ML17223A568
| ML17223A568 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 03/14/1990 |
| From: | Crlenjak R, Elrod S, Michael Scott NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17223A567 | List: |
| References | |
| 50-335-90-02, 50-335-90-2, 50-389-90-02, 50-389-90-2, NUDOCS 9003210041 | |
| Download: ML17223A568 (26) | |
See also: IR 05000335/1990002
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323
'eport
Nos:
50-335/90-02
AND 50-389/90-02
Licensee:
Florida Power
5 Light Co
9250 West Flagler Street
Miami, FL
33102
Docket Nos.:
50-335
and 50-389
License Nos.:
and
Inspecto
S.
A.
, Sen
r
R
Wo.c
Inspect'or
4iz.
M.
ott, Resident
nspector
Approved By:
.
V. Crle
ak,
S
ion Chief
Division of Reactor Projects
Facility Name:
St. Lucie
1 and
2
Inspection
Conduct
. January
- Febr ary 12,
1990
9 /p
Dat
Si
ed
Date Si
ne
7 /'f fd
Date Signed
SUMMARY
Scope:
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,
followup of previous inspection findings,
and allegation followup.
Results:
Unit
2 reactor
plant
was
heated
up
from cold to hot standby
and
the
reactor
was
taken critical
on January
13
and
14.
On January
14, Unit 2
tripped from about
50 percent
power and
was subsequently
restarted
on January
16.
Unit
1
was
shutdown
due to
a minor
1B
SG tube leak
and entered
into the
refueling outage early.
This was
a conservative
action
on the part of FPL.
On February
10,
an industrial injury at Unit
1 resulted in an unusual
event
being declared
based
on the individual being potentially contaminated.
The
individual was found to actually
be clean.
Additionally, on February
11, Unit
1
had
an apparently
spurious
CIAS.
At the
end of the inspection
period,
the
licensee
was researching
the reason
for the CIAS.
00321004i
900314
DR
ADOCK 05000335
Within the areas
inspected,
the following violations were identified:
Failure to implement preventive
maintenance
on the
2C
AFW pump governor,
paragraph
2.b...
failure to properly
implement
the Unit
2 startup
procedure,
paragraph
2.b.
Failure to properly retorque
an ADV, paragraph
4.
A noncited violation is discussed
in paragraph
3.
REPORT
DETAILS
Persons
Contacted
Licensee
Employees
- D. Sager,
St. Lucie Site Vice President
- G. Boissy, Plant Manager
- J.
Barrow, Operations
Superintendent
J. Barrow, Fire Prevention
Coordinator
H. Buchanan,
Health Physics
Supervisor
C. Burton, Operations
Supervisor
- C. Crider,
Outage Supervisor
- D. Culpepper,
Site Juno Engineering
Manager
R. Dawson,
Maintenance
Superintendent
- R. Frechette,
Chemistry Supervisor
J. Harper, guality Assurance
Superintendent
C. Leppla,
I&C Supervisor
- L. McLaughlin, Plant licensing Supervisor
- L. Rogers, Electrical Maintenance
Supervisor
- N. Roos, guality Control Supervisor
- R. Sipos,
Services
Manager
- D. West, Technical Staff Supervisor
W. White, Security Supervisor
- J. West, Mechanical
Maintenance
Supervisor
G. Wood, Reliability and Support Supervisor
E. Wunderlich, Reactor Engineering Supervisor
Other
licensee
employees
contacted
included
engineers,
technicians,
operators,
mechanics,
security force members
and office personnel.
- Attended exit interview
2.
and initialisms used
throughout this report are listed in the
last paragraph.
Review of Plant Operations
(71707)
Unit
1 began
the inspection
period at power.
The unit was shut
down on
January
22,
due to
a
SG tube leak
and
began
the refueling outage three
weeks earlier
than
scheduled.
Unit
1 ended
the inspection period, in a
refueling outage.
Unit 2 began
the inspection
period recovering
from a maintenance
outage
that
was primarily focused
on repairing
a pressurizer-safety-valve-to-
mounting-flange
steam leak.
The unit returned to power on January
16 and
had been operating for 26 days at the end of the inspection period.
During this inspection period,
on January
23, the St. Lucie facility was
toured
by
NRC Commissioner
J.R.
Curtiss,
Region II Deputy Administrator
J.
L. Hilhoan,
and
the
Commissioner's
Technical
Assistant,
K.
A.
Connaughton.
On January
24,. the resident
inspectors
participated
in the licensee's
large scale
emergency
exercise.
The NRC's evaluation of this exercise is
included in IR 335,389/89-31.
a 0
Plant Tours
b.
The
inspectors
periodically conducted
plant tours to verify that
monitoring equipment'as
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'aterial
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.
Yalve,
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:
Unit
1
AFW at the
Unit 2
AFW at the steam trestle.
Unit 2
EDG fuel oil storage
area.
