ML17222A797
| ML17222A797 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 05/10/1989 |
| From: | Crlenjak R, Elrod S, Michael Scott NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17222A794 | List: |
| References | |
| 50-335-89-10, 50-389-89-10, NUDOCS 8905190175 | |
| Download: ML17222A797 (18) | |
See also: IR 05000335/1989010
Text
~C
0p
+
0
cy %.
~) %~
0 Q
+**++
UN IT E0 STATES
'UCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323
Report Nos:
50-335/89-10
and 50-389/89-10
Licensee:
Florida Power 5 Li'ght Company
9250 West Flagler Street
Miami,
FL
33102
Docket Nos.:
50-335
and 50-389
Facility Name:
St.
Lucie
1
and
2
License Nos.:
and
Inspection
Conducted:
March
12
April 10,
1989
Inspector
. A. Elrod, Senior Resident
Inspector
. A.
ot
, Resident
Inspector
Approved
y:
Crlenjak
tion
C
f
ivision of Reactor
Projects
Date Signed
-) >la-(
Date Signed
l~S
at
Signed
SUMMARY
Scope:
This
inspection
involved
on site activities
in the
areas
of
TS
compliance,
overall
plant operations,
quality assurance
practices,
station
and corporate
management
practices,
corrective
and preventive
maintenance,
site security, radiation control,
and surveillance.
Results:
One violation was identified for failure to
use
the proper torque
pattern
when installing
the
Unit 2 containment
maintenance
hatch,
paragraph
6 (VIO 389/89-10-01)
Five unresolved
items" were identified:
2.
The staff was
unaware
of
since
1986,
paragraph
6 (URI 335,389/89-10-02).
Validity of the
LTOP accident
analysis,
paragraph
9
(URI 335,
389/89-10-03).
3.
Applicability of
GDC 57 to the
blowdown piping in light of
valve
leakage
to
containment,
paragraph
10
(URI 335, 389/89"10-04).
4.
Operability
requirements
for
Containment
Coolers,
paragraph
3
(URI 335, 389/89-10-05).
Unresolved
Items are matters
about which more information is required
to determine
whether
they are acceptable
or may involve violations or
deviations.
EI905i90l75 S905iP
ADOCK 05000335
9
5.
Sealing
requirements
for
Class
1E
valve
solenoids
in
containment,
paragraph
3 (URI 335, 389/89-10-06).
This inspection
disclosed
no particular
widepsread
weaknesses
but did
identify
a concern
in the closeout
of the Unit 2
containment
prior to
entering
mode
4.
The majority of the areas
reviewed,
as they related to
the
Unit 2
outage,
showed
an
adequate
understanding
of
goals
and
processes.
The
level
of work detail
in the finalizing af the Unit 2
containment,
discussed
in section
3, displayed
a potential
lack of resolve
and
a lack of site inspection effort necessary
to clear work items for
positive work package
closure.
The violation identified by this inspection
was believed to be
an isolated
case.
As the
procedure
upgrade
program
proceeds,
the
inspectors
will
continue to routinely monitor procedure
adherence.
REPORT
DETAILS
Persons
Contacted
Licensee
Employees
K.
G.
- J
J.
S.
H.
4'C
D.
- R.
R.
W.
- J
p.
C.
L.
"N.
B.
R.
- R
R
~
D.
W.
- C
E.
C.
Harris, St.
Lucie Site Vice President
Boissy, Plant Manager
Barrow, Operations
Superintendent
Barrow, Fire Prevent Coordinator
Brain, Independent
Safety Evaluation
Group
Buchanan,
Health Physics
Supervisor
Burton, Operations
Supervisor
Culpepper,
Site Juno Engineering
Manager
Dawson,
Maintenance
Superintendent
Frechette,
Chemistry Supervisor
Hagar,
Nuclear Plant Supervisor
Harper,
QA Supervisor
Isaacs,
Nuclear Plant Supervisor
Leppla,
ICC Supervisor
Libby, Outage Supervisor
McLaughlin, Plant Licensing Supervisor
Rogers,
Electrical Maintenance
Supervisor
Roos, Quality Control Supervisor
Sculthorpe,
Reliability and Support Supervi
Sipos,
Service
Manager
Stewart,
Lead System
Engineer
Storke,
Outage Supervisor
Weller, Nuclear Plant Supervisor
West, Technical Staff Supervisor
White, Security Supervisor
Wilson, Mechanical
Maintenance
Supervisor
Wunderlich,
Reactor
Engineering
Supervisor
Wood, Nuclear Plant Supervisor
sor
Ot
me
her
licensee
employees
contacted
included
technicians,
operators,
chanics,
security force. members
and office personnel.
