ML17228A379
| ML17228A379 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 11/22/1993 |
| From: | Elrod S, Landis K, Mark Miller, Trocine L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17228A377 | List: |
| References | |
| 50-335-93-22, 50-389-93-22, NUDOCS 9312140054 | |
| Download: ML17228A379 (38) | |
See also: IR 05000335/1993022
Text
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UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W., SUITE 2900
ATLANTA,GEORGIA 303234199
Report Nos.:
50-335/93-22
and 50-389/93-22
Licensee:
Power
5 Light Co
9250 West Flagler Street
Miami,
FL
33102
Docket Nos.:
50-335
and 50-389
License Nos.:
and
Facility Name:
St.
Lucie
1 and
2
Inspection
Conducted:
September
26 - October 23,
1993
Inspectors:
O, R.t ov e
iS. A. Elrod, Senior Resident
Inspector
Q.R. L->
"M. S. Hiller, Resident
Inspector
Q.Q
.L. Trocine,
Residen
Inspector,
Turkey Point
e
Approved by:
K. D.
Lan
s, Chief
Reactor Projects
Section
2B
Division of Reactor Projects
SUMMARY
II z> qg
Date Signed
II zz, R3
'Date Si
ned
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Date Signed
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S'gned
Scope:
This routine resident
inspection
was conducted
onsite in the areas
of plant operations
review, surveillance observations,
maintenance
observations, fire protection review, review of nonroutine events,
onsite followup of written nonroutine event reports,
and followup of
regional
requests.
Backshift inspection
was performed
on October
ll, 15,
16,
17,
19 and 20,
1993.
Results:
Plant
0 erations:
Operations
reacted well to power reductions
required to support
maintenance
on Unit
1 and to the intrusion of jellyfish into
the plant intake canal for both units.
Changes
in power level
and plant conditions were conducted appropriately.
Operators
in both units were alert to several
conditions of increasing
system leakage
and effectively located
and
isolated
leakage
paths.
Control
room operator attentiveness
was
a strength.
(paragraph
3)
9312140054
931122
ADQCK 05000335
6
Maintenance:
The predictive maintenance
program effectively detected
a
degrading
main feed
pump thrust bearing,
allowing timely
repair.
Work performed to correct excessive
corrosion
on the
was thorough
and
appropriate.
However,
a failure to follow a procedure
prepared
for jumpering the accumulator
and
a failure to perform
a safety
evaluation for the installation of the jumper were identified
as violations.
(paragraph
5)
Surveillance tests
observed
were effectively performed.
(paragraph
4)
En ineerin
Engineering analysis of vibration data
was important in
defining main feed
pump degradation.
(paragraph
5.a)
Within the areas
inspected,
the following violations were
identified:
VIO 335,389/93-22-01,
Failure to Follow Procedure for UHS
Valves Air Supply Maintenance,
paragraph
5.b.
VIO 335,389/93-22-02,
Failure to Perform
and Document
a
10 CFR 50.59 Safety Evaluation for Temporary Modifications to
Valves Air Supply,
paragraph
5.b.
REPORT DETAILS
Persons
Contacted
Licensee
Employees
D. Sager,
St.
Lucie Plant Vice President
- C. Burton, St. Lucie Plant General
Manager
K. Heffelfinger, Protection Services
Supervisor
H. Buchanan,
Health Physics Supervisor
- J. Scarola,
Operations
Manager
- R. Church,
Independent
Safety Engineering
Group Chairman
R.
Dawson,
Maintenance
Manager
- W. Dean, Electrical
Maintenance
Department
Head
- J.
Dyer, Plant quality Control Manager
W. Bladow, Site guality Manager
H. Fagley,
Construction
Services
Manager
R. Frechette,
Chemistry Supervisor
J. Holt, Plant Licensing Engineer
- J.
Hosmer, Site Engineering
Manager
- L. McLaughlin, Licensing Manager
G. Madden,
Plant Licensing Engineer
A. Menocal,
Mechanical
Maintenance
Department
Head
- C. Pell, Site Services
Manager
L. Rogers,
Instrument
and Control Maintenance
Department
Head
C. Scott,
Outage
Manager
J. Spodick,
Operations
Training Supervisor
D. West, Technical
Manager
- J.
West, Operations
Supervisor
W. White, Security Supervisor
- D. Wolf, Site Engineering Supervisor
E.
Wunder lich, Reactor
Engineering Supervisor
Other licensee
employees
contacted
included engineers,
technicians,
operators,
mechanics,
security force members,
and office personnel.
NRC Personnel
M. Sinkule, Chief, Reactor Projects
Branch 2, Division of Reactor
Projects,
NRC Region II.
K. Landis, Chief, Reactor Projects
Section
2B, Division of Reactor
Projects,
NRC Region II.
- S. Elrod, Senior Resident
Inspector
- M. Miller, Resident
Inspector
L. Trocine,
Resident
Inspector,
Turkey Point Site
- Attended exit interview
and initialisms used throughout this report are listed in the
last paragraph.
Plant Status
and Activities
Unit
1 began
the inspection
period at power but the generator
was taken
off line on September
26 because
of a large scale intrusion of jellyfish
into the intake canal.
The unit was returned to 30 percent
power on
September
27 but was again taken off line for
a jellyfish intrusion that
afternoon,
returning to service that evening.
Unit
1 operated
at power
the remainder of the inspection period - ending the period in day
21 of
power operation
since the September
28 turbine startup.
Unit 2 began the inspection period at power.
Several
power reductions
occurred during the period.
On September
26,
power was reduced first
because
of the large scale intrusion of jellyfish into the intake canal,
then because
high chloride ion concentration
was reported
in 2A SG.
A
salt water leak in the
2A2 waterbox was suspected.
The chloride ion
concentration
decreased
after nine hours
and power was restored to the
50-60 percent
range while the
2A2 and
2B1 waterboxes
were cleaned.
No
leaking tubes
were found.
On September
29, Unit 2 power was reduced
because
the screen
wash system
header ruptured.
This was quickly
restored to service.
Unit 2 ended the period in day 66 of power
operation since startup
on August 13,
1992.
Hr. H. V. Sinkule, Chief, Reactor Projects
Branch 2, Division of Reactor
Projects,
NRC Region II, was
on site
on October
14.