Unit 1
II 2 batteries.
Plant Operations
Review
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.
Dur ing 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
status
was verified.
The
inspectors
reviewed
the
following safety-related
tagouts
(clearances):
number
2-1-17
2-1-17
2-2-48
2-2-45
Unit 2 Plant Heatup
component
2A HPSI
pump
2A charging
pump
2B Boric acid
pump
2C
AFW pump
Portions of Unit 2 reactor plant heatup
were observed
on January
13.
Heatup
was
performed in accordance
with procedure
OP 2-0030121,
Rev
29, Reactor Plant Keatup - Cold to Hot Standby.
In paragraph
3 of
the report
examples
of inadequate
surveillance
control
and locked
valve control observed
during the heatup
are discussed.
Testing of 2C
AFW Pump
On January
13, following the Unit
2 reactor plant heatup
to hot
standby,
the inspector
observed
the
2C
pump being tested
in
accordance
with
OP 2-0700050,
Rev
Periodic
Test,
in preparation for the
impending reactor
startup.
The
pump
oversped
and tripped, thus failing the test.
The overspeed
condition
and
subsequent
trip were attributed to governor
or
governor
valve'roblems.
On January
13,
The
governor
was
repaired
under
a
NPWO
by
changing the governor oil - followup testing
was unsatisfactory.
On January
14, the governor was flushed with oil through several
orifices - followup testing
was unsatisfactory.
Finally, after flushing the governor
compensating
needle valve,
the
pump
was
successfully
started
three
times
and declared
Unit 2 Reactor Startup
Reactor
startup
and
power escalation
began later
on January
14.
Portions
of the reactor
startup
were
observed
by the inspectors.
Criticality was
achieved
using
procedure
OP
2-0030122,
Rev
23,
Reactor Startup.
Unit 2 Reactor Trip
Late
on January
14, at 11:24 p.m.,
the Unit 2 reactor automatically
tripped
on low
SG water level
due to personnel
error.
Prior to
the event
a
2B
NFP
low suction
pressure
alarm
was
noted shortly
after
10:55 p.m.
At that time, the unit was at 325
HW (38 percent
power),
the
2B
NFP
and
2B condensate
pump were operating,
the load
was
increasing
at
4
NW/min,
and shift turnover
was in progress
between
the
evening
and night shifts.
Several
other operational
considerations
required
operator
attention
at this
same
time.
The
oncoming
NPS left the control
room following his turnover to
evaluate
an
MSR block valve indication problem.
No attempt
was
made
to stabilize the plant prior to or during the turnover period.
Procedure
OP 2-0030124,
Rev 31, Turbine Start-Up Zero to Full Load,
section
8. 19, requires that the second
condensate
pump be started at
approximately
400
NW and section
8.20 requires
the
second
be
started at approximately
420
NW.
A low 2B MFP suction pressure
alarm
was received shortly after 10:55 p.m.
and efforts were
made to both
halt the
power
ascension
and to start
the
2A condensate
pump.
Suction
pressure
on the operating
2B
MFP continued to drop
and the
pump finally tripped
from low suction
pressure.
The
2B
NFP
was
restarted
twice but tripped
each
time
and the
2A condensate
pump
failed to start.
SG water level
decreased
until low
SG levels
tripped the reactor.
By the time of the reactor trip, reactor
power
was
470
MW, approximately
52 percent
power.
The
I&C department
examined
the
MFP suction pressure trip setpoints
as part of the post trip review.
The required
MFP suction pressure
trip setting
was
275 psig (plus or minus
6 psig).
The "as-found"
trip settings
were
315 psig for 2B MFP and within tolerance for 2A
MFP.
The
2B MFP had tripped sooner
than required.
The
2B switch was
reset
to the
required trip band.
Subsequent
review found that
neither the Unit
1. nor Unit 2 MFP low suction pressure trip switches
had
been calibrated
since
each unit's initial start
up.
The Unit 1
switches
have subsequently
been
scheduled for calibration during the
February refueling outage.
Other pressure
switches that provided the
MFP low suction
pressure
alarm/annunciator
function were separate
from the switches that provided the trip function.
They were found
to have
been calibrated
every outage
and were confirmed to be within
the
allowed tolerance.
Following this event,
the
I&C department
started
a survey to identify other instruments
that might be in this
category.
Based
on the
above trip scenario,
the operations
department
planned
to implement the following:
Ensure
that the
SRO considers
stabilizing the plant for shift
turnovers during power
change evolutions.
Maintain an experienced
supervisor
in the control
room during
plant startup
and shutdown evolutions.
Provide
a more detailed startup
check list identifying equipment
to be in service at various
power levels.
Change
the turbine startup
procedure
tq provide clearer guidance
concerning
the startup of the condensate
pumps -and NFPs.