"Attended exit interview
Acronyms, abbreviations
and initialisms used in this report are listed in
the last paragraph.
Plant Status
Unit I began
and ended the inspection
period at power.
The unit ended
the
inspection
period in day
200 of power operation
since its return from an
outage.
During the
period,
the unit
had
two
blowdown valve
repairs,'imited
emergency diesel
maintenance,
and
CEA reed switch repairs.
Unit
2
began
the
inspection
period
in
day
68 of
a
maintenance
and
refueling outage that began
on February
1,
1989.
Restart
was anticipated
to begin
towards
the
end of the week of April 10.
During the inspection
period,
the unit had
an inadvertent
CIS actuation
(see
section
10 of this
report).
Plant Tours (Units
1 and 2) (71707)
The inspectors
conducted
plant tours periodically during the inspection
interval to verify that monitoring equipment
was
recording
as required,
equipment
was properly tagged,
operations
personnel
were
aware of plant
conditions,
and plant housekeeping
efforts were adequate.
The inspectors
also
determined
that
appropriate
radiation
controls
were
properly
established,
critical clean
areas
were being controlled in accordance
with
procedures,
excess
equipment
or
material
was
stored
properly
and
combustible materials
and debris
were disposed
of expeditiously.
During
tours,
the inspectors
looked for the existence
of unusual
fluid leaks,
piping vibrations,
pipe
hanger
and
seismic
restraint
settings,
various
valve
and breaker positions,
equipment caution
and danger tags,
component
positions,
adequacy
of fire fighting equipment,
and instrument calibration
dates.
Some tours
were
conducted
on backshifts.
The frequency of plant
tours
and control
room visits by site management
was noted to be adequate.
The
inspectors
routinely
conducted
partial
walkdowns
of
systems.
Valve positions,
breaker/switch
lineups
and
equipment
conditions
were
randomly verified both locally and in the control
room.
As
a part of preparing for Unit 2 startup,
the licensee
conducted
valve
lineups
and walk downs of their HPSI
and
LPSI systems.
The valve lineups
were in accordance
with OP 2-0410020,
Rev 13,
LPSI/HPSI Normal Operation.
The inspector
observed
a portion of the
system
valve lineup in the
RCB.
The operators
carried
a
copy of the
procedure
that identified the
valves
by number
and valve function description.
They utilized the valve
number
and valve type to confirm the valve's identity.
The valve
number
was
on
a tag connected
to the valve
by
a length of wire.
The inspector
verified that
a
number of the valves
checked
where consistent
with the
information on applicable
system drawings.
The valve lineup observed
went
per. procedure.
Independent verification of the lineup
was to occur at
a
later
time
using
the
same
procedure
but
by different operators.
The
inspector
had
no further questions
concerning
the validity of this valve
lineup.
During the
above
valve
lineup,
the
operators
utilized neither
piping
diagrams
nor
hand carried valve locator information to assist
them.
When
a valve could not
be located,
the operators
would call the control
room
requesting
assistance.
Valve location information
has
been
compiled
in
tabular form and was provided
when requested,
but efficiencies in control
room operations
and reduction of radiation
exposure
could apparently
be
gained
by preview of the information.
The
inspectors
walked
down portions
of SIT piping,
HPSI piping,
piping,
and the charging piping inside the Unit 2
RCB at the
2A2
RCS loop,
where
these
piping
runs join or connect.
The applicable
drawing
was
Ebasco
drawing 2998-G-078,
sheets
110,
131,
and
132.
Work was continuing
in the area
as the outage
neared
completions
The charging line was still
unlagged
where it joined the
RCS.
The
remainder
of the piping run
had
been
relagged
or was still covered with lagging.
The charging line
had
been
examined
under
the licensee's
ISI program.
Prior to Unit
2 entering
Mode 4, several
tours of the
RCB were conducted
to evaluate
licensee
readiness
for heatup.
Several
minor discrepancies
were found and reported to the site management.
Several
more significant
items were observed.
They are discussed
below:
Sample
line tubing for several
was
found bent significantly.
The hot leg sample line, within the containment
boundary,
was bent
and
had obviously been
stepped
on.
None
had
been identified
by the licensee
and evaluated for stress
or operability.
