ML17227A412
| ML17227A412 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 04/16/1992 |
| From: | Butcher R, Elrod S, Lesser M, Schin R, Michael Scott NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17227A410 | List: |
| References | |
| 50-335-92-05, 50-335-92-5, 50-389-92-05, 50-389-92-5, NUDOCS 9205120083 | |
| Download: ML17227A412 (25) | |
See also: IR 05000335/1992005
Text
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UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.IN.
ATLANTA,GEORGIA 30323
Report Nos.:
50-335/92-05
and 50-389/92-05
Licensee:
Florida Power
5 Light Co
9250 Nest Flagler Street
Miami,
FL
33102
Docket Nos.:
50-335
and 50-389
License Nos.:
and
Facility Name:
St. Lucie
1 and
2
Inspection
Conducted:
Februar
25 - March 23,
1992
I
Inspectors
r
, Senior
Ress
ent
nspector,
St. Lucie Site
M.
.
cott,
esi ent
nspector
D
eS
ne
II,/1Z.
at
Signed
u c
,
en>or
es)
ent
nspector,
Tur ey Point Site
e
gne
~. Lesser,
Se
or Resident
Inspector,
Nor h Anna Site
c
D
e
S gne
Approved by:
R.
P. Schin,
roject
ine
.
Lan ss,
Se
ion
C ief,
Division of Reactor Projects
Da
e Si
ned
z-
D te
igned
SUMMARY
Scope:
This routine resident
inspection
was
conducted
onsite in the
areas
of plant
operations
review,
maintenance
observations,
surveillance
observations,
fire
protection
review,
review of nonroutine
events,
followup of regional office
requests,
and followup of previous inspection findings.
Results:
This inspection
found that the licensee
operated
the
two units in
a routine
manner with obvious
regard for safety.
Minor events
occurring during the
period,
such
as
a loss of circulating water
pump
and
an
emergency
diesel
generator failure during testing,
received
prompt responses
consistent with the
9205120083
920022
ADOCK 05000335
9
event.
Maintenance
controls
were appropriate
for the various
maintenance
activities.
Followup inspection
to Service
Water Inspection
335,389/91-201
produced
enforcement findings which were issued with this report.
Within the areas
inspected,
the following violations were identified:
VIO 335,389/92-05-04,
Inadequate
Test of Intake
Cooling
Water
Pump,
paragraph
7d.
VIO 335/92-05-05,
Failure to Test Certain Valves quarter ly as
Required
by
the Inservice Test Program,
paragraph
7e.
Within the areas
inspected,
the following unresolved
item was identified:
URI 335,389/92-05-06,
Evaluation of whether
or
not Air Controls -for
Component
Cooling
Water
Temperature
Control
Valves
should
be Safety
Related,
paragraph
9e.
Within the areas
inspected,
the following non-cited violation was identified:
NCV 335,389/92-05-03,
Inadequate
Training Materials,
paragraph
7c.
Within the areas
inspected,
the following non-cited deviation
was identified:
NCD 335,389/92-05-02,
Failure to Maintain Submersible
Valve gualifications
as Described in the Final Safety Analysis Report,
paragraph
7b.
REPORT
DETAILS
Persons
Contacted
Licensee
Employees
D. Sager, St. Lucie Plant Vice President
G. Boissy, Plant General
Manager
J. Barrow, Fire/Safety Coordinator
H. Buchanan,
Health Physics
Supervisor
C. Burton, Operations
Manager'.
Church,
Independent
Safety Engineering
Group
R. Dawson,
Maintenance
Manager
R. Englmeier,
Nuclear Assurance
Manager
R. Frechette,
Chemistry Supervisor
J. Holt, Plant Licensing Engineer
C. Leppla,
Instrument
and Control Supervisor
L. McLaughlin, Licensing Manager
G. Madden, Plant Licensing Engineer
A. Menocal,
Mechanical
Supervisor
T. Roberts, Site Engineering
Manager
L. Rogers, Electrical Supervisor
N. Roos,
Services
Manager
C. Scott,
Outage
Manager
M. Shepherd,
Operations
Training Supervisor
D. West, Technical
Manager
J. West, Operations
Supervisor
W. White, Security Supervisor
D. Wolf, Site Engineering Supervisor
E. Wunderlich, Reactor Engineering Supervisor
Chairman
Other
licensee
employees
contacted
included
engineers,
technicians,
operators,
mechanics,
security force members,
and office personnel.