His activities
included
a site tour, discussions
with licensee
management,
and
an
overview of resident office activities
and issues.
The St. Lucie resident
inspectors,
Turkey Point resident
inspectors,
and
Hr. K. D. Landis, Chief, Reactor Projects
Section
2B, Division of Reactor
Projects,
NRC Region II, met with members of the licensee's
nuclear
engineering
organization
in Juno
Beach
on October 20.
The licensee
presented
discussions
on
a range of topics involving both
FPL nuclear
facilities.
Hr. K. D. Landis was
on site
on October 21.
His activities included
a
site tour, discussions
with licensee
management,
and
an overview of
resident office activities
and issues.
Review of Plant Operations
(71707)
a ~
Plant Tours
The inspectors periodically 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 ESF,
ECCS,
and support
systems.
Valve, breaker,
and switch lineups
as well as
equipment conditions
were randomly verified both locally and in the
control
room.
The following accessible-area
ESF system
and area
walkdowns were
made to verify that system lineups were in accordance
with licensee
requirements for operability and equipment material
conditions were satisfactory:
Intake Structures/
Screen
Wash Systems,
2C
AFW System,
and
Unit 2 CST and piping
b.
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.
They observed
and evaluated
control
room staffing, control
room access,
and
operator
performance
during routine operations.
The inspectors
conducted
random off-hours inspections to ensure that operations
and
security performance
remained at acceptable
levels.
Shift turnovers
were observed
to verify that they were conducted
in accordance
with
approved
licensee
procedures.
Control
room annunciator status
was
verified.
Except
as noted below,
no deficiencies
were observed.
During this inspection period,
the inspectors
reviewed tagout
(clearance)
2-9310-045
- HVS-6 Fuel Handling Building Fan.
(1)
Unit
1
Load Reduction
Due to Linear Heat Rate
Issue
-
Se tember
26
1993
After returning Unit
1 to service following a reactor
shutdown
to facilitate replacement
of the No.
2 governor valve anti-
rotation pin,
a load reduction from 100% reactor
power was
commenced
at 1:00 a.m.. on September
26 because
four incore
detectors
were found in alarm.
This load reduction
was
performed per procedure
OP 3200052,
Monitoring Linear Heat
Rate,
and
Step 8.2.3 of OP 3200052 required that with four or more
detectors
in alarm, the licensee notify Reactor Engineering
and
ISC within 15 minutes
and reduce the linear heat rate to within
limits (less
than four detectors
in alarm) within one hour per
0
(2)
TS 3.2. 1.
TS 3.2. 1 required that with the linear heat rate
exceeding its limits as indicated
by four or more coincident
incore channels
or by the axial
shape
index outside of the
power dependent
control limits, the licensee initiate
corrective actions within 15 minutes to either restore
the
linear heat rate to within its limits within one hour or be in
Hot Standby within the next six hours.
When reactor
power reached
92% at 1:20 a.m.,
one of the four
alarms cleared,
and the operators
exited the action statement.
With reactor
power maintained at 92%,
2 more alarms cleared at
1:23 a.m.,
and the last alarm cleared at 1:26 a.m.
At 4:30
a.m., reactor engineering
took a snap shot of the core
and
provided
new setpoints.
Following the insertion of the
new
setpoints,
power ascension
was
commenced
at 4:31 a.m.,
and
100%
reactor
power was re-achieved
at 5:08 a.m.
The previously existing setpoints
had
been set during
a monthly
surveillance
performed while at
30% reactor
power during the
jellyfish influx.
In contrast,
during startup
from refueling,
the licensee routinely rechecked
the alarms
several
times
as
power level increased
as part of a broader test program.
The
licensee
concluded that these setpoints
are
somewhat affected
by the power level at which they are set.
When set at low
power, the alarms
are more conservative
than intended.
Unit
1 Load Shutdown
Due to Jell fish Intrusion - Se tember
26
1993
(3)
At 7:35 a.m.
on September
26,
a Unit
1 load reduction from 100%
reactor
power was
commenced
due to the intrusion of large
quantities of jellyfish into the intake canal.
Reactor
power
was stabilized at
64% at 8: 18 a.m., all circulating water
pump
~ di scharge
valves were throttled to
75% open at 8:50 a.m.,
and
a
load reduction
was
re-commenced
at 8:53 a.m.
Unit
1 was taken
off line at 9:49 a.m.,
and
Mode
2 was entered
at 9:50 a.m., At
9:00 a.m.
on September
27, Unit
1 re-entered
Mode
1 and
was
placed
back on line at 10:03 a.m.
Reactor
power was stabilized
at approximately
30% at 10:55 a.m.
Unit
1 Shutdown
Due to Jell fish Intrusion -
Se tember
27
1993
At 3: 10 p.m.
on September
27,
a Unit
1 load reduction
from
approximately
30% reactor
power was
commenced
due to the
intrusion of large quantities of jellyfish into the intake
canal.
At 3:20 p.m., Unit
1 was taken off line,
and
Mode
2 was
entered.
Unit
1 re-entered
Mode
1 at 8:20 p.m.
and was placed
back
on line at 9:40 p.m.
Reactor
power was stabilized at
approximately
32% at ll:25 p.m.
Power ascension
was
commenced
at ll:45 a.m.
on September
28,
1993,
and reactor
power was
stabilized at
40% at ll:58 a.m.
Power ascension
was re-
commenced
at 12: 19 p.m.,
and reactor
power was stabilized at
approximately
75% at 1:55 p.m.
At 10: 10 a.m.
on September
29,
1993, the licensee
commenced
another
power ascension,
and
90%
reactor
power was achieved
at ll:10 a.m:
Power ascension
was
re-commenced
at 1: 10 p.m.,
and reactor
power was stabilized at
approximately
96% for axial
shape
index considerations
at 2: 15
p.m.
The last power ascension
was
commenced
at 2:20 a.m.
on
September
30,
and rated
power was achieved at 3:00 a.m.
Unit
1
72-Hour
LCO -
Se tember
28
1993
At 5:15 a.m.
on September
28, the
was
removed
from service
due to a limit switch problem on the
1B HPSI
injection valve to the
1A2 loop (HCV-3616).
The control
room
position indication
showed that the valve was
open
when it was
actually closed.