These
have
subsequently
been evaluated.
The hot leg
sample
line valve solenoid inside containment
was loose
on the valve body.
This has
subsequently
been repaired.
The
inside-containment
electrical
covers
were
missing
many
fasteners.
Several
nearby
pieces
of cable
tray
cover
and
associated
fasteners
were
missing.
These
have
subsequently
been
repaired or completed.
The dogged
doors to the four containment
coolers
had
some or all dogs
unengaged,
yet had
been aligned for operation
and were running.
The
fans were not requi red by TS at the time.
The licensee
was informed
of the
unengaged
dogs.
This issue
is
URI 335,389/89-10-05
pending
licensee
evaluation
and
NRC review of the Unit
1 cooler configuration
and accident
performance.
The
power
to Class
lE solenoid
valves
I-FSE-26-20,23,24
etc.
inside
containment
were unsealed
between
the solenoid valves
and the
Conax conduit seals.
The valves are
used to sample
containment air.
Plant
drawing
2998-B-271,
Sheet
11,
Rev
2 .required
that
they
be
sealed.
The
Rev
1 drawing,
in effect
when 'the unit was licensed,
specified 'ater'egarding
the sealing
requirements.
The licensee
has
subsequently
sealed
the
power leads.
This issue
is
URI 335,-
389/89-10-06
pending
licensee
evaluation
and
NRC
review of the
sealing
requirements
for these
valve solenoids.
4.
Plant Operations
Review (Units
1 and 2) (71707)
The inspectors,
periodically reviewed shift logs
and operations
records,
including
data
sheets,
instrument
traces,
and
records
of
equipment
malfunctions.
This review included control
room logs and auxiliary logs,
operating
orders,
standing
order s,
jumper
logs
and
equipment
tagout
records.
The
inspector s
routinely
observed
operator
alertness
and
demeanor
during plant tours.
During routine
operations,
control
room
staffing,
control
room
access
and
operator
performance
and
response
actions
were
observed
and
evaluated.
The
inspectors
conducted
random
off-hours inspections
to assure
that operations
and security
remained
at
an acceptable
level.
Shift turnovers
were
observed
to verify that they
were conducted
in accordance
with approved
licensee
procedures.
Control
room annunciator
status
was verified.
The
inspector
performed
general
reviews of the Unit
2
EDG tag out for
maintenance
and postmaintenance
electrical
tag outs.
With the
lA1 water box discussed
in paragraph
6 below returned to service,
the
inspector
observed
control
room operations
during
power ascension.
The inspector
observed
no problems with the power ascension.
The inspector
observed
the Unit 2
SDC system during mid-nozzle operation,
which was initiated after refueling
and landing the reactor vessel
head.
The operators
had
manned
both the local
and
control
room
nozzle
level
indications.
Certain operations
personnel
had been to an
INPO seminar
on
mid-nozzle operations
which apparently contributed to the site
operators'acility
in this area.
Smooth operation
in this
mode
was
observed
over
portions
of
a
three
day
period.
During this
period,
the
operators
reported
some blockage of a flow indication instrument line.
The blockage
was easily flushed from the line.
At all times observed
by the inspector,
the licensee
maintained
a watchstander
at
a temporary reactor water level
indicator inside the
RCB.
By March 30,
1989,
the licensee
had filled the Unit 2
RCS and prepared
to
remove
gases still trapped
in the
from the filling process.
The
applicable
procedure
was
OP 2-0120020,
Rev
27, Filling and Venting the
RCS.
The inspector
observed
operation
of the
as
they were
used to
force or
sweep
the
gas
pockets
or voids in the
toward
system
high
points.
The four RCPs were alternately
run for brief periods.
When each
was
st'opped,
the
RCS high point vents
were
opened
and
then
closed
when
indication of pure fluid was
observed.
Procedure
OP 2-0120020
had
been
recently
revised
and
was
unclear
on
several
points;
three
temporary
changes
were required to make the instructions compatible (the last being
TC 2-89-154) with the desired intent.
The site was using the
SDCS relief
valves for RCS
LTOP.
During the performance
of the five second
pump runs,
one of the reliefs inadvertently lifted with no
harm to the
equipment.
The operators
reduced
RCS pressure
to reseat
the relief valve
and
then
resumed testing.
Technical Specification
Compliance (Units
1 and 2) (71707)
The inspectors
verified compliance with selected "TS
LCOs. This included
the
review of selected
surveillance
test results.