NRC Employees
S. Elrod, Senior Resident
Inspector,
St. Lucie Site
M. Scott, Resident
Inspector,
St. Lucie Site
M. Lesser,
Senior Resident
Inspector,
North Anna Site
R. Butcher, Senior Resident
Inspector,
Turkey Point Site
R. Schin, Project Engineer, Division of Reactor Projects
- Attended exit interview
and initialisms used
throughout this report are listed in the
last paragraph.
2.
Review of Plant Operations
(71707)
Unit 1 and Unit 2 began
and ended
the inspection period at power - days
91
and 473 of continuous
power operation, respectively.
During the inspection
period,
a number of
INPO personnel
were onsite for
two weeks conducting evaluat'ion activities.
During the inspection
period,
both the cognizant
NRC Region II Project
Branch Chief and the Deputy Director of the
NRC Region II Reactor Projects
Division visited the site.
a 0
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
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:
Unit 2
EDGs,
Unit I and
2 SFPs,
Unit I and
2 SFP
pumps
and heat exchangers,
and,.
Unit 2 Control
Room ventilation.
On
March
9,
1992,
while touring the Unit I B-train
4160 Volt
switchgear
room, the inspector
observed
that the
18
ICW breaker
had
been
removed from its switchgear
housing
and
was sitting unrestrained
in front of other safety-related
switchgear.
Based
on nuclear
industry
concerns
regarding
seismic qualification of safety-related
switchgear
with breakers
in racked-out
or
removed condition,
the
licensee
was informed that the
removed
breaker
should
be restrained
to prevent possible safety-related
switchgear
damage
during
a seismic
event.
The licensee
initiated
REA 92-104,
requesting
engineering
evaluation
of circuit breaker
seismic
loading/qualification
in
various positions
other than fully installed.
This issue will be
tracked
as
IFI 50-335,389/92-05-01,
Seismic gualification of Racked
Out Circuit Breakers.
At 9:30 p.m.
on March
14, Unit 2 control
room operators
recognized
a
loss of
panels
H, J,
K, L,
M, and
N due to lit
becoming
very dim and
no annunciator
lights
on these
panels
lighting brightly when
checked.
Operators
entered
ONOP
2-0030137,
Partial
or Complete
Loss of Annunciators,
Rev.
1.
The
ONOP
was written in the
two
column
EOP format
and did contain
guidance for operators;
including checking all alarm panels for the
extent
of the malfunction,
referring to
an
Summary
procedure
to assess
the
impact of the lost annunciators,
increased
monitoring of the
RTGB,
and
implementing the
Emergency
Plan per EPIP
3100022E,
Classification
of
Emergencies.
The
required
declaration
of
an
Unusual
Event
based
on
a loss of indication or.
alarm panels
which, in the opinion of the NPS/EC,
would significantly
impair accident
or emergency
assessment.
An unusual
event
was not
declared.
(The
inspector
later
reviewed
the
approximately
240
'nnunciators
lost with an
who described
why he also would not
have declared
an Unusual
Event.)
The
ONOP also directed operators
to
check annunciator
power supplies
and contact the
18C staff.
At 10:48
p.m.,
ISC personnel
manually
bypassed
the power supply inverter (and
its logic) and restored
the annunciator
panels to operation
on backup
120 volt ac
power.
IKC personnel
subsequently
replaced
the failed
power supply inverter and logic assembly.
Shop
testing
of the failed
power
supply
assembly
revealed
a
previously
unseen
failure mode.
A 12 volt regulator
had failed,
causing
28 volt unregulated
dc voltage to be introduced into the
12
volt regulated
dc voltage
sensor
card.
The voltage
sensor
card
failed, causing
the
two power supply switching relays to chatter
as
they switched
back
and forth between
the normal
(120 volt ac through
the
power supply assembly)
and alternate
(125 volt dc through
the
inverter)
power sour ces.
This caused
the related
alarm lights in the
control
room to
become
very dim.
ISC determined
that
a similar
failure to
a different power supply assembly
could cause
the loss of
virtually all control
room annunciators.
For long term corrective
action,
I&C initiated
an
REA requesting
modification of the
power supply to limit such
a failure to
a specific group
of annunciators.
Also,
the
licensee
labeled
the
power
supply
inverter
bypass
switches
(located
inside
cabinets
in the
cable
spreading
room)
and
issued
a temporary
change
to
ONOP 2-0030137
on
March
19.
This temporary
change
gave operators
instructions
on when
and where to operate
the
power supply inverter bypass
switches.
The
inspector
walked
down the temporary
change with an operator'nd
found
that
the
bypass
switches
were clearly labeled,
but were