Failure to follow procedure
OP 2-0030124,
sections
8.19
and 8.20,
concerning starting the second
condensate
pump and
NFP is
a violation
of TS 6.8.1.,
and is identified as Violation 389/90-02-01.
Failure of 2C AFM Pump
During the reactor
plant trip, the steam-driven
2C AFM pump received
a legitimate
AFAS start
signal
but
oversped
and tripped.,
Two
electric
AFM pumps
were available to feed the
SGs.
After the plant
was stabilized,
the
pump
was
retested
and started satisfactorily
three times.
Following consultation
between
the
operators
and
senior
plant
management,
Unit
2
reactor
plant
startup
was re-initiated
at
approximately
6:00
a.m.
on January
15.
During this restart,
after
criticality but prior to adding heat to the primary, at about 6:30
a.m.,
the operators
attempted
to start the
2C
AFW pump in response
to
NRC concerns
regarding operability from cold ambient conditions.
The
pump oversped
and tripped twice prior to being successfully started.
It was declared
and placed in a 72-hour
LCO.
The reactor
startup
was
suspended
and the reactor
remained
in mode
2 until the
pump was returned
to operability.
The
licensee
then
developed
and
implemented
Moodward
governor
flushing and
PM instructions for the
2C
AFW pump in accordance
with
recommendations
of FPL-approved
vendor technical
manual
2998-12474,
Rev
Pump,
Tab 6.
The flushes
performed
previously
on January
13
and early
14th in accordance
with
NPWO
7649/62
were
found to have not been
in accordance
with the vendor
technical
manual
recommendations.
Proper flushing, directed
by
NPWO
7653/62,
implementing the vendor technical
manual
recommendations
and
using the
recommended
solvent, resulted in suspended
solids appearing
in the flush effluent.
Subsequent
investigation
found that there
was
no
governor
preventive
maintenance
performed
regularly
that
implemented
the
technical
manual
recommendations.
Further,
the
governor oil
had
never
been
changed
though
the
vendor
manual
recommended
that -.the governor
be flushed
and filled with new oil
approximately
every
six
months.
The
licensee
satisfactorily
completed
2C AFM pump maintenance
late
on January
15.
Extensive
testing
was
completed
early
January
16
and
the
pump
returned
to operability.
Power
ascension
and
subsequent
entry into
Mode
1 followed shortly.
Subsequent
turbine vendor review of the
licensee's
just-completed
maintenance
and
pump
testing
actions
produced
no negative
comments.
The
1C
AFW pump governor
was found to not share this problem.
It is
a different model
Woodward governor that uses turbine lubricating oil
from direct communication with the lubricating oil system.
That oil
had
been
changed
on
a periodic basis.
Section
4 of
NRC
IR 335,389/89-23
discussed
a previous similar
violation regarding safety-related
equipment
degradation
and failure
from the lack of, or inadequate,
preventive maintenance
procedures.
The licensee
is still implementing their corrective actions for this
violation.
In their
response
to that violation, the
licensee
coamitted to review
a sample of their mechanical
PMs.
The licensee
review found sufficient evidence
to warrant increasing
the review
scope
to include all mechanical
PMs.
This
2C
AFW pump governor
failure
suggests
that
the
original
problem
was
of
a
broader
.scope
than cited.
Failure to implement
a
2C
AFW pump governor
PM program
and failure
to address
the
recommendations
of the
approved
vendor
manual
is
a
violation of TS 6.8. 1. Additionally, the failure of the
2C
AFW pump
to start
and unavailability over
a several
day period is
a violation
of TS 3.7. 1.2.
This is identified as Violation 389/90-02-02.
Unit 1 Shutdown
Due to a
SG Tube Leak
On January
21 the plant operators
discovered
an increase
of about
50
counts per second in radioactivity levels of the continuous
sample of
the Unit
1 condenser air ejector discharge.
SG blowdown radioactivity
level
trending
indicated
increasing
1B
SG radioactivity levels.
Radiochemistry
analysis
confirmed that the leak was in the
1B
SG and
that it appeared
to have started
about
noon that day.
Unit 1 person-
nel initiated proceduralized
actions to reduce
the release
of radio-
active material
to the environment.
Over the next several
hours
these
actions resulted
in
a reactor
power reduction
and isolation of
the
IB SG.
On the morning of January
22, Unit
1 was shut
down to
enter
a
planned
refueling
outage
three
weeks
early rather
than
operate
with a leaking
SG,
even
though the leak rate
was well below
that allowed by the operating license.
No violations or deviations
were identified in this area.
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.
The licensee's
compliance with LCO action state-
ments
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.
No violations or deviations
were identified in this area.
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.
No violations or deviations
were identified in this area.
3.
Surveillance Observations
Various
plant
operations
were verified to
comply with selected
TS
requirements.