These verifications
were
accomplished
by direct observation
of monitoring instrumentation,
valve
positions,
switch
positions,
and
review of completed
logs
and
records.
The
licensee's
compliance
with
LCO action
statements
was
reviewed
on
selected
occurrences
as
they
happened.
The
inspectors
verified that plant procedures
involved were
adequate,
complete,
and
the
correct revision.
Instrumentation
and recorder
traces
were
observed
for
abnormalities.
Naintenance
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
were
considered
during this
review;
limiting conditions for operations
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.
Work requests
were reviewed to determine
status of outstanding
jobs
and to assure
the priority was assigned
to safety-related
equipment.
The inspectors
observed
portions of the following maintenance activities:
This inspection
included
follow-up of instances
reported at another site
where
some Century Series
(nuclear safety grade)
HFA relays would bind and
fail to close if the four screws
in the
back that hold the coil to the
case
were
loosened
then retightened
after
shaking
the relay.
This would
simulate
the effects
of vibration or earthquake.
The site staff
had
procedures
for inspection
and testing of HFA relays
but was
not familiar
with this condition.
The first spare relay tested failed.
The site staff
consulted with the vendor
and found that the condition was discussed
in GE
SAL 188. 1,
HFA Armature Binding, dated
November
14,
1986, which could not
be found on site but was obtained.
The target date
range for the
SAL was
January,
1983 through October,
1986.
Licensee
inspection
found
109
HFA
relays in stores,
of which about
48 were Century Series.
Fifty six of the
109
showed target
date
codes
and
were all inspected.
Ten (nine Century
Series)
of the
56 failed
and
were
removed
from stores.
Failed
relays
seemed
to
have
been
received
in groups rather
than
scattered
throughout
the. inventory.
The remaining
53 relays in stores with date
codes
outside
the
. target
range
were
sampled
by
shipment
and
type, if a
shipment
contained
more than
one type.
None failed.
All Unit-2 installed
safety-
related
and control
room relays were inspected
by the licensee for target
date
codes - one was found. It passed
the inspection.
The plant staff's
response
to the inspector's
information was prompt and
thorough.
The plant staff plans
to inspect
Unit
1 installed relays
for
this condition during the
next
shutdown.
This appears
to be
reasonable
because
relays
are
routinely tested
upon installation
and during major
plant outages,
and
no failures in service
due to this condition have
been
identified.
Since the time of Generic Letter 83-28,
Salem
ATWS Event,
licensees
should
have
had
a program for capturing
and resolving
vendor information.
This
SAL was also
discussed
in
Potential
Problems
With Electrical
Relays.
That the site staff was
unaware of this
SAL until informed by the
inspector
is identified as
URI 335,389/89-10-02
pending further review by
the licensee
and the
NRC.
When silicone
and
lead levels
became
elevated
in the
1B
EDG engine oil
samples,
a contractor
was
engaged
to change
the oil and filters.
The
EOG
engines
(two diesel
engines drive one generator),
which had been recently
overhauled
during
an outage
ending in January
1989,
were completing their
break-in
period with this oil
change.
The
50ppm
levels,
which
prompted
the oil
change
were
considered
to
be
from expected
bearing
break-in wear (the vendor
recommends
changing oil at 75ppm).
The silicone
was
thought
to
be
from
a
sealant
used
on gasket
seating
surfaces
and
thought
not to
cause
a
problem with engine
operation.
The
inspector
monitored the change
out and
examined
the three
sieve
screens
that filter
each engine's oil.
No problems
were identified.
An
inquiry
concerning
oil
around
the
(non-safety-related)
1A
main
condensate
pump
seal
and motor flange lip revealed
that the maintenance
department
was closely monitoring the
1A main condensate
pump motor, which
was losing approximately five pints of oil per week from a lower bearing
seal
(the reservoir for the bearing
holds thirty gallons of oil).
The loss
rate
had
been reported
as constant
over the previous
several
weeks.
The
site
had not had this type leak before
so the electrical
maintenance
group
had ordered
vendor drawings of the bearing
seal
area
in anticipation of
work.
A contractor normally overhauls
these
large motors during outages.
The licensee's
activities appeared
to be appropriate
and the inspector
had
no further questions
concerning this
pump motor.
On March 27,
1989,
Unit
1 reduced
power due to clogging of the condenser
tube sheets
by marine growth, with has
occurred routinely
and requires
a
power
reduction
for cleaning.
