting
comments
were not received
from the licensee.
Item Number
Status
Description
and Reference
335,389/88-07-02
Closed
IFI - Establish
a Program to Trend
Valve Stroke Items,
paragraph
Ba.
335,389/90-09-07
Open
335,389/90-09-08
Open
335,389/P2188-03
Closed
IFI - Weaknesses
in the
ISEG
Corrective Action System,
paragraph
8a.
IFI - Weaknesses
in
FRG
Administrati on, paragraph
8a.
IFI - Gamma-Metrics
Cable Assemblies
in the Post Accident Neutron Monitoring
System
May Leak, paragraph
9.
10.
Abbreviations,
and Initialisms
ACTH
Automatic
CEA Timing Module
Actuation System
AFM
(system)
16
ANPO
ANPS
ANSI
ASME Code
BAM
CEOMCS
CFR
CIS
CWD
CWO
EOG
EMP
FI
FRG
FT
GMP
gpm
HCY
HFA
ICW
IFI
IR
ISEG
JPE
JPN
LCO
LER
As
Low as Reasonably
Achievable (radiation exposure)
Auxiliary Nuclear Plant
t unlicensed]
Operator
Assistant Nuclear Plant Supervisor
American National Standards
Institute
Administrative Procedure
American Society of Mechanical
Engineers Boiler and Pressure
Vessel
Code
Anticipated Transient Without Scram
Boric Acid Makeup (station, etc.)
Component Cooling Water
Combustion Engineering
(company)
Control Element Assembly
Control Element Drive Mechanism
Control Element Drive Mechanism Control
System
Code of Federal
Regulations
Containment Isolation System
Control Wiring Diagram
Construction
Work Order
Demonstration
Power Reactor
(A type of operating license)
Diverse
Scram System
Emergency
Core Cooling System
Emergency Diesel
Generator
Electrical Maintenance
Procedure
Engineered
Safety Feature
Engineered
Safety Feature Actuation System
Flow Control Valve
Flow Indicator
The Florida Power
& Light Company
Facility Review Group
Final Safety Analysis Report
Flow Transmitter
General Electric Company
General
Maintenance
Procedure
Gallon(s)
Per Minute (flow rate)
Hydraulic Control Valve
A GE relay designation
Health Physics
High Pressure
Safety Injection (system)
Instrumentation
and Control
Intake Cooling Water
[NRC] Inspector
Followup Item
[NRCj Inspection
Report
Independent
Safety Engineering
Group
(Juno Beach)
Power Plant Engineering
(Juno
Beach
Nuclear Engineering
TS Limiting Condition for Operation
Licensee
Event Report
Letter of Instruction
Low Pressure
Safety Injection (system)
e
e
MOVATS
MV
NPF
NPWO
NRC
ONOP
OP
PSL
PWO
RCO
Rev
SNPO
TCB
TS
UGS
17
Motor Generator
Motor Operated
Valve
Motor Operated
Valve Test System
Maintenance
Procedure
Motorized Valve
Non Conformance
Report
Non Destructive
Examination
Nuclear Production Facility (a typ
Nuclear Plant Operator
Nuclear Plant Supervisor
Net Positive Suction
Head
Nuclear Plant
Work Order
Nuclear Regulatory Comission
Operating Instruction
Off Normal Operating
Procedure
Operating
Procedure
Preventive Maintenance
Plant St. Lucie
Plant Work Order
Pressurized
Water Reactor
Quality Assurance
Quality Control
Reactor Control Operator
Pump
Revision
Reactor [licensedj Operator
Reactor Protection
System
Shut
Down Cooling
Safety Injection (system)
Senior Nuclear Plant [unlicensedj
Senior Reactor [licensed] Operator
Temporary
Change
Trip Circuit Breaker
Technical Specification(s)
Upper Guide Structire (part of the
Violation (of NRC requirements)
e of operating license)
Operator
reactor)
I ~