ML17223A317
| ML17223A317 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 08/29/1989 |
| From: | Crlenjak R, Elrod S, Michael Scott NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17223A316 | List: |
| References | |
| 50-335-89-20, 50-389-89-20, NUDOCS 8909140149 | |
| Download: ML17223A317 (17) | |
See also: IR 05000335/1989020
Text
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UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTAST., N.W.
ATLANTA,GEORGIA 30323
Report
Nos:
50-335/89-20
AND 50-389/89-20
Licensee:
Florida Power
8 Light Co
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
Conduct
-:
11 August 14,
1989
Inspect
S. A.
ro
o
Resident Inspector
at
Signed
M. A. Sco
, Res'n
In pecto
Approved By:
R.
V. Crlenjak,
ection Chief
Division of Reactor Projects
Date Signed
D te
Soigne
.SUMMARY
Scope:
This routine resident .inspection
was
conducted
onsite in the
areas
of plant
operations
review, maintenance
observations,
surveillance
observations,
safety
system inspection,
and followup of previous inspection findings.
Results:
Three previously identified unresolved
items
have
been identified as violations
and
are
being
considered
for potential
escalated
enforcement
action.
Additionally, one other
new unresolved
item * was identified.
Within the
areas
inspected,
the following violations were identified and are
being considered for escalated
enforcement:
1B fuel oil transfer
system inoperable,
paragraph
7.
Containment
cooler
temporary -filter media
installed
during
plant
operation,
paragraph
2.a.
Containment
cooler
access
doors
not properly sealed
in required
modes,
paragraph
7.
Within the areas
inspected,
the following *URI was'dentified:
Unexplained plant modification, paragraph
2a.
- Unresolved
items
are matters
about
which
more
information is required
to
determine
whether they are acceptable
or may involve violations or deviations.
890&i40i49 890831
ADOCK 050003::5
REPORT
DETAILS
Persons
Contacted
Licensee
Employees
"D. Sager,
St. Lucie-Site Vice President
- G. Boissy, Plant Manager
- A. Bailey, guality Assurance
Super visor
'*J. Barrow, Operations
Superintendent
- J. Barrow, Fire Prevention Coordinator
- S. Brain,
Independent
Safety Evaluation
Group
'*H. Buchanan,
Health Physics
Supervisor
- C. Crider, Outage Supervisor
- D. Culpepper,
Site Juno Engineering
Manager
- R. Dawson, Maintenance
Superintendent
- C. Leppla,
IKC Supervisor
- L. McLaughlin, Plant licensing Supervisor
- L. Rogers, Electrical Maintenance
Supervisor
- N. Roos,
equality Control Supervisor
- R. Sipos,
Service
Manager
- D. West,
Technical Staff Supervisor
- E. Wunderlich, Reactor Engineering Supervisor
Other
licensee
employees
contacted
included
engineers,
technicians,
operators,
mechanics,
security force members
and office personnel.
NRC Employees
- P. Madden,
Region II Project Engineer
- M. Scott, Resident Inspector
- Attended exit interview
and initialisms used
throughout this report are listed in the
last paragraph.
Review of Plant Operations
(71707).
Unit
1
began
the inspection
period
in day
12 of an
outage to replug
certain
SG tubes.
On July 17th, at 3:00
am, the unit tripped from 15
percent
power during. restart
from the outage.
'Power operation
was
resumed
by early the 18th.
During the
SG replugging,
44 'A'G hot leg,tube
ends
where
replugged
and
19 'B'G hot leg tube
ends
were replugged.
The
licensee
intends
to replug
the
cold leg
tube
ends
during
the
next
refueling outage.
The unit ended
the period at
100 percent
power.
Unit 2 began
the inspection
period at power.
The
2A heater drain cooler
expansion joint began to leak
on August 14.
The unit ended
the period at
approximately
80
percent
power
while the
leaking joint was
being
evaluated.