The
inspector
observed
part of the
1Al
waterbox tube sheet cleaning.
The
condenser
has
four
subcompartments,
or
waterboxes,
that
can
be
separately
taken out of operation for this cleaning.
The condenser
tubes
are protected
by plastic traps,
cylindric closed
screens,
which insert
into
each
tube
and
protrude
out into the
waterbox.
The traps
deter
organic growth from growing into the tubes.
Since
the relatively recent
advent of the traps,
cleaning
had consisted of pulling and
hand cleaning
the
traps
and
then
mechanically
raking
the
tube
sheet;
the
average
'leaning time with this method
was 8 to
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> per waterbox.
Maintenance
personnel
had
opened
the
waterbox
when
a
load dispatcher
requested
that the unit be returned
to power to support
emergent
power
needs.
To
expedite
cleaning
and
closure,
maintenance
utilized
a
mechanic's
suggestion
to
use
a
small
pressure
washer to clean
the tube
sheet.
The
crew
cleaned
for approximately
forty minutes.
With the
pressure
washer,
the debris
around
and covering
the traps
was literally
blown off the
tube
sheet
and
traps.
Condenser
efficiency returned
to
nearly normal after the limited cleaning.
The licensee
has
subsequently
cleaned
all
of
the
Unit
1
condenser
waterbox
tube
sheets
with this
pressure
washing technique with an average
cleaning
time of four hours
per
waterbox.
During the return to power from the waterbox cleaning discussed
above,
the
inspector
observed
IKC department
personnel
replacing
a module
in the
B
channel
cabinet of the Unit
1
RPS.
The channel
had developed
problems
in
the high power trip portion of its circuitry during the previous
evening.
The operators
were extremely careful
during the power ascension
to check
the
operation
of
the
other
three
system
channels.
The
technicians
returned later that evening
and
replaced
other modules in the channel
to
finally remedy the problem.
The, inspector
reviewed
the plant work order
associated
with the work and found
no problems.
The installing of the Unit 2 containment
maintenance
hatch
and torquing of
the twelve mounting bolts
was
observed
.
Maintenance
procedure
M-0311,
Rev
5,
was
the
applicable
procedure.
The bolts
were
lubricated
as
specified.
The
procedure
specified
a
standard
x-pattern
for
application
in two pa'sses,
with the intermediate
and final torque values
specified.
Maintenance
procedure
M-0039,
Threaded
Fasteners
of Closure
Connections
on
Pressure
Boundaries
and Structural
Steel,
defines
the
standard
x-pattern.
The personnel
installing the hatch actually
made
two
passes
at each
torque value but did not use the standard
x-pattern for any
pass.
One bolt was totally missed during the intermediate
torque setting.
TS 6.8. 1
requires
that
procedures
listed
in
Regulatory
Guide
1.33,
Appendix
A, shall
be
followed.
Appendix
A,
paragraph
9.a.,
includes
maintenance
that can affect the
performance
of safety-related
equipment.
Paragraph
3.f.
includes
procedures
for maintaining
integrity of the
containment
system.
-Failure
to
follow procedure
M-0311
is
a
violation
of
TS 6.8. 1.
335,389/89-10"01
Review of Nonroutine Events
Reported
by the Licensee (Units
1 and 2)
Non-routine plant events
were
reviewed for potential
generic
impact,
to
detect
trends,
and
to
determine
whether
corrective
actions
appeared
appropriate.
Events which were reported
immediately were also rev'ewed
as
they occurred
to determine
that
TS were being
met
and that the
public
health
and safety were of upmost consideration.
There
were
two security-related
LERs
that
were
reviewed
by regional
personnel.
The results will be found in IR 335,389/89-11
as
one violation
with two examples.
On March 21,
1989,
Unit
2
had
a
CIS actuation
while the unit was
in
a
refuel.ing outage.
With one of four containment radiation
channels
having
no output
and
being
troubleshot,
and
a
second
channel
being
disabled
(tripped) for maintenance,
an operator
pressed
the source
check pushbutton
for
the
channel
being
trouble
shot.
The
operator
believed
that
the
tripped channel
was bypassed
instead of tripped.
The operator
was trying
to get
some reaction out of the channel - he did.
The trip setpoints for
all of the
channels
had
been
reduced
to
90
mrem/hour
for the
outage
instead
of the higher
normal
set point of 10 Rem/hour.
The source
check
signal
exceeded
the
lowered trip setpoint
and tripped the
channel.