The licensee's
investigation revealed that
the limit switch cartridge pinion gear shaft
had failed
resulting in a failure of the limit switch assembly.
This in
turn resulted
in the actuator potentially developing stall
thrust in the closing direction.
The initial engineering
assessment
of this issue
concluded that there would be no
concern for the condition of the actuator
based
on the rebuild
of the actuator in place
and the successful
post-maintenance
stroke testing.
The valve was successfully tested,
and the
1B
was returned to service at 2:56 p.m.
on September
29.
Unit
1 Main Feed
Pum
Vibration - Se tember
30
1993
At 2:35 p.m.
on September
30, Unit
1 power was reduced
from
100% to 45% to investigate vibration readings
taken
on the
1B
MFP under the predictive maintenance
program.
When power
reached
45% at 4:25 p.m., the
pump was stopped for repair.
The
licensee
found
a problem in the thrust bearing caused'by
loose
internal
mounting pins.
Tightness of these
pins was not
discussed
in the vendor manual.
The predictive maintenance
program certainly prevented
a major failure in this case.
Following repair,
the
pump was started
at 12:25 a.m.
on October
2 with subsequent
uppower occurring from 1:07 to 5:35 a.m.
The
unit finished the inspection period at power.
Unit 2 Load Reduction
Due to Jell fish Intrusion -
Se tember
26
1993
At 9:06 a.m.
on September
26,
a Unit 2 load reduction
from 92%
reactor
power was
commenced
due to the intrusion of large
quantities of jellyfish in the intake canal.
Reactor
power was
stabilized at
55% at 9:40 a.m.,
another
load reduction
was
commenced
at 10:05 a.m.,
and reactor
power was stabilized at
31% at 11: 10 a.m.
Power
ascension
was
commenced
at 12:15 p.m.,
and reactor
power was stabilized at
49% for axial
shape
index
limitations at 2:10 p.m.
6
Unit 2 Load Reduction
Due to Jell fish Intrusion
and
a
Potential
Condenser
Tube
Leak -
Se tember
26
1993
Due to increasing chloride
and sodium levels in the Unit 2
the licensee initiated investigation,
and
entered
Action Level
1 of procedure
ONOP 2-0610030,
Secondary
Chemistry - Off Normal, at 2:00 p.m.
on September
26.
Action
Level
1 of this procedure
required that,
when steam generator
become greater
than
20 ppb,
normal values
be established
within one week or proceed to Action Level 2.
At 8:50 p.m., chloride levels in the
were
reported to be
103 ppb,
and the licensee
entered Action Level
2
of procedure
ONOP 2-0610030.
Action Level
2 of this procedure
required that,
when steam generator chlorides
become greater
than
100 ppb, reactor
power be reduced to less
than or equal to
30% within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />
and that normal values
be established
within
100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br />.
As
a result of a suspected
condenser
tube leak in
the
2A2 waterbox,
the
2A2 circulation water
pump was stopped
at
9: 18 p.m.,
and
a Unit 2 load reduction
from approximately
50%
reactor
power was
commenced
at 9:28 p.m.
During this load
reduction,
the 2AI, 2B1,
and
2B2 circulating water
pump
discharge
valves were throttled to
75% open
due to the
intrusion of large quantities of jellyfish into the intake
canal.
Reactor
power was stabilized at
29% at 9:46 p.m.
Action Level
2 of procedure
ONOP 2-0610030
was exited at 10:50
p.m.
when the secondary
chemistry chloride level
was reported
to be 87 ppb
and decreasing,
and Action Level
1 of this
procedure
was exited at 6: 10 a.m.
on September
27,
when
chloride levels were reported to be
12 ppb and
15 ppb in the
2A
and
2B steam generators,
respectively.
At 6: 15 a.m.
on September
27,
power ascension
was
commenced,
.
and reactor
power was stabilized at
41% at 7:30 a.m. to
facilitate the performance of a calorimetric.
Power ascension
was re-commenced
at 7:50 a.m., reactor
power was stabilized at
45% at 8:21 a.m.,
power ascension
was re-commenced
at 8:49
a.m.,
and reactor
power was stabilized at
55% at 10:00 a.m.
due
to axial
shape
index limitations.
Power ascension
was re-
commenced
at 10: 15 a.m.,
and reactor
power was stabilized at
59% at 10:42 a.m.
due to main condenser
backpressure
limitations.
In order to maintain backpressure
within its
limitations,
a load reduction
was
commenced
at 12:00 p.m.,
and
reactor
power was stabilized at
53% at 12:50 p.m.
Waterbox cleaning
and further investigation revealed potential
condenser
tube leakage
in the
2A2 waterbox.
As a result,
the
licensee utilized helium gas to localize the potential
tube
leak.
No tube leaks
were identified.
The 2A2 waterbox
was
returned to service,
and the
2A2 circulating
pump was restarted
at 5:32 p.m.
on September
29.
In order to detect
increases
in
chloride levels,
the licensee
also lowered the alarm setpoints.
No alarms
were received.
(8)
Subsequent
licensee
analysis identified that the air ejector
piping had
a bolted flange connection
inside each water box.
Bolts have
been
found somewhat
loosened
or missing in the past.
Considering that the pipe would heat
up significantly while the
waterbox was empty and could then
squeeze
the gasket tight,
a
leak at this joint might not be found while the waterbox
was
open for cleaning.
On September
29, while Unit 2 was at reduced
load, the licensee
also performed turbine valve testing
and
removed the
2B1
waterbox from service for cleaning.
The 2Bl circulating water
pump was stopped
at 9:07 p.m.
and
a load increase
commenced
at
9:20 p.m.
Reactor
power was stabilized at
57% at 10:20 p.m.
Unit 2 Load Reduction
Due to
Ru ture in Screen
Wash
S stem
-
Se tember
29
1993
A load reduction from 57% reactor
power was
commenced
at ll:15
p.m.
on September
29,
due to a rupture in the screen
wash
system
header coincident with a high differential pressure
across
the screen
assembly for the
2B2 well.
The header
ruptured from external
corrosion at
a threaded joint.
Reactor
power was stabilized at
22% at ll:57 p.m.
Power'ascension
was
commenced
at 8:20 a.m.
on September
30,
was stabilized at 8:35
a.m. to facilitate
a feedwater regulating valve transfer,
then
re-commenced
at 9:25 a.m.