On July 18,
1989,
the
SALP presentation
was given by the
NRC at the site.
The presentation
Was well received
by the licensee
and
NRC management
toured the facility prior to and after the presentation.
The
SALP ratings
for licensee
were considered
to
be above
average
in most categories;
the
SALP report
was issued
as
IR 50-335,389/89-13.
a.
Plant Tours (Units
1 and 2).
The
inspectors
perio'dically conducted
plant tours 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 ECCS systems.
Valve,
breaker,
and
switch lineups
and
equipment
conditions
were
randomly verified
both locally
and
in the control
room.
The
following accessible-area
ECCS system
walkdowns
were
made to verify
that system lineups
were in accordance
with licensee
requirements
for
operability and equipment material conditions
were satisfactory:
The
1A LPSI
room piping was
inspected this period in detail.
The walkdown indicated that the piping
was in accordance
with
procedure
OP 1-0410020,
Rev. 24,
HPSI/LPSI - Normal Operation,
and
drawing
8770-G-078,
sheet
130,
Rev 5, Safety Injection
System.
During a tour of the Unit 1
ECCS space,
the inspector
noted that
1B
pump
discharge
vent
valve
V3920
was
leaking
approximately
3 to
5 cc/minute.
When attempts to vent and shut
.the valve failed to reduce
the leakage,
the valve
was repaired
within a few days
under
a
PWO.
The inspectors
performed
walkdown of the piping around the Unit
1
CST.
The
valve
lineup
was
in accordance
with drawing
8770-G-080,
sheet
3,
Rev.
26,
and
procedure
OP 1-0700022,
Rev
- Normal Operation.
Walkdown of the
major safety related
components
was satisfactory.
During the
above
walkdown,
two inch valve
V28145,
Condensate
Recovery
to
CST Isolation,
was
noted to be suspended
from the
3
side of the tank
on
a
25 foot vertical length of pipe.
This
line was
shown
on drawing 8770-B-124,
isometric
number
CR-23,
Condensate
Recovery,
Rev. 3.
The piping
down to the valve was
covered with metal
insulation to just above
the valve and the
line ended
approximately five inches
below the valve in an open
ended nipple.
There were
no hangers
on the line or the valve.
The condensate
recovery drawing indicates
other piping attached
to the existing piping as
a continuous
pipe run.
This other
pipe
no longer existed.
The drawing, issued
on March 20, 1978,
did not indicate
any modification that might have deleted
the
missing piping run.
The licensee
was researching their records
to determine
whether or not this piping configuration
had
been
'valuated
by their staff.
Additionally, the
site
was
determining if a plant modification existed to explain what had
happened
to the
removed
condensate
recovery piping and hangers.
,Corporate
and site procedures
which are consistent with license
and
regulatory
requirements
require
that
modifications
be
documented
and analyzed.
This is identified
as
URI 335/89-20-04,
Unexplained
Plant
Modification, until this situation is clarified by the licensee.
During
a Unit
1 containment
tour on July 15,
1989, with Unit 1
shut
down
for
tube
replugging, filter media
(blue
loosely-woven fibrous material)
was found covering the coils of
all four containment
fan coolers.
The filter media,
which was
covered
by
a matted dirt film, had
been
installed
during
a
previous refueling outage
as is commonly done to maintain'coil
cleanliness
during
the
outage.
There
was
no
procedure
to
install or remove the media for this unit.
However, there
was
a
procedure
for Unit 2,
which
was verified to
have
no media
installed.
The licensee
immediately
removed
the filter media
from the coils.
At. the
end of the reporting period,
the
licensee
was performing
an engineering
evaluation of coil/fan
cooler
performance
and previous operability with the media in
place.
The evaluation
was not yet available.
The licensee
had
also initiated
a
LER on the event.
Unit
1
requires
containment
fan coolers
to
be
operable for modes
1, 2, and 3.