Two
out of four channels
being tripped properly initiated the
CIS.
The
CIS
actuation
then
properly initiated
an
EDG start.
Once
the
operator
realized
that
the
CIS
was
actuated,
he
reset
the trip
and
restored
effected
equipment to the desired state.
The running
EDG tripped
on indicated high crank case
pressure
coincident
with the reset
of the
CIS actuation
discussed
above.
The
EDG high crank
case
pressure
trip is
locked
out during safety-related
operation
and
reinitiates
upon reset
of the
safeguard
system actuation,
in this case,
the
CIS actuation.
The high pressure
indication
came
from oil splashing
on
a weakened
sensor in'he
crank case.
The
EDG had not yet received
a
planned modification to prevent extraneous oil splashing
from causing
trips.
The modification,
a
splash
guard
in front of the
sensor,
was
installed along with a
new sensor
shortly after the
EDG trip.
While attempting
to complete
a surveillance
on the
2A EDG a thrust pillow
block bearing
assembly failed on
a radiator cooling fan.
This occurred
on
April 6,
1989, after outage
repairs
which were not bearing-related
had
been
completed.
On Unit 2, there are
two diesels
per generator with two
belt-driven cooling
fans that cool
one radiator
per diesel.
The failed
bearing
took the thrust of one of the
fans for 56 minutes of a one hour
test prior to the
inner
race failing from undetermined
causes.
The
licensee
has committed to submit
a special
report
on the valid failure and
determine
potential
10
CFR part
21 reportabi lity.
The failed race
had
what appeared
to
be
an existing crack that
suddenly
propagated
farther
causing
a loss of the
race
and thrust loading.
The fan
moved into the
shroud
at
the
radiator.
The
fan. rubbing
on
the
shroud
alerted
the
operations staff to the problem.
The licensee
has initiated an inspection
of other bearings
on this
and
the
second
EDG serving
the unit; the
Unit
1
EDGs are of a different design.
The inspectors will follow up
on
this event,
which had
become
the critical path for the unit returning from
the outage.
Physical
Protection (Units
1 and 2) (71707)
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
b'eing locked and alarmed.
9
~
Surveillance
Observations
(61726)
The
inspectors
verifiecl that
various
plant
operations
complied with
selected
TS
requirements.
Typical
of
these
were
confirmation
of
TS
compliance for reactor
coolant chemistry,
refueling water tank 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 instruventation
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
The
performance
of the local
leak rate test of the Unit
2 containment
maintenance
hatch
was witnessed.
The procedure
was
OP
1300051,
Rev 3,
Local
Leak
Rate Testing.
The test
was
performed
smoothly
and
the
hatch
seal did not leak.
The inspector
had
no further questions.
The performance
of the Unit
1
AFW flow channel
check
was observed.
The
governing
procedure
was
IKC procedure
1-1400064F,
Rev 4, Installed
Plant
Instrumentation
Calibration (Flow), Appendix 'B', tab
6.
The inspector
observed
the check at the flow transmitter.
The site technician
used
the
appropriate
test
equipment
and
performed
the
procedure
correctly.
The
procedure
had specified neither the deflection
range for maximum flow nor
a tolerance
for that range.
This did not agree with a proposed
change
to
the
channel
check criteria
which
was
in
a
procedure
revision
to
an
administrative
procedure titled Schedule
of Periodic Tests,
Checks,
and
Calibrations.
The technician
had
independently
pulled
the
range
and
tolerance
information
from another
document
and written them
on his copy
of tab
6 of the procedure.
When asked. about
the the
range
and tolerance
absence
in the applicable
procedure,
the
inspector
was told that
the
procedure
was being
changed.
The inspector verified that this was,
in
fact,
occurring.
The
low pressure
side
isolation
valve
on
instrument
+T-09-2C was found to be leaking slightly; the leakage did not invalidate
the test.
The technician
took action to submit
a
PWO to repair
the valve.
~
The, inspector
had
no further questions
on this test.
Part of a periodic test
on the MSIVs was observed.
The procedure
involved
was
OP
1-0810050,
Rev 8,
Main
Steam
Valves
Periodic
Test,
part
8. 1,
Part-Stroke
Test of MSIV.
This
segment
of the test
was
performed with
Unit
1 at power.
The procedure
operates
the valves through approximately
5/8 of an
inch of travel.
The test
was
performed
per
procedure.
The
valves
were
returned
to their normal
operating
position.
The inspector
had
no further questions
on this test.