Reactor
power was held at
34% at
10:05 a.m. for continued
intake work.
Following these
activities,
power ascension
was
re-commenced
at 10: 10 a.m.
on
October
1, with stops for ASI control,
and
100% reactor
power
was re-achieved
at 7:30 a.m.
on October 3.
(9)
(10)
Unit 2 Waterbox Cleanin
'
October
17 and
18
1993
Unit 2 downpowered to 63% power
on October
17 to clean
waterboxes
and returned to full power on October
18.
Unit 2
finished the inspection period at power.
RCS Unidentified Leak Rate
Increases
Operators
responded
to
a number of increases
in unidentified
RCS leak rate.
On October
18, the Unit
1 leak rate reached
1.09 gpm.
Operators
entered
the action statement
of TS
which requires that, if unidentified leakage
exceeds
a
1
gpm limit, then reduce the leakage rate to within limits
within four hours or be in hot standby within the next six
hours.
In investigating the cause of the increased
leakage,
operators
found that misaligned
sample valves
had
been
diverting coolant from the
VCT to the
HUT.
The sample valves
were realigned
and leakage fell back within TS limits within
the four-hour
LCO action statement
time.
0
8
On October
19, Unit
1 operators
noted that
RCS leakage
had
increased
from approximately 0.5
to 0.845
gpm.
A tour of
accessible
containment
spaces,
conducted
the
same day,
indicated
a packing leak on the pressurizer
steam
space
sample
heat
exchanger
isolation valve.
A second
containment entry was
made to backseat
the valve and adjust the packing.
Following
this evolution,
RCS leak rate dropped to 0.35
gpm.
On October
20, Unit 2 experienced
a 1.83
gpm
RCS leak rate.
Operators
entered
the action statement of TS
and
began investigations
as to the cause of the increased
leak
rate.
In the course of the investigation,
a containment entry
identified
a packing leak at one of the two pressurizer
spray
bypass
valves.
The valve was isolated.
Additional leak rate
contributors
were identified in a sampling
system line, the.
operation of the
2A charging
pump,
and the
2A charging
pump
thermal relief valve.
Following these
leak isolation
activities, the Unit 2
RCS leak rate
was reduced to
approximately 0.5
gpm within the four-hour
LCO action statement
time.
c.
Technical Specification
Compliance
Licensee
compliance with selected
TS
LCOs was verified. This
included the review of selected
surveillance test results.
These
verifications were accomplished
by direct observation of monitoring
instrumentation,
valve positions,
and switch positions,
and by
review of completed
logs
and records.
Instrumentation
and recorder
traces
were observed for abnormalities.
The licensee's
compliance
with LCO action statements
was reviewed
on selected
occurrences
as
they happened.
The inspectors verified that related plant
procedures
in use were adequate,
complete,
and included the most
recent revisions.
d.
Physical
Protection
The inspectors verified by observation
during routine activities
that security program plans
were being implemented
as evidenced
by:
proper display of picture badges;
searching of packages
and
personnel
at the plant entrance;
and vital area portals
being locked
and alarmed.
e.
Radiological
Protection
Program
Radiation protection control activities were observed
to verify that
-these activities were in conformance with the facility policies
and
procedures,
and in compliance with regulatory requirements.
These
observations
included:
Entry to and exit from contaminated
areas,
including step-off
pad conditions
and disposal
of contaminated
clothing;
Area postings
and controls;
e
Work activity within radiation,
high radiation,
and
contaminated
areas;
Radiation Control Area
(RCA) exiting practices;
and,
Proper wearing of personnel
monitoring equipment,
Proper wearing of personnel
monitoring equipment,
protective,
"
clothing,
and respiratory equipment.
The inspectors
read
an informal publication at the plant titled:
"St. Lucie Power Lines,
Volume 3,
Number 3, September,
1993."
It
described
the August
31 special visit of the Prime Hinister of
Russia
and
an entourage of Russian
and U.S. Dignitaries to the site
in a less
than serious
manner,
and included
a statement
about plant
rules:
"Although the tour did not
seem particularly organized
and
uncounted security
and health physics rules were
abused
inadvertently..."
The inspectors
were
aware that certain site
security procedures
were replaced
by alternate
methods for the
August 31 special visit, with related
as
discussed
in IR 335,389/93-20.
Inspectors
were not aware of any
relaxation of health physics (radiation protection) regulations.
The inspectors
discussed
the matter of health physics rules with the
Health Physics Supervisor,
who stated that site
and
NRC health
physics rules were followed during the August 31 special visit.
To
accomplish this, the licensee
had
made
one temporary
change to
health physics procedure
HP-30,
Personnel
Monitoring.
This
temporary
change
provided for the visitors to enter the
RCA without
each wearing individual dosimetry for monitoring radiation exposure.
The inspector reviewed the temporary
change,
which stated:
"At the
discretion of the
HP Supervisor,
those individuals who are visitors
and will not exceed
25% of the quarterly limit (312 mc)
may enter
the
RCA without personnel
monitoring devices
when accompanied
by an
individual wearing appropriate dosimetry."
The inspector verified
that the temporary
change
was in accordance
with NRC regulations.
The inspector also considered
that the
RCA tour path
and duration
(as described
by several
persons)
and other health physics
aspects
of this special visit were also in accordance
with site health
physics
procedures
and
NRC regulations.
In summary,
the inspectors
found that operations
were conducted
in a safe
and professional
manner.
Operators,
confronted with repeated
needs to
maneuver the units'ower levels
and modes,
performed these functions
well.
Control
room operator attentiveness
to plant conditions
and trends
was
a noteworthy strength in identifying and isolating
RCS leakage
on
both units.
Radiological controls
and general
housekeeping
continued to
be good.
10
Various plant operations
were verified to comply with selected
TS
requirements.
Typical of these
were confirmation of TS compliance for
reactor coolant chemistry,
RWT conditions,
containment
pressure,
control
room ventilation,
and
AC and
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 tests
were observed:
1B
ICW Pump Performance
Test per
OP 1-0010125A,
Revision 32,
Data
Sheet
18.
2C
AFW Pump Performance
Test per
OP 2-0700050,
Revision 31.
These tests
were effectively performed.
5.
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
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 ensure that priority was assigned
to safety-
related
equipment.
Portions of the following maintenance
activities were
observed:
NPWO 8413/61
Excessive Axial Movement -
Feed
Pump
The
1B feed
pump thrust bearing
was opened for inspection
and
correction
because
the vibration monitoring program
had detected
a
change
in vibration amplitude
and phase.
Additionally, on September
30, the shaft
was observed
by maintenance
engineers
to be moving
axially about
1/16 inch vice the 0.012-0.016
inch design.
Upon
disassembly,
the end play was 0.045 inch.
No obvious problems
were
found but the end play was only 0.003 inch upon reassembly.
With
this clue, maintenance
found
a rocker plate pin cocked in its
mounting hole,
changing the axial play.
This condition was not
discussed
in the vendor manual.
Once the end play was set properly,
the
pump performed well.
The maintenance
group plans to include
this information in their procedure.
The inspector
observed
portions of the field work, cleanness
controls,
and material
condition of the thrust bearing.
Workmanship
and material controls
were very good.
This event highlights the effectiveness
of the
predictive maintenance
program.
NPWO 2038,
UHS Air Accumulator Repair
The licensee
began work to replace the saddle
supports to the
air accumulator
due to excessive
corrosion.
The accumulator
provides
a reserve
volume of air for the operation of the
valves,
which isolate
Big Hud Creek from the plant intake canal.
The
UHS valves
are normally shut.
The Instrument Air System provides air, through
a check valve, to
the subject
From the accumulator,
air is supplied to a
which branches
to each of the two
UHS valve actuators.
Each
branch line is isolable from the header
by a manually operated
valve
and,
downstream of this valve, contains
a four-way solenoid valve
which serves to isolate the branch
from the header
and vent the
valve actuator
upon
an open signal.
When the actuator is vented,
spring force serves
to open the
UHS valve.
The
UHS valves
have
operability requirements
detailed in technical specifications for
Units I and 2.
To allow for the removal of the air accumulator without opening the
UHS valves, Letter of Instruction LOI-T-78, revision 0, "Ultimate
Heat Sink Accumulator Tank Repairs,"
was prepared,
which directed
the installation of a temporary mechanical
jumper around the air
The jumper was installed
by, first installing
a
regulated
nitrogen supply to a temporary connection
in each
branch
line between
the branch solenoid valve and the
UHS valve actuator
(V-37226 or V-37227).
Each branch line was then isolated
from the
whereupon
the accumulator
was isolated
from the Instrument
Air System
and bled
down to atmospheric
pressure.
When the
was moved,
the jumper was installed,
the Instrument Air
System supply to the
UHS valve actuators
was restored
and the
temporary nitrogen supplies at valves
V-37226 and 37227 were
isolated.
To provide
a reserve
volume of air to the actuators
(previously provided
by the accumulator),
another regulated
supply was to be installed via a temporary connection at the air
supply header
(V-37220).
In tracing the temporary nitrogen supplies installed under LOI-T-78,
the inspector noted that the temporary supply which had
been
installed at V-37226 was disconnected
and rerouted to the temporary
connection at the air supply header
(V-37220).
In reviewing LOI-T-
78, the inspector
found that the
LOI did not include steps for
rerouting 'the subject line and that the LOI, in its restoration
steps,
assumed that this line was still connected
at V-37226.
The inspector questioned
the system engineer responsible for the
as to the acceptability of the apparent
departure
from the LOI.
The
system engineer stated that,
upon performing the steps of the LOI,
12
the crew could not obtain
a third regulated nitrogen supply for
connection to V-37220.
The system engineer
explained that his
decision to reroute
one of the existing nitrogen supplies without
modifying the
LOI was
based
upon the following factors:
~
As the author of the LOI, he was
aware of the procedure's
intent
and felt that the action was'ot contrary to that
intent.
~
He planned to personally follow the job and would be available
to explain the routing upon commencing restoration activities.
~
The decision
was discussed
with the Unit
1 Assistant
Nuclear
Plant Supervisor,
who agreed that the action would have
no ill
effects,
as the nitrogen supply was isolated
from the
instrument air system at V-37226.
While discussing
the matter with the inspector,
the system engineer
acknowledged that the configuration of the temporary equipment
should agree with the LOI.
A third regulated nitrogen source
was
located
and installed.
The inspector
found that the actions
taken in the installation of
the temporary nitrogen sources
were technically sound,
as
was the
methodology described
in the LOI.
As
a loss of air pressure
to the
UHS valve actuators
would have resulted
in the valves
assuming their
fail-safe positions
(open), plant safety
was not compromised.
However,
in rerouting the subject nitrogen line without first
obtaining
a change to the LOI, the actual configuration of the
valves'ir supply was incorrectly documented
and the proper return-
to-normal following maintenance
depended
upon
a second deviation
from the LOI.
The inspector
spoke with the Technical
Manager
on the
issue of procedural
compliance.
The Technical
Manager
acknowledged
that
a change to the procedure
would be in order,
given the
circumstances,
and that the sys'em engineer
had
been counselled to
that affect.
Technical Specification 6.8.1 requires that written procedures
be
established,
implemented,
and maintained.
Procedure
gI 5-PR/PSL-1,
revision 53, "Preparation,
Revision,
Review/Approval of Procedures,"
section
5. 13.2 states, in part, that "all procedures
shall
be
strictly adhered to."
The inspector
found that the rerouting of
temporary nitrogen from V-37226 to V-37220 constituted
a cognitive
departure
from an approved
procedure
and is identified as violation
335,389/93-22-01.
The inspector
reviewed the Unit
1
UFSAR for discussions
of the
valves
and found that the valves
and their operation
was discussed
in section 9.2.7.2.1.
Additionally, the air supply to the
actuators,
including the accumulator,
was graphically depicted
on
Figure 9.2-6f.
In attempting to review the
10 CFR 50.59 Safety
Evaluation
(SE) resulting from the LOI, the inspector
was informed
'n
13
that no
SE was performed.
members of the licensee's
technical staff
stated that,
as the jumper and nitrogen supplies
were part of a
maintenance activity, no Safety Evaluation
was required.
The
inspector
was informed that guidance
on when to perform SEs
was
obtained
from NSAC 125,
"Guidelines for 10 CFR 50.59 Safety
Evaluations."