With one containment
fan cooler
inoperable, it must
be
. restored
within
30
days if both
containment
spray
pumps
are operable,
or within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> with
one
containment
spray
system
or the reactor unit
must
be placed in hot shutdown within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
Between
February
1987
and July
15,
1989, all four Unit
1
containment- coolers
were potentially inoperable
due to temporary
filter media not being
removed following the last two refueling
outages.
This is identified as violation 50-335,389/89-20-02,
Containment
Cooler Temporary Filter Media Installed During Plant Operations.
b.
Plant Operations
Review (Units
1 and 2)
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
orders,
jumper logs
and
equipment tagout records.
The inspectors
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
inspectors
performed
an
in-depth
review of the
following
safety-related
tagouts
(clearances):
1-7-221-1
1-8-404-76
HVE-10B inlet damper breaker ¹40508
181 SIT outlet MV-3634 breaker
¹42113
The above clearances
were satisfactory.
8-118
Unit
1 Nitrogen to Condenser
(PWO 6122)
,9-13
Unit.1
1
(PWO 6627/61)
Drawing 8770-B-327,
sheet
1506,
associated
with tag
9-13,
contained
an
erroneous
electrical
cabinet
number.
A I&C foreman
was able, with difficulty, to
determine
the
appropriate
cabinet.
The
personnel
involved notified an
I&C foreman
who leads
a QIP team
in
human
factors
concerns
related
to electrical
drawings.
This particular problem will be resolved
via the
IP team.
Q
8-127
. Unit
1 TR-22-1, Point 2, terminals
G-3, G-4
(PWO
6372)
The
inspector
examined
the following jumper
log tags
(circuit
alteration tags):
The
above
jumpers
were in accordance
with procedure
AP 0010124,
Rev.
20, Control
and
Use of Jumpers
and Disconnected
At about 3:00
am on July 17, while operators
were preparing to roll
the main turbine during
a startup,
Unit 1'ripped from approximately
15 percent
power.
The trip resulted
from low level in 18
SG.
The
RCO at the
SG level station
was shifting
main
feed.
The
RCO noticed
the
SG levels
decreasing
and
took
corrective
action but
SG level
continued
to drop until the trip.
Causal factors for the trip included:
Main feedwater line block valves
NV-09-7 and'V-09-8
were shut
and
main feed
water
could not get to the
SGs.
The startup
procedure
did not require
these
valves to
be
opened prior to
power ascension.
Previously,
RCOs
had automatically
checked
valve status,
located at a different control panel.
The audible
alarm accompanying
the pretrip annunciator
did not
alarm
when the
SG reached pretrip level.
This alarm was stated
to be used
by the operators
as
a warning,of the impending trip.
Corrective action included halting the startup until the annunciator
audible
alarm
was repaired.
Prior to restart,
a temporary startup
procedure
change,
which required
the block valves to'be checked
open
prior to main feed initiation, was
issued.
A permanent
procedure
change
was being processed
at the time of the restart.
The inspector
arrived
on site to review this event shortly after it occurred
and
determined that the licensee's
actions
in response
to this event were
satisfactory.
Unit 2 Turbine Load Runback
On July 22, Unit 2
Sigma
PIS 22-36,
which reads
out turbine
first stage
pressure,
began
to deteriorate.
The
provides
. feedback
to the turbine control circuits concerning
the
amount of
runback that
has
occurred.
The gauge
was reading artificially low
and, if left unrepaired,
could eventually
cause
a turbine runback.
The inspector discussed
the problem with the
NPS on shift.
The load-threatening
repair was planned for day shift on July 25 when
..support
would be available.
Operators
were briefed
on the intended
, repair
and possible operator actions
were discussed
should the repair
cause
generator
load problems.
During the repair, the
18C technician
shorted
the gauge
in such
a manner that
a runback with a zero-load
end
point
was initiated.
Due to the briefing and appropriate
operator
actions,
the
runback
was
limited to approximately
200
NW.