IN 89-32, Surveillance Testing of Low Temperature
Overpressure
Protection
Systems,
dated
March 23,
1989, arrived
on site prior to Unit 2 requiring
the indicated
valves for LTOP.
Initial licensee
evaluation
of. the
IN
'0
found that
more
consideration
was
necessary.
After reevaluation,
the
licensee
wrote
a
new
LTOP test titled "Test Method D" of Data Sheet
10 in
AP 2-0010125A.
During performance
of the test at
a test
pressure
less
than
the
set
point,
the
Unit
2
valves
opened fully in about
2
seconds.
The
accident
analysis
of April,
1986,
page
21,
states
the
assumption
that the valves
would
pop
open
instantaneously
to their full
flow position.
The licensee
was
requested
to confirm that the accident
analysis
assumptions
are valid and actually bounc'he
system
response.
The validity of the
accident
analysis
is
URI 335,389/89-10-03
pending
licensee
completion of the evaluation
and
subsequent
NRC review.
10.
Outage
(71707)
The inspector
observed
the following overhaul activity during the ongoing
Unit 2 outage:
Licensee
performance
of portions
of the fuel bundle
and
CEA location
and
orientation verification,
as
a part of their refueling activities,
was
reviewed.
The fuel shuffle
had
been
completed
and work activities
were
moving
toward
reactor
vessel
closure.
With site
gC
present
and
independently
recording the data
on procedure
data
pages,
the operations
group
and reactor. engineering
personnel
video taped
the serial
numbers,
location,
and orientation of the components.
The personnel
involved with
the verification rode
the refueling bridge,
from which the underwater
TV
camera
was
suspended
and
operated.
The operation
was
conducted
in
a
methodical
and orderly fashion.
Visibility was excellent
and the data
recorded
while the inspectors
were present
agreed
with the
inspectors'bservations.
Clean
up and close
up activities within the containment
were observed just
prior to vessel
head installation. This included work controls for various
jobs that were active during this period.
Most jobs appeared
to be worked
through
from start to completion.
The job sites
were cleared
of debris
and
the
systems
were
closed.
The
exception-
was
the
electrical
yenetrations
and other items indicated in report section
3.
Clean
up
and
removal of scaffolding was orderly and accomplished
in a safe
manner with
little risk to adjacent
equipment.
With the
lower core
internals
in
place,
hydrolazing activities were observed
around the reactor vessel
area
and in the vessel
stud holes.
The areas
were
vacuumed
(except
under
the
reactor
vessel
stud
hole cleanliness
covers)
prior to
and after
the
hydrolazing.
During the
outage,
a
C&D Power
System
Inc. battery
was
replaced
in
a
nonsafety-related
application
on Unit 2..
Problems with the type
LC-33
batteries
are
discussed
in
Contamination
and
Degradation
of
Safety-Related
Battery Cells, of February
22,
1989.
Two of the cells of
the
battery
being
replaced
exhibited
transfer
(contamination)
problems
discussed
in the notice.
The site continues to run surveillance
on this battery
as well
as
the safety related batteries.
The inspector
was
informed
that,
although
the
battery
was
being
replaced,
the
replacement
schedule was'eing
very conservative
in that tests
indicated
thai the replaced battery
had substantial
power reserve.
The installation of the high pressure
turbine generator cover/throttle
and
control valve housing
was observed
by the inspector.
Three valves in the
four
valve
group
had
been
replaced
during this
outage.
The
seating
surface
of the
cover
had
been
modified this
outage
by
the
turbine
contractor to facilitate repair of steam
leakage
between
the cover
and its
mating lower half.
Turbine blading
had also
been replaced.
The movement
and seating of the cover went well with no incidents.
This outage,
the site staff overhauled
the
2A containment
spray
pump for
the first time.
Some short time after the postoverhaul
surveillance
test
had
been
completed, it was
noted that the mechanical
seal
had developed
some static
head
mechanical
seal
leakage.
The mechanical
seal
had
been
replaced during the original overhaul of the
pump. It was decided
to open
the
pump again.
The inspector
was present for the removal of the
pump
and
motor
combination.
The
applicable
procedure
was
general
maintenance
procedure
2-M-0045,
Rev
0,
Oisassembly/Reassembly
of Containment
Spray
Pump.
The procedure
contained
several
weaknesses
which did not apparently
cause
actual
work problems this time:
The procedure
was
not
as radiologically ALARA conscious
as it could
have
been.