Typical of these
were confirmation of TS compliance for
reactor coolant chemistry,
RMT 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 following surveillance test(s)
were observed:
On January
13, while in mode
3 during plant heatup operations,
2A CS
'ump
discharge
check valve was confirmed to open in accordance
with
AP 0010125A,
Rev 16, Data Sheet
11,
Check Valves Cycled During Mode
5
(page
2 of 3).
The surveillance intention was stated
in the form of
a cryptic note
on the right side of Data Sheet
11 listing the valves
directly involved in the surveillance.
These
were locked valves
2-0010123,
Rev
40,
Administrative
Control
Program.
Since
the
surveillance
was sufficiently complex
and the plant was not in mode
5, the
ANPS wrote informal directions
to the operator,
including
positioning of several
locked flowpath valves not listed on the data
sheet.
Operators
did not enter locked valves into the locked valve
deviation log as required
as the valves were being operated,
nor was
there
a formal
procedure
being followed that would independently
verify return of the valves to their normal position.
By happen-
stance,
the next section
of
OP
2-0030121,
Rev
29,
Reactor
Plant
Heatup - Cold to-Hot Standby, later verified the lineup of most of
the
CS flowpath valves,
but it 'did not verify valves
and
2I-V07158, Isolation Valve to Containment
Spray
Pump Test Flowpath to
the
RWT,
B Side
and
A Side respectively,
which were locked valves
included in the Administrative Control Program.
Two condi.tions
violated
which required
procedures
be
adequate
and that they be followed.
Procedure
0010125A,
Data
Sheet
11,
was
inadequate
to
independently
control
the surveillance,
which involved locked
valves
that
required
independent
verification of position
changes.
The operators
in the control
room failed to follow procedure
2-0010123,
Rev 40, Administrative Control of Locked Valves.
The licensee
aborted
the surveillance
and
performed
a formal valve
lineup of the
CS system.
Though this
was
an isolated
example,
the
licensee
aggressively
evaluated
the
causes
of this problem.
Many
data
sheet
surveillances
were
found to be simple,
not requiring
an
actual
procedure
or independent
verification, but
some did.
Some
data
sheet
notes
were
found to create
confusion.
The licensee
initiated changes
to the surveillance
data
sheets
in
OP 0010125
so
that they would adequately
control surveillances
either directly or
by reference
to other procedures.
Because
of the licensee's
aggressive
review of this problem
and the
isolated
nature of the occurrence,
this violation is not being cited
and is identified. as
NCV 389/90-02-04.
For the Unit 2 startup,
the following surveillances
were observed:
The
RPS Monthly Functional
Test
was conducted
in accordance
with IKC
2-1400050,
Rev 15.
The Unit
2 SITs
were filled and pressurized
for the startup
in
accordance
with
OP 2-04100021,
Rev 21, Safety Injection Tank,
Normal
Operation.
No violations or deviations
were identified in these
areas.
On January
13th, the
2C
AFM pump was tested
and found unsatisfactory
in accordance
with OP 2-0700050,
Rev 15, Auxiliary Feedwater
Periodic
Test.
See paragraph
2.b for additional details.
On January
26, with Unit
1 in Mode 5,
the
safeguards
test
was
performed in accordance
with procedure
OP 1-0400050,
Rev 21, Periodic
Integrated
Test of the Engineered
Safety Features.
NRC observations
included
both control
room activities
and
equipment
performance
in
the
RAB, and the
EDG rooms for the load rejection part of the
test.
Several
test
anomalies
occurred
but did not invalidate the
test.
No violations or deviations
were identified in these
areas.
0
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
were
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 ser vice; quality
control records
were maintained; activities were accomplished
by qualified
personnel;
parts
and materials
used
were properly certified;
and radio-
logical
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-related
equipment.
Portions
of the
following maintenance activities were observed:
NPWO 3011/61
worked
the Unit
2 pressurizer
code
safety
valves.
During
a containment
inspection
Y1202 had been found leaking (see
IR
335,389/89-30).
This resulted
in the Unit 2 shutdown January 8, 1990.
All three valves were worked due to conditions
found on Y1202.
Aside
from Y1202 pressurizer-to-valve-flange
fastener
being
steam cut from
the leakage,
the fasteners
associated
with all 8 code safety valves
had "as-found" bolting torques
ranging from 0 to 250 ft-lbs.
This
variance
in "as-found"
was
thought to have
been
caused
by
previous
uneven
torque application to adjacent bolting fasteners
and
uneven crushing of the spira'l
wound gasket
involved in the mechanical
joint makeup.
Slugging
wrenches
had
been
used in this application
because
normal
wrenches
would not fit in the space
available
around the valves.
Upon
evaluating
the
"as-found"
data,
the
licensee
changed
the
procedure
for bolting the safety valve flanges
to the pressurizer
outlet flange
and incorporated
a hydraulic torque wrench to control
the fastener
torquing process.
The learning process
involved several
installations
and
removals of different combinations
of the three
safety valves.
Work atop the pressurizer
is considered
a high radiation risk (air
borne radioactivity and
50
mrem field requiring respirators
and
coverage.
Three
work delays
discussed
below
were
not
supportive:
Y1202
was reinstalled with the
new technique
and found to
be
unacceptable,
based
on
newly-applied
crush
criteria.
The valve
was
cocked relative to the pressurizer
outlet flange.
Interference
from the valve discharge
piping had
forced the valve to one side of the mounting flange
such that
metal
was raised
on the mounting flange during installation.
The
raised
metal
prevented
the
from mating
properly.
Subsequent
use of a chain fall on the discharge
piping corrected
this interference.
Interference
had
been previously addressed
by the
engineering
department
but
was
not addressed
in the
10
installation procedure.
The crew that installed the valve was
unaware of the potential
problem.
Guide pins were installed in the pressurizer
flange to guide the
valve to the installed position.
In use,
the guide pins were
found to be oversized
and work was halted to remachine
them.
Mork was
again
halted
once
the
valve
was
landed
on
the
pressurizer
The mechanic
involved requested
that the
work procedure
be obtained prior to proceeding;
a procedure
was
not at the work site
and
had to be brought in from outside
the
containment.
The mechanic,
up to the time
he requested
the
procedure,
had
been
aware of the procedural
requirements
to that
point.
The hydraulic torque wrench
used in the torquing the safety valve to
pressurizer
flange bolting fasteners
was
not in the
M&TE program.
Though the pressure
gage
was calibrated,
there
was
no pre-use
check
of the hydraulic unit.
This was formally recognized
by the licensee
after
work
completion
b'ut
prior
to
plant
repressurization.
Subsequent
evaluation
by mechanical
maintenance
engineering
found
that
the
wrong hydraulic pressure
to torque
conversion
chart
was
being
used
and the torque applied to the fasteners
was approximately
100 ft-lbs below the procedure
value.
Fortunately,
the procedure
value
was conservatively
high and,the
actual
were acceptable
in this application.
Later vendor evaluation
showed that the torque
applied
was about
30 ft-'Ibs low and that the licensee's
test machine
was
not well suited
to testing
hydraulic torque
wrenches.
The
licensee
has
initiated
the
procurement
of several
new hydraulic
torque wrenches
and appropriate calibration check devices.
In summary,
the licensee
made significant improvements
to both the
pressurizer
safety valve mounting
process
and the hydraulic torque
wrench program.
NPMO 5882/62 refilled the
2A1
upper oil reservoir.
All RCP
reservoirs
had
been
checked
and the 2Al RCP had the only low level,
which was 3.5 gallons short of the 45 gallon full mark.
The licensee
believed that this level
discrepancy
occurred
as
a result of the
reservoir
being slightly under filled during the last outage
plus
some
pump-to-oil-collection-system
leakage,
which can
be expected
du< ing normal operations.
No violations or deviations
were identified.
NPWO 7548/62
removed
the air operator for pressurizer
spray valve
VllOOF.
The valve
had
been worked during the Vnit 2 mini-outage for
packing
leakage.
Return to service
acceptance
testing identified
that the operator.: would not stroke
the valve.
The valve
had
been
worked in the last outage
as with each
outage
due to its importance
and location in a high heat environment adjacent to the pressurizer.
The diaphragm
was replaced at this time as
a conservative
measure.
11
No violations or deviations
were identified.
NPWO
7611/62
had
ILC
department
personnel
check
certain
instrumentation
vent points for boric acid leakage
during the Unit 2
mini-outage.
When discovered,
the technicians
would evaluate
the
leakage,
tighten the joint and document their findings.
No violations or deviations
were identified.
NPWOs
5885/62
to
5890/62
refurbished
several
safety-related
electrical
panels
in the Unit 2 steam trestle
space.
Aside from
containing
the
the
steam
and
feed lines,
SG safety valves,
ADVs,
MSIVs, MFIVs and
AFW pumps,
the trestle
space
contains
the electrical
control
panels for many of the
above
items.
Initially, two panels
with unlatched
doors
were identified to the licensee for evaluation.
After the licensee's
inspection,
NPWOs were issued to repair these
and
the additional trestle
panels
identified by the licensee.
The
trestle
space
has
been subject to recurring wetting
as
discussed
in
335,389/89-26,
section
5.
The two panels identified by the
NRC were
the
2C
AFW control panel
and
a MFIV control panel.
No violations or deviations
were identified.
NPWO 5871/62,
discussed
in IR 335,389/89-30,
was being worked at the
beginning
of this inspection
period
and
the
licensee
was still
evaluating
problems
associated
with the work.
ADV MV 08-18A was
worked
because
the transition plate
between
the valve operator
and
the valve yoke
had
become
loose resulting in dual
valve position
indication
being
annunciated
in the
control
room.
Without
a
procedure,
but with a trained engineer
and crew, the yoke, plate,
and
operator
were separated
and the associated
fasteners
were retorqued.
Since the vendor
technical
manual
did not provide torque values,
the
used
were
from
a standard
generic
torque table.
The socket
head
cap screws
were torqued to
125 ft-lbs.
The valve was returned
to service.
System flow diagram 2998-6-079,
sht 1, and the Valve List
drawing 2998-A-051, identified the valve as seismic Class
1.
The day
after
the valve
was returned
to service,
the job and the torquing
requirements
were discussed
with the licensee.
The licensee,
in
discussions
with the valve vendor about the fastener
torque value,
found that the required
should
have
been
80 ft-lbs.
The
licensee
subsequently
disassembled
the valve, replaced
the cap screws
in question,
and torqued the
new cap screws to the appropriate
value
prior to the unit starting up.
The above-indicated
overtorquing is violation 389/89-02-03,
Failure
of ADV 08-18A to meet
10CFR 50 Appendix A, Criterion 2, the design
basis for protection against
natural
phenomena.
Limitorque Corporation
maintenance
update
89-1, addressing
the valve
vendor's,
not Limitorque's, responsibility in providing torque values
for operators
or valves,
was
received
on site while work was in
progress,
.too late to affect this job.
The site electrical
department
had recently
assumed
responsibility
for
the entire motor operated
valve
assembly
and operator.
The
department
has
taken admirable efforts to take control of the motor
operated
valve program
and
improve it.
Procedures
for the different
types of valve
and
operators
have
been written.
The lack of a
procedure
for Limitorque type
SMB 4 operators
was
an exception.
In
addition,
the majority of the
personnel
in the
department
has
completed training on the valve operators.
The
licensee
is
going
to
review other
valves
that
may
have
misapplications
of torque
values
and
determine if this condition
detracts
from their se'ismic qualification.
a.
Outage Activities (62703)
The inspectors
observed
the following overhaul activities during the
ongoing Unit 1 outage:
NPWOs
1065/61
and 0872/61
covered
disassembly
of the MFPs.
The
inspectors
observed
various
aspects
of the
disassembly
and
overhaul activities.
Work Process
Sheet
6882-1529
performed
the Unit
1 pressurizer
heater
inspection for indications of boric acid and/or
cracks.
As indicated
in
IR 335,389/89-30,
made of
Inconel
600
are
possibly
subject
to degradation
problems.
During this outage,
21 suspect
a portion of the total
population,
were visually inspected
by
a level III NDE
inspector.
No external
evidence of cracks
was found.
Though
CE, the pressurizer
manufacturer,
had indicated that the sleeves
would have
unique identification numbers,
no numbers
could be
seen
during the initial inspection.
CE later explained
numbering discrepancies
in a letter.
Because of the uncertainty
introduced
by the lack of identification numbers, all heater
were inspected.
No evidence of leakage
was found.
The inspectors
observed
the detensioning
of the reactor
vessel
head
studs
and nuts in accordance
with procedure
1-M-0015,
Rev
18,
Reactor
Vessel
Maintenance.
The inspectors
subsequently
observed
inspection
of the
studs
and
nuts
under
the
same
procedure.
The inspectors
observed
the health physics
survey of the
RDT for
work to be accomplished
during this outage.
13
Refueling activities
involving both
fuel
movement
and
movement
were observed
in the containment
and at the refueling
control station.
The refueling activities
met staffing
and
procedural
requirements,
and were pr'oceeding
smoothly.
The in-shop overhaul of Limitorque type 000 valve operators for
AFW discharge
valves
was
observed.
New procedure
MP-0940075,
Rev 0, Maintenance
and Repair of Limitorque Valve Actuators
Type
SMB-000,
was
invoked for it's initial field use.
Workmanship
and procedure
adherence
were at
a high level.
No violations or deviations
were identified.
Followup (Units
1 and 2) (92701)
Followup of Inspection Identified Items
Based
on prior
NRC concerns
at other facilities with the use of adhesive
backed plastic
padeyes
or tiedowns to support safety-related
electrical or
electronic cabinet wiring in seismic or vibrational service,
the inspector
reviewed conditions at St. Lucie and identified several
instances
of such
items
being
used.
In
some
cases,
such
as the
EOG control cabinet
door
instrument wiring, the adhesive
backed
tiedowns
had unstuck
and the wire
bundles
were
being
supported
by
the
connections
at
switches
and
instruments.
The licensee
concluded (ref.
NCR 1-367,
dated
January
9,
1990) that the use of adhesive
back tiedowns
was for housekeeping
purposes
only and
was satisfactory.
The completed
NCR package
was
subsequently
evaluated
as satisfactory
by
NRC Region II engineering
management.
This
issue is closed.
Allegation Followup
(Closed) Allegation (RII-90-A-0022) Anonymous Allegation regarding
Lack of
Root
Cause
Analysis for
Leaking
Steam
Generator
Blowdown Valves.
On
February
21,
1990,
an allegation
was received
by
NRC Region II, through
the
NRC Resident Inspector,
concerning
the Unit 2 Steam Generator
Blowdown
Valves.
The alleger
indicated that the root cause
analysis
associated
with these
valves, specifically the upper
and lower flange connections
leaking conditions,
was not adequate
and that this condition
has
been
a
recurring
problem
since
1987.
In order to eliminate this leaking
condition, the licensee is evaluating
the current valve design
and leakage
problems
under
request for engineering
assistance
89-18.
The inspector
also determined that the licensee
has initiated Plant Change
036290.
This
plant modification will change
out the four Unit 2 B/G Blowdown valves
during the next r'efueling outage with a valve which has different design
characteristics.
The inspector determined that the licensee is taking the
necessary
actions
to correct
the
concerns
identified
by the alleger;
therefore, this case is considered
closed.
(Closed) Allegation (RII-90-A-0074) Anonymous Allegation Regarding Shift
Technical Advisors Working Excessive. Overtime.
The inspector
reviewed the
14
licensee's
implementation of TS section 6.2.2.
This section identifies
the
overtime
guidelines
for the Unit Staff performing safety
related
functions.
The Unit Staff is defined
by
TS Table 6.2-1.
The minimum
shift crew composition
as
defined
by the
TS for modes
1,
2
, 3, or
4
operations,
shall
consist of one shift supervisor,
one senior reactor
operator,
one reactor
operator,
one auxiliary operator,
and
one shift
technical
advisor.
TS section 6.2.2.f requires
the licensee
to develop
and
implement administrative
procedures
which limit the working hours of
the Unit Staff.
In addition, this
TS section
requires
that
adequate
coverage
be maintained without the routine
heavy
use of overtime.
The
following overtime guidance is provided by the TS:
a.
An individual
should
not
be permitted
to work more
than
16
straight hours, excluding shift turnover time.
b.
An indivisual should not be permitted to work more than
16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />
in any 24-hour period,
nor more than
24
hours
in
a 48-hour
period,
nor
more than
72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in a 7-day period, all excluding
shift turnover.
c.
A break of at least
8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />
should
be allowed
between
work
periods,
excluding shift turnover time.
d.
Except during
extended
shutdown
periods,
the
use of overtime
should
be considered
on
an individual basis
and not for the
entire staff on. shift.
Any deviation
from these
guidelines
are to
be authorized
by the Plant
Manager in accordance
with established
procedures.
The inspector
performed
a review of Administrative Procedure
No. 0010119,
Rev.
8, Overtime Limitations for Plant
Personnel
and verified that the
licensee's
procedure
followed the guidance
imposed
by the TS.
In order to
determine
TS compliance during the period of January
1 to May 5, 1989, the
inspector
reviewed
a sample of the work schedules,
overtime records,
and
security
access
logs for 6 Nuclear
Watch Engineers,
34 Reactor
Control
Operators,
18
Nuclear
Operators,
22
Nuclear
Turbine
Operators,
21
Associate
Nuclear Plant Operators,
3 Senior Nuclear Plant Operators,
and
3
The inspector did not identify any cases within
the operations
department
where the overtime exceeded
the limits imposed
by the
TS and the licensee's
procedure.
However, the inspector did have
a
concern
associated
with the work schedule
governing the Shift Technical
Advisors.
The work schedule
requires
the Shift Technical
Advisors to work
7 consecutive
12-hour night shifts.
This schedule,
not including over-
time, routinely exceeds
the
72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />
worked in a 7-day period criteria
established
by the TS.
The inspector
found that
on
a monthly basis,
an
overtime request
which accounts for the STA's work schedule,
in accordance
with Administrative'rocedure
No. 0010119, is submitted
to Plant Manage-
ment for approval.
With regard to the overall
hours
worked by the STAs,
the inspector
did not identify any cases
where excessive
over time was
worked during the time period inspected.
On the basis that the licensee
15
is complying with their overtime procedure
and that the plant records did
not indicate that the
STAs were working excessive
overtime, the inspector
did not identify any violations or deviations
in this area;
therefore,
this case is considered
closed.
Exit Interview (30703)
The inspection
scope
and findings were
summarized
on February
23,
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
389/90-02-01
open
VIO - Failure to properly implement the
Unit 2 startup procedure,
paragraph
2.b.
389/90-02-02
389/90-02-03
389/90-02-04
open
open
open
H
VIO - Failure to implement preventive
maintenance
on
2C
AFW pump governor,
paragraph
2.b.
VIO - Failure to seismically remount
an
ADV, paragraph
4.
NCV - Inadequate
Procedure for CS system
check valve surveillance,
paragraph
3.
Abbreviations,
and Initialisms
ADV
A/E
ANPO
AN< S
ANSI
ASME Code
BQAP
ASEA Brown Boveri
(company)
Auxiliary Building
Alternating Current
Atmospheric
Dump Valve
Architect/Engineer
Auxiliary Feedwater Actuation System
(system)
As Low as Reasonably
Achievable (radiation exposure)
Auxiliary Nuclear Plant [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
Backfit Quality Assurance
Procedure
(EBASCO Services
Inc.)
Corrective Action Request
Component
Cooling Water
Combustion Engineering
(company)
16
CFR
CIS
DDPS
DEV
F
FI
FIS
FRG
FT
GDC
GL
GMP
gpm
HFA
HVE
IKC
ICW
IFI
IN
IR
IX
JPE
JPN
KW
LIV
LCO
LER
etc.)
ng license)
ix A)
etc.)
em)
Control Element Assembly
Control Element Drive Mechanism Control
System
Code of Federal
Regulations
Containment Isolation System
Containment
Spray (system)
Condensate
Storage
Tank
Chemical
& Volume Control System
Direct Current
Digital Data Processing
System
Deviation (from Codes,
Standards,
Commitments,
Demonstration
Power Reactor
(A type of operati
Emergency
Core Cooling System
Emergency
Diesel Generator
Electric Power Research
Institute
Engineered
Safety Feature
Fahrenheit
Flow Control Valve
Flow Indicator
Flow Indicator/Switch
The Florida Power
5 Light Company
Facility Review Group
Final Safety Analysis Report
Flow Transmitter
General
Design Criteria (from 10CFR 50, Append
General Electric Company
[NRC] Generic Letter
General
Maintenance
Procedure
Gallon(s)
Per Minute {flow rate)
Hydraulic Control Valve
A GE relay designation
Health Physics
High Pressure
Safety Injection (system)
Heating
and Ventilating Exhaust (fan, system,
Heat Exchanger
Instrumentation
and Control
Intake Cooling Water
[NRC3 Inspector
Followup Item
Integrated
Leak Rate Testing
[NRC] Information Notice
Institute for Nuclear Power Operations
[NRC] Inspection Report
InService Inspection
{program)
Ion Exchanger
Juno
Beach)
Power Plant Engineering
Juno
Beach
Nuclear Engineering
KiloWatt(s)
Licensee Identified Violation
Low Temperature
Overpressure
Protection (syst
TS Limiting .Condition for Operation
Licensee
Event Report
Low Pressure
Safety Injection (system)
17
MFIY
min
mrem
MV
NPF
NPWO
NRC
ONOP
OP
PAID
PIS
pslg
ppm
PWO
QI
RCB
RCO
RDT
Rev
Measuring
5 Test Equipment
Motor Control Center
Main Feed Isolation Valve
Main. Feed
Pump
minute
mi llirem
Moisture Separator/Reheater
Motorized Valve
Megawatt{s)
Non Conformance
Report
NonCited Violation (of NRC requirements)
Non Destructive Examination
Nuclear Production Facility (a type of license)
Nuclear Plant Operator
Nucl,ear Plant Supervisor
Nuclear Plant Work Order
Nuclear Regulatory
Commission
Nuclear Steam Supply System
Operating Instruction
Off Normal Operating
Procedure
Operating
Procedure
Plant Change/Modification
Pressure
Control Valve
Piping 5 Instrumentation
Diagram
Pressure
Indicator/Switch
Preventive
Maintenance
Power Operated
Rel'ief Valve
Pounds
per square
inch (gage)
Part(s)
per Million
Pressure
Transmitter
Plant Work Order
Pressurized
Water Reactor
Quality Assurance
Quality Control
Quality Instruction
Qualified Safety Parameter
Display System
Reactor Auxiliary Building
Reactor Containment Building
Reactor
Control Operator
Reactor
Coolant
Pump
Reactor Coolant Pressure
Boundary
Reactor Drain Tank
Revision
(NRC] Regulatory Guide
Reactor
[licensed] Operator
Reactor Protection
System
Refueling Wafer Tank
Service Advice Letter
Systematic
Assessment
of Licensee
Performance
18
SDCS
SNPO
Tavg
TCB
TCW
TEDB
TI
TS
V
Safety Assessment
System
Shut
Down Cooling
Shut
Down Cooling System
Safety Injection (system)
Safety Injection Tank
Senior Nuclear Plant Lunlicensed] Operator
Senior
Reactor [licensed] Operator
Reactor
average
temperature
Temporary
Change
Trip Circuit Breaker
Turbine Cooling Mater
Temperature
Element
Total Equipment Data
Base
LNRC] Temporary Instruction
Three Mile Island
Temperature
Recorder
Technical Specification(s)
LNRC
Unresolved
Item
Volt s)
Volume Control Tank
Violation (of NRC requirements)