The
minimal reactor
response
was
as expected;
Tavg rose from 573 degrees
to
579 degrees,
pressurizer
pressure
rose
from 2250 psig to 2320
psig,
and
pressurizer
level
rose
from
65% to
73%.
Parameters
returned
to
normal
when
the electrical
load
was
restored.
The
licensee's
operations
staff
handled
the
well.
The
inspector
arrived
in the control
room within minutes after the
runback
and
assessed
the
reactor
conditions
with the onshift
operations
staff.
The inspector
also reviewed the
PWO C31592
work
package
and
found
no
problems.
The
repair
was
completed
successfully.
c.
Technical Specification
Compliance (Units
1 and 2)
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.
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, the correct revision and instrumentation
and
recorder traces
were observed for abnormalities.
No violations or deviations
were identified.
d.
Physical
Protection
(Units 1 and 2)
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.
Backshift security patrols
were
observed
during the observation
of
surveillances
such
as the fire protection item discussed
in paragraph
3.
No violations or deviations
were identified.
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
and
DC 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
performance
of monthly fire prevention
surveillance
OP
1800050,
Rev.
27,
Monthly Fire
Valves,
Fire
Pumps
Surveillance
and
Wet
Pipe
Sprinkler Systems
Test,
was observed.
The ANPO-required actions
were the
principal
area
observed.
Multiple valves that were checked
were missing
the metal identification tags that
had
been
hung during construction
and
the painted-on
valve identifiers
had not been verified to be correct.
The
valves
had to be identified by the
system
drawing.
Several
of the
ANPO
valves
were listed
on the
SNPO list and vice versa.
This created
some
confusion.
The
procedure
sketch
which
showed
some of the
remote
valve
locations
was not very legible.
The last
two items mentioned
were minor
human factor problems
but should
be corrected
by a procedure
change.
The
inspector also
noted that the fire pump miniflow recirculation line had
a
minor through wall leak at
a weld joint and required
a
PWO for its repair.
The inspector's
concerns
were identified to the licensee.
The
performance
of
OP
1-0110050,
Rev.
18,
Control
Element
Assembly
Periodic Exercise,
was observed.
CEA 23 would -not operate in the outward
direction.
One of the four upper electrical limit switches
was found to
be stuck shut.
This indicaged
to. the control circuit that the-control
element
was fully withdrawn, resulting in no out motion.
The switch was
disconnected
.from the circuit 'and
CEA 23 control
was
restored;
The
inspector
observed
operator,
supervisor
and
I&C repair activities during
this troubleshooting evolution and
had no further questions.
The performance
of
OP 1-0410050,
Rev.
27,
HPSI/LPSI Periodic Test,
was
observed for the Vnit 1, train A, pumps.
This monthly surveillance test
involved flow path valve lineup,
pump operation,
check valve operation
verification,
recording
pump
and
valve
program data,
and visual
inspection of the systems
in the
pump area.
The procedure
did not line up
the
pump recirculation
flow path,
however
those
valves
were lined
up
weekly by procedure
AP 1-00100125A,
Surveillance
Data Sheets,
Data
Sheet
36F,
and
checked
monthly per
AP 0010123,
Rev.
63, Administrative Control
of Valves,
Locks,
and Switches.
The test data
was properly obtained
and
recorded.
Several
small boric acid leaks
were observed
by the operator
and reported for repair.
The inspector
had
no further questions.
No violations or deviations
were identified
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
were
considered
during this review:
ICOs 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
the status
of outstanding
jobs
and to assure
that
priority was
assigned
to safety-rela'ted
equipment.
Portions
of the
following maintenance activities were observed:
(PWO C31592,
Maintenance
on Gauge
PIS 22-36) is discussed
in paragraph
2.b.
above.
(PWOs 1768/61, Air Filter, and 1802/61 Valve Replacement)
relating to
maintenance
on the
18 instrument air compressor
were
observed
in
part.