Procedures
that support
work preparation
outside of the
radiological
work area,
rather
than
in the
area,
are desirable.
Though the health physics staff had anticipated
higher radiation
and
contamination
levels than
found
upon
pump/system
entry,
the working
procedure text did not call out the various fastener
sizes
such that
the mechanics
could prestage
tools.
The mechanics
were measuring
the
fasteners
on the
pump to determine
what wrenches to use.
Oue to the
low radiation levels
found around the
pump at that time, this
posed
no particular problems.
The procedure text allowed prying on the stationary
side of the seal,
which
was
a
quote
from the
applicable
vendor
manual.
Literal
adherence
could
result
in
seal
damage.
The
pump did
pass
its
subsequent
surveillance test.
The root cause
of the
seal
leakage
was not available
by the
end of the
inspection
period.
Site personnel
have taken
notes
on the work evolution
and procedural
anoma1ies
and
have planned
a post-work debrief.
Plant staff 'preparation
for the integrated
leakrate test
was
reviewed.
One of the
steps
taken
was to replace
a leaking metal
in
a steam
generator
blowdown valve with. a
rubber
for the test - without
accounting for the leakage
path that
had existed.
This was based
on
sections
6.2.4.2,
System
Oesign,
and 6.2.4.4,
Tests
and Inspections,
which
12
classify
these
as
meeting
Closed
System Isolation
Valves.
GDC 57 discusses
lines that penetrate
the containment
vessel
that
are neither part of the
RCPB nor connected directly to the containment
atmosphere.
connects
the
system directly to
the containment
atmosphere.
It is not clear whether or not this condition
was considered
by the
NRC in formulating acceptable
tests.
This issue is URI 350,389/89-10-04
pending further
NRC review.
11.
Licensee Action on Previous
Enforcement Natters
Not addressed
during this inspection
period.
12.
Exit Interview (30703)
The inspection
scope
and findings were
summarized
on April 10,
1989 with
those
persons
indicated in paragraph
1 above.
The inspector described
the
areas
inspected
and discussed
in detail
the
inspection
findings listed
below.
The licensee
did not identify as proprietary
any of the material
provided
to
or
reviewed
by
the
inspector
during
this
inspection.
Dissenting
comments
were not received
from the licensee.
Item Number
Status
Descri tion and Reference
389/89-10"01
open
VIO - Failure to follow maintenance
procedures,
paragraph
6.
335,389/89-10-02
open
335,389/89-10-03
open
335,389/89-10-04
open
335,389/89-10-05
open
335,389/89-10-06
open
h
13.
Acronyms and Abbreviations
URI - Site staff unaware of GE SAL
188. 1 (HFA relays)
since
1986,
paragraph
6.
URI - Validity of the
LTOP accident
analysis,
paragraph
9.
URI - Applicability of GDC 57 if
on
SG blowdown valves leak,
paragraph
10.
URI - Operability requirements
for
Containment Coolers,
paragraph
3.
URI - Sealing
requirements
for
Class
1E solenoids
in containment,
paragraph
3.
Alternating Current
Auxiliary Feed Mater (system)
As
Low as Reasonably
Achievable (radiation exposure)
Anticipated Transient Without Scram
13
CFR
CIS
GDC
IFI
IN
IR
LCO
LER
MFIV
NRC'pm
PWO
RCB
Rev
SDCS
-SIT
TS
, Appendix A)
(system)
Control
Element Assembly
Code of Federal
Regulations
Containment Isolation System
Direct Current
Emergency
Core Cooling System
Emergency
Diesel
Generator
Final Safety Analysis Report
General
Design Criteria (from 10CFR 50
High Pressure
Safety Injection (system)
The Florida Power
and Light Company
NRC Inspector
Follow-up Item
NRC Information Notice
Instrumentation
and Control
Institute for Nuclear
Power Operations
I'nspection
Report
(NRC)
InService Inspection
(program)
Low Temperature
Overpressure
Protection
TS Limiting Condition for Operation
Licensee
Event Report
Low Pressure
Safety Injection (system)
Main Feed Isolation Valve
Nuclear Regulatory
Commission
Part(s)
per Million
Pl ant Work Order
Quality Assurance
Quality Control
Reactor
Containment Building
Pump
Reactor Coolant Pressure
Boundary
Revision
Shut
Down Cooling
Shut
Down Cooling System
Safety Injection Tank
Technical Specification(s)
NRC Unresolved
Item
Violation (of NRC requirements)