The inspector reviewed
NSAC 125 and found that section
4. 1. 1 states
that "maintenance activities are not required to be reviewed under
except for those activities that require deviation from a
SAR procedure,
put the plant in a condition where it functions
differently than described
in the
SAR, or might violate
a technical
specification."
The licensee
stated that, in considering
the
applicability of 10 CFR 50.59 to the modifications
made under LOI-T-
78; the functional
aspects
of the
UHS valves were considered
and
found to be unchanged
(air was supplied to maintain the valves shut
and vented to open).
Following initial discussions
with the
inspector,
the plant's technical staff stated that they had
consulted with members of FPL's corporate
Nuclear Engineering staff,
who concurred in the opinion that
an
SE was not required.
The
inspector noted that
NSAC 125 also states that "Temporary changes
to
the facility should
be evaluated
to determine if an unreviewed
safety question exists...Examples
of temporary modifications include
jumpers...used
on
a temporary basis."
When asked
why an
SE was not
performed
based
upon this guidance,
members of the technical staff
stated that the actions directed
under LOI-T-78 constitutes
maintenance,
not
a temporary
change.
The inspector
found that changes
to the facility as described
in
Section 9.2.7.2.1
and Figure 9.2-6f had
been affected in the
implementation of LOI-T-78.
These
changes
included:
~
The use of regulated nitrogen sources
at valves
V-37226 and V-
37227 to maintain the
UHS valves in a shut position while
actuator air supplies
were isolated
from the accumulator.
~
.
The installation of a mechanical
jumper around the
UHS air
~
The use of a regulated
nitrogen source at V-37220 to act
as
a
reserve
volume of air while the accumulator
was
removed
from
the system.
The inspector
concluded that
no unreviewed safety question existed
as
a result of the changes
detailed
above.
The
UHS valves could
have
been
opened
from the control
room (as designed)
at any time,
and the valves'ail-open
characteristics
were unchanged.
While an
approximate
valve stroke time of 30 seconds
is described
in the
and while the stroke time may have
been affected
by the
modification (due to the, increased
reserve
volume of air available),
this time does not factor into accident
analyses.
14
As
a result of discussions
with the licensee,
the inspector
concluded that the failure to perform the required
SE was the result
two causal
factors:
~
In determining that LOI-T-78 addressed
a maintenance
evolution
(and
was therefore not
a change to the facility), the licensee
failed to differentiate
between
the work to be performed
on the
UHS air accumulator
and the actions
taken to assure
continued
operability of the
UHS valves.
~
In considering
a change to the facility. as
a change in
component functionality alone,
the licensee failed to consider
the more basic question of whether or not the facility had
been
physically changed
from its description in the
. The inspector reviewed portions of the licensee's
administrative
program for conformance to the requirements
of 10 CFR 50.59.
The
following procedures
were reviewed:
gI 5-PR/PSL-I,
Rev.
53, "Preparation,
Revision,
Review/Approval
of Procedures"
gI 3-PR/PSL-I,
Rev.
29,
"Design Control"
AP 0010124,
Rev.
29, "Control
and
Use of Jumpers
and
Disconnected
AP 0005769,
Rev.
0,
"10 CFR 50.59 Safety Evaluation Guidelines"
The inspector
found that the procedures
correctly required reviews
for 10 CFR 50.59 applicability and adequately
assigned
preparation,
review, approval,
and reporting responsibilities.
AP 0005769
contained
guidance for determining
when
a change to the plant exists,
which was consistent with NSAC 125.
The inspector
found that this
guidance
was consistent with 10 CFR 50.59.
Given the adequacy of
the licensee's
administrative
program
and the reported consistency
of opinions
between site
and corporate
engineering organizations,
the inspector concluded that
an interpretive weakness
exists
on the
part of the licensee with respect to the identification of plant
changes.
This perceived
weakness
does not imply that the licensee
has
conducted unsatisfactory
SEs,
only that the potential exists
that
an inadequate
number of SEs are being performed.
10 CFR 50.59(b)(l) requires,
in part, that records of changes
to the
facility as described
in the safety analysis report
be maintained
and that such records
include
a written safety evaluation which
provides the basis for the determination that the change
does not
include
a unreviewed safety question.
The failure to perform and
document
an
SE for LOI-T-78 is identified as violation 335,389/93-
22-02.
The work performed
under
NPWO 2038 to repair the
saddle
supports
was reviewed
by the inspector.
At the
end of the
inspection period,
the accumulator
saddle
supports
had
been
ground
free of the accumulator
and the
embedded
plates
in the
15
foundation.
New saddle
supports
were fabricated
and corrosion
damage to the plates
and to the accumulator
were evaluated visually
and ultrasonically.
Weld repairs
were made to the
embedded
plates
and the
need for repairs to the accumulator
was being evaluated
by
corporate
engineering.
The inspector
found the licensee's
actions
in these
areas
to be thorough
and appropriate.
In summary,
maintenance activities continued to be performed in a
professional
manner.
The detection
and correction of changes
in the
performance of the IB HFP highlight the effectiveness
of the predictive
maintenance
program.
Violations were identified which involved
procedural
compliance
and the applicability of 10 CFR 50.59 to
a
procedure
prepared to support
UHS accumulator repair.
The inspectors
concluded that the issue of procedural
compliance did not represent
a
programmatic
shortcoming.
The inspectors
found that the failure to
prepare
an
SE for the noted procedure highlighted
an interpretive err or
on the part of the licensee of the requirements
of 10 CFR 50.59.
Fire Protection
Review (64704)
During the course of their normal tours,
the inspectors
routinely
examined facets of the Fire Protection
Program.
The inspectors
reviewed
tr ansient fire loads,
flammable materials
storage,
housekeeping,
control
hazardous
chemicals,
ignition source/fire risk reduction efforts,
and
While touring the Unit I auxiliary building, the inspector noted that
fire door
RA-4 (access
to the
B LPSI
pump room)
was
open
and unattended
without a posted fire barrier breach request.
Air and
vacuum hoses
were
run through the door in support of painting which was being conducted
in
the room.
The inspector notified the painting supervisor responsible for
the work of the noted condition.
After investigating the situation,
the
supervisor
informed the inspector that the paint crew working in the
B
LPSI room had mistook the breach
request
posted
adjacent to door RA-3 as
the permit which applied to their work.
Door RA-3 is located in close
proximity to door RA-4.
A new breach
request
was promptly prepared
and
posted.
In Summary,
the inspectors
found that appropriate fire protection
practices
were in place.
One case of a failure to properly obtain
a fire
barrier breach permit was identified and was promptly corrected
by the
licensee.
Onsite Followup of Written Nonroutine Event Reports
(Units I and 2)
(92700)
LERs were reviewed for potential generic
impact, to detect trends,
and to
determine
whether corrective actions
appeared
appropriate.
Events that
the licensee
reported
immediately were reviewed
as they occurred to
determine if the
TS were satisfied.
LERs were reviewed in accordance
with the current
16
(Closed
- Unit 2)
Inadvertent Actuation of Auxiliary
Components
While Performing Honthly Auxiliary Feedwater
Actuation System Test
Oue to Equipment Failure.
With Unit 2 operating at
100% reactor
power on Harch 4,
1991,
an
inadvertent
actuation of Channel
A AFW components
occurred during
the performance of the
AFAS monthly functional test per
procedure
2-0700051, Auxiliary Feedwater Actuation System Honthly
Functional
Test.
I&C was balancing
and adjusting the Channel
A
auctioneered
power supplies to the
AFW actuation relays at the time.
When the components
actuated, trip status
and lockout status lights
were lit, several
AFAS-related annunciations
occurred,
the
2A AFW
pump started,
the steam
admission
valve from the
2B
SG to the steam-
driven
2C
AFW pump opened
and the
2C pump started.
However, the
discharge
valves for both
pumps remained
closed,
so
AFW did not
enter either steam generator.
HFIV A also received
a close signal,
but it only moved slightly from its full open position in the 0.21
seconds
before the signal cleared.
Operators
instructed
I&C to stop
testing, identify any equipment out of normal configuration,
and
return the plant to its normal configuration.
Extensive troubleshooting
revealed that the initiating event
was the
momentary loss of power from the two auctioneered
power supplies
serving channel
A.
In this circuit, two power supplies
are
auctioneered
through diodes
such that the power supply with the
higher voltage supplies
the load.
As the voltage of the two power
supplies varies with respect to each other,
the higher voltage power
supply will assume
the load from the other one.
Power supply
PS-
302B was found to be faulty.
The procedural
methodology involved in
balancing
and adjusting
power supplies
PS-301A
and
PS-302B,
combined
with the
PS-302B failure, momentarily resulted
in the auctioneered
voltage output level being less than that specified for system
operation.
The root cause of the event
was determined to be the
failure of one power supply to pick up load from the other power
supply.
In addition, after reviewing the procedure
and technical
manuals,
the licensee
determined that the "monthly" power supply
adjustments
were not intended
by the vendor to be performed
on
a
monthly basis.
The licensee
also determined that the
AFAS was able
to perform its intended safety function at all times during this
event.
As a result of this event,
I&C personnel
replaced
the faulty power
supply on Harch 6,
1991.
The AFAS monthly functional test
was also
satisfactorily completed
on Harch 8,
1991.
Engineering evaluated
the need for replacement
of the
AFAS power supplies for both units
with an improved model,
and the power supplies
have since
been
modified on both units.
I&C personnel
changed
the surveillance
procedures
to match the testing frequency
recommended
by the
technical
manual
and required
by the TS.
As a result,
at-power
power supply testing
was suspended,
and
18-month surveillance
procedure
IHP-09.03,
AFAS Power Supply Calibration Instruction,
was
instituted.
As a generic response
to difficulties experienced
with
17
the
AFAS and other sensitive
systems,
the licensee
also formed
a
cross-functional
task team to review past events
and identify
improvement opportunities.
The inspector's verified that the licensee's
corrective actions
have
been completed.
This item is closed.
(Closed - Unit 2)
Engineered
Safety Features
Actuation Channel
Out of Service
Due to Personnel
Error.
This event
was mentioned in paragraph
2.c of IR 335,389/91-22
and
was discussed
in detail in paragraph
6.a of IR 335,389/91-27.
389/91-27-02,
Engineered
Safety Features
Actuation Channel Out-of-
Service
Due to Personnel
Error,
was previously issued
on February
25,
1992,
as
a result of this event.
This item was kept open
pending the completion of the licensee's
three following corrective
actions:
open item notice 91-26 (2) requesting
a Training
Department evaluation of the event
as
a training item,
open item
notice 91-26 (4) requesting
review of the equipment out-of-service
process,
and open item notice 91-26-(50) for human factors oriented
modification of the bypass
key.
This
LER was evaluated
by the Training Department to determine
the
appropriate training requirements
and methods
and is being tracked
by Training System Action Request
No. 9201025.
The licensee
strengthened
the procedural
process
governing the review of
equipment
placed out-of-service
by the installation of key
identifiers
on the
RAS and
CSAS keys for Unit 2 and by the placement
of emphasis
on the
and
ANPS for more thorough reviews of all
paperwork concerned
with the operation of the units.
This was
further promulgated
through
NPS/ANPS meetings,
correspondence
of
expectations,
and additional
event meetings.
In addition, the
licensee
modified the
RWT level
bypass
key with a
human factors
identification tag to highlight its unique
TS action statement.
The inspectors verified that the licensee's
corrective actions
have
been completed.
This item is closed.
(Closed
- Unit 2)
Reactor Trip From
100% Power on
(Loss of Load)
Caused
by a Design Error in the Turbine Trip Testing
On-Line Modification.
This event
was discussed
in detail in paragraphs
2 and 3.b. (12) of
IR 335,389/92-11.
The licensee
redesigned
the turbine trip test
modification, tested it on
a fossil plant turbine, installed it in
St Lucie Unit 1,
and uses it for the monthly turbine trip
surveillance test.
The inspector witnessed
the successful
performance of the subsequently-corrected
design
on September
11,
1993,
and discussed
the test in IR 335,389/93-20,
paragraph
4.b.
The inspectors verified that the licensee's
corrective actions
have
been completed.
This item is closed.
18
d.
(Closed
- Unit 1)
Three
Prevent
Equipment
Damage
by Jellyfish Influx.
These
events
were discussed
in paragraph
3.b. of IR 335/93-20.
The
LER accurately described
the events
and corrective actions.
This
LER is closed.
8.
Onsite Followup of Events
(Units
1
and 2)(93702)
Nonroutine plant events
were reviewed to determine
the need for further
or continued
NRC response,
to determine
whether corrective actions
appeared
appropriate,
and to determine that
TS were being met
and that
the public health
and safety received
primary consideration.
Potential
generic
impact
and trend detection
were also considered.
Events
involving large influxes of jellyfish are discussed
in paragraph
3.b.
9.
Followup of Regional
Requests
- Inspection of Leak Sealant
Practices
(Units
1 and 2)
(92701)
a.
Does the licensee
use temporary leak sealant?
If so, give the trade
name
and describe
the process.
Yes, the licensee
uses
temporary leak sealant.
The trade
name is "Leak Repair, Inc.",
a subsidiary of Team,
Inc.
The process
uses
an injectable material
which is injected into
the joint through
a hole drilled in the component,
or around
the joint through
a hole drilled in a manufactured barrier.
b.
Is it used
on safety-related
equipment?
Nonsafety-related
equipment?
Are there
any prohibitions
on its use?
Yes, it is used
on safety-related
equipment.
Yes, it is used
on nonsafety-related
equipment.
There are
no universal prohibitions
on its use other than
Code requirements.
C.
How is the use controlled administratively?
Are licensee
procedures
used?
Are contractor
procedures
used?
Is it treated
as
maintenance?
Modification?
Its use is primarily controlled administratively
by a site
administrative
procedure
ADM-08.01,
Rev 2, On-Line Leak Sealant
Procedure.
That procedure,
however,
invokes other procedures
such
as the Nuclear Plant
Work Order procedure,
Nonconformance
Report
(NCR) procedure,
and Chemical
Control procedures.
Licensee
procedures
are
used
as discussed
above.
19
d.
Manufacturer's
procedures
are
used for the application.
The
manual
has
been
reviewed
and approved for use
by engineering
and by the site Facility Review Group.
The process
is basically treated
as maintenance
vice
a
modification.
For safety-related
components
or systems,
a
is sent to engineering.
The engineering
response
provides the
analysis of operability and special
steps that might be
required.
Does the licensee
control the type
and
amount of injected material?
If so,
how?
The licensee
used the
NCR response
to control the type
and
amount of material
injected for safety-related
applications.
Nonsafety-related
applications
are watched
by mechanical
maintenance
supervisors.
e.
How is the procedure
reviewed for reactor
and personnel
safety
issues?
By the
PORC (or equivalent)?
Yes, the procedures
have
been
reviewed
by the site equivalent
to the
PORC termed the Facility Review Group
(FRG).
f.
What is the licensee's
policy on length of use?
For safety-related
applications,
the
NCR response
addresses
ultimate repair.
For nonsafety-related
applications,
no hard policy was found.
The licensee
states
that they prefer to replace
the component
at the next opportunity.
g.
It is noted that
a permanent repair work order is required
from
the onset
as well as the work order for the temporary repair.
This helps
keep the need for permanent repair visible.
4
Determine
how involved the
gA and engineering
organizations
are in
preparation,
witnessing,
and post
use audits.
Engineering
reviewed the contractor's
procedures
and responds
to the
NCRs, specifying the type repair allowed for safety-
related applications.
This site has
a number of engineers
attached to the mechanical
maintenance
shop itself.
They are
the contract administrators for the leak repair contract.
The
nonsafety-related
applications
are controlled by engineers
not
from the design organization,
but using procedures
approved
by
the design organization.
h.
Is plant management
aware of the extent of use
and any significant
issues
resulting from use of temporary leak sealants.
20
Yes, plant management
is aware.
A recent study by the
mechanical
shop engineers
analyzed leak repair applications for
the past several
years with the goal of pointing out
opportunities for improved permanent
repairs
such that
temporary on-line repairs
would be minimized.
There
have
been
design
changes
such
as replacing sight glass
columns with
sealed units,
and replacement
of small valve types with more
reliable valves.
As
a result,
the
use of temporary on-line
repair
has decreased
significantly over the last three years.
Exit Interview
The inspection
scope
and findings were summarized
on October 22,
1993,
with those
persons
indicated in paragraph
1 above.
The inspector
described
the areas
inspected
and discussed
in detail the inspection
results listed below.
Proprietary material is not contained
in this
report.
Dissenting
comments
were not received
from the licensee.
Item Number
Status
335,389/93-22-01
open
335,389/93-22-02
open
Description
and Reference
VIO - Failure to Follow Procedure for UHS
Valves Air Supply Haintenance,
paragraph
S.b.
VIO - Failure to Perform
and Document
a
10 CFR 50.59 Safety Evaluation for
UHS Valves
Air Supply,
paragraph
5.b.
Abbreviations,
and Initialisms
ANPS
ATTN
CFR
IR
LCO
LER
Alternating Current
Auxiliary Feedwater Actuation System
(system)
Assistant
Nuclear Plant Supervisor
Administrative Procedure
Attention
Code of Federal
Regulations
Containment
Spray Actuation System
Direct Current
Demonstration
Power Reactor
(A type of operating license)
Emergency
Core Cooling System
Engineered
Safety Feature
The Florida Power
5 Light Company
Hydraulic Control Valve
Health Physics
High Pressure
Safety Injection (system)
Instrumentation
and Control
[NRC] Inspection
Report
TS Limiting Condition for Operation
Licensee
Event Report
Letter of Instruction
MFIV
No.
NPF
NPWO
NRC
NSAC
ONOP
OP
ppb
PSL
Pub
gA
gI
St.
TS
21
Low Pressure
Safety Injection (system)
Main Feed Isolation Valve
Main Feedwater
Pump
NonCited Violation (of NRC requirements)
Number
Nuclear Production Facility (a type of operating license)
Nuclear Plant Supervisor
Nuclear Plant Work Order
Nuclear Regulatory
Commission
Nuclear Safety Analysis Center
Off Normal Operating
Procedure
Operating
Procedure
Part(s)
per Billion
Plant St. Lucie
Publication
guality Assurance
guality Instruction
Recirculation Actuation Signal
Radiation Control Area
Refueling Water Tank
Safety Analysis Report
Safety Evaluation
Saint
Technical Specification(s)
Updated Final Safety Analysis Report
[NRC] Unresolved
Item
Violation (of NRC requirements)