The compressors
are
approximately
one year old Atlas
Copco
models.
The suction
and discharge
valves
were removed for inspection
and,
though very little wear
was evident,
the licensee
replaced
the
valves.
In order to determine
and
document
the level of wear,
the
valves
were dimensionally
inspected
and
examined *by various site
personnel.
The licensee
has
plans to expand
the written instructions
regarding air. compressor
tear
down based
on the experience
gained
,duri.ng this evolution.
Work detai,ls
such
as
val.ues
for
fasteners
were
discussed
with the
vendor
and
implemented.
The
inspector
found the licensee'.s
ma'intenance
activity 'in this area to
be .satisfactory.
.(PWO
5184/61)
The electrical
.department
repaired circuit breaker
40508 for safety-related
fan
HVE lOB, the main
RAB exhaust fan.
The
packaged
replacement
assembly
that is
changed
out during breaker
overhaul
had
been previously replaced
on this breaker during the last
outage.
That previous replacement
package
was missing
a part causing
the breaker to not trip as designed while being manually racked out.
This condition had
no direct nuclear safety impact (i.e., the breaker
would have
performed normally in-service),
but could have
a personnel
safety
impact.
This current
work activity installed the missing
part.
The work was
performed without a supporting
procedure.
The
electricians
had
been trained
by the breaker
vendor
and did have the
technical
manual at hand.
The technical
manual.did not list detailed
work instructions
but listed
parts
and their function.
Per
discussions
with the electricians,
the vendor
had not discussed
the
particulars of the off-normal evolution which had occurred.
The work
proceeded
with difficulty but
was
completed
satisfactorily.
Subsequent
testing of the breaker
proved the item to be functionally
acceptable.
The department
was considering
procedural
changes.
At
the time of this work- observation,
the details of the missing part
problem
had not been relayed to the electrical
'department
management.
Once
alerted,
similar
breakers
were
inspected,
affected
breakers
identified,
and repair
work scheduled.
The missing part
problem
affected
3 of 9 recently-received
breakers.
The licensee is is aware
of the potentially-generic
nature of this
issue
and is discussing
this information with the breaker distributor.
During the
past
several
months,
the
inspectors
'had
observed
the
licensee
attempting repair of a seal
around
a safety related
pipe in
'-- the lA LPSI-room.
These seals
provide several
types of protection to
-- the
ECCS envelope.
The seal
material
in question
was
a putty- like
material that weighs
147 .to
177
pounds
per cubic foot; the material
stays in place
due to primarily surface friction between the material
and
the surrounding
(steel)
envelope.
The problems with the seals
were
generally
known to engineering
via
a
nonconformance
report
written in January
1989;
the fire protection
group
had written the
report based
on potential fire protection
boundary implications.
The
repairs initially involved forcing the existing
seal
back into its
position in the
room ceiling.
Subsequently,
engineering
generated
a
modification which included additional angle'iron"supports."
'NRC and
licensee
inspection
has identified additional
seals for repair.
The
licensee
was continuing to evaluate
the seals.
These
seals
which
were originally installed
by Tech-Sil, Inc.,
are
believed
to
be
installed at other utilities.
The licensee
and the
NRC are following
the evaluation for potential
informational release
as appropriate.
On June
28,
1989, the lower (most interior) of four seals failed in
the 2Bl RCP shaft seal
package.
This date
was also associated
with a
During this
inspection
period,
the
seal
package
condition
has
not continued
to degrade.
The licensee
has
been
monitoring
the
seal
package
condition
using
control
room
instrumentation.
The last
time
a
RCP seal
package
had
a similar
failure, the package
did not exhibit any additional
degradation
and
remained fully functional until the unit was shutdown for refueling.
5.
Safety System Inspection
(71710)
During the
1A LPSI
room piping walkdown,
discussed
in paragraph
2.a,
portions of the
CCW piping which provides cooling flow to
ECCS equipment
inside the LPSI
room were also
walked down.
The walkdown indicated that
the
CCW piping inside this room was in accordance
with drawing 8770-G-083,
Rev.
22,
Component Cooling System.
The walkdown and inspection of the
system will be completed during subsequent
NRC inspections.
No violations or deviations
were identified.
6.
Onsite Followup of Written Nonroutine Event Reports
(Unit 1) (92700)
(Open)
LER 89-02, Misaligned Valve Caused
Inoperability of the
1B Diesel
Fuel Oil System
Due to Personnel
Error,
was issued
on July 14, 1989.
The
event
was
discussed
in
a
previous
inspection
report
as
335,389/89-18-01
and in this report in paragraph
7.
The
LER remains
open.
7.
Followup of Unresolved
Items (Units
1 and'2)
(92701)
(Closed)
URI 335,389/89-18-01,
Mispositioned
1B Diesel
Fuel Transfer
Pump
Discharge
Valve.
Unit 1
requires that, for modes 1,2,3,
and
4 as
a minimum, two
separate
and independent
diesel
generator
sets
be operable,
each with: an
engine
mounted fuel tank containing
a minimum of 152 gallons of fuel,
a
separate
fuel storage
system
containing
a
minimum of 16,450
gallons of
fuel,
and
a separate
fuel transfer
pump.
With
a diesel
generator
set
operability of the remaining
AC sources
must
be demonstrated
within one
hour and at least
once
per eight hours thereafter.
At least
two offsite circuits
and
two diesel
generator
sets
must
be restored
to
status
within 72
hours
or the unit must
be in at least
hot
standby within the next
6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
On June
14,
1989, for a period of approximately
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />,
the fuel oil
transfer
pump discharge
valve for-the
1B
EDG was not in the required
open
10
position
and
the
remaining
AC sources
were
not demonstrated
within one
hour.
The
EDG would have automatically started
and
run if
needed
but the automatic
fuel makeup to the engine
mounted
tank would not
function.
The tank does
have
a level alarm to warn of low level.
Failure
to
have
an
fuel
transfer
system
is
violation
50-335/89-20-03.
-
URI -335,389/89-18-01
is administratively
closed
and
replaced
by this violation.
-'(Closed)
URI 335,389/89-10-05,"
Operability Requirements. for Containment
Coolers.
Containment
cooler doors
were discussed
in Inspection
Reports
335,389/89-10
and 89-16.
-: Unit
1
TS 3.6.2.3 requires
containment
fan .coolers to,be
operable, for
modes 1, 2, and 3.
With one containment fan cooler inoperable, it must
be
restored within 30 days if both containment
spray
pumps
are operable,
or
within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> with one containment
spray system inoperable,
or be in hot
shutdown within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
Unit 2 TS 3.6.2.3 requires that containment fan coolers shall
be operable
for modes
1, 2,
and
3.
With one containment
fan cooler inoperable, it
must
be restored within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in hot shutdown within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
8.
For Unit 1,
between
August
28,
1988
and April 12, .1989, all four
containment, coolers
were potentially inoperable
due to cooler access
doors
not being properly dogged after the last refueling outage.
Also, for Unit
2, the fan coolers
were potentially inoperable
from 1:56
am, April 14,
1989,
when the unit entered
Mode
3 with multiple access
doors improperly
dogged, until the dogs were adjusted
on April 15.
335,389/89-10-05
is
- administratively
closed
and
replaced
with
violation 335,389/89-20-01,
Containment
Cooler Access
Doors not Properly
Sealed
in Required
Modes.
Exit Interview (30703).
The inspection
scope
and findings were summarized
on August 15,1989, 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
"
Descri tion and Reference
335,389/89-20-01
open
VIO--Containment Cooler Access
Doors
not Properly
Sealed
in Required
Modes,
paragraph
7
335/89-20-02
open
VIO--Containment Cooler Temporary
Filter
Media
Installed
During
Plant Operation,"paragraph
2.a
11
I tern Number
335/89-20-03
'35/89-20-04
Status
open
open
Descri tion and Reference
EDG 18 Fuel Oil Transfer
System
paragraph
7
URIUnexplained
Plant Modification,
. paragraph
2.a
335,381/89-10-05
closed
URI--Operability Requirements
for
Containment
Coolers
335/89-18-01
closed
URI Nispositioned
1B Diesel
Fuel
Transfer
Pump Discharge
Valve and
Effects
on .EDG Operability
Abbreviations,
and Initialisms
AFM
ANPO
ANSI
BQAP
CFR
CIS
DDPS
DEY
FIS
GDC
GL
HVE
IFI
IN
ICW
IR
JPE
Alternating Current
Auxiliary Feed Mater (system)
As Low as Reasonably
Achievable (radiation exposure)
Auxiliary Nuclear Plant
I unlicensedj
Operator
American National
Standards
Institute
Administrative Procedure
Anticipated Transient Without Scram
Backfit Quality Assurance
Procedure
(EBASCO Services
Inc.)
Component Cooling Water
Control Element Assembly
Code of Federal
Regulations
Containment Isolation System
Condensate
Storage
Tank
Direct Current
Digital Data Processing
System
Deviation (from Codes,
Standards,
Commitments, etc.)
Emergency
Core Cooling System
Emergency Diesel
Generator
Flow Indication Sensor
The Florida Power
& Light Company
Final Safety Analysis Report
General
Design Criteria (from 10CFR 50, Appendix A)
NRC Generic Letter
" Health Physics
High Pressure
Safety Injection (system)
Heating
and Ventilating Exhaust (fan, system, etc.)
Heat Exchanger
NRC Inspector
Follow-up Item
NRC Information Notice
Instrumentation
and Control
Intake Cooling Water
Institute for Nuclear
Power Operations
Inspection Report
(NRC)
InService Inspection
(program)
(Juno
Beach)
Power Plant Engineering
12
JPN
LCO
LER
MFIV
MV
'MW
NRC
ONOP
OP
PIS
psi 9
ppm
PWO
QI
RCB
RCO
Rev
~
SDCS
SNPO
Tavg
TCW
TS
(Juno
Beach)
Nuclear Engineering
Low Temperature
Overpressure
Protection
(system)
TS Limiting Condition for Operation
Licensee
Event Report
Low Pressure
Safety Injection (system)
Main Feed Isolation Valve
Main Feed
Pump
Motorized Valve
'Megawatt(s)
Non-Cited Violation (of NRC requirements)
Nuclear Plant Operator
Nuclear Plant Supervisor
Nuclear Regulatory
Commission
Off Normal Operating
Procedure
Operating
Procedure
Plant Change/Modification
Pressure
Indicator/Switch
Power Operated Relief Valve
Pounds
per square
inch (gage)
Part(s)
per Million
Pressure
Transmitter
Plant Work Order
Quality Assurance
Quality Control
Quality Instruction
Reactor Auxiliary Building
Reactor
Containment Building
Reactor Control Operator
Reactor
Coolant
Pump
Reactor Coolant Pressure
Boundary
Revision
[NRC] Regulatory Guide
Reactor [licensed] Operator
Refueling Water Tank
Systematic
Assessment
of Licensee
Performance
Safety Assessment
System
Shut
Down Cooling
Shut
Down Cooling System
~ : Steam Generator
Safety Injection,Tank
Senior Nuclear Plant [unlicensed] Operator
Senior Reactor [licensed] Operator
Reactor
average
temperature
Turbine Cooling Water
Temperature
Element
Three Mile Island
Temperature
Recorder
Technical Specification(s)
13
NRC Unresolved
Item
VIO 'iolation (of NRC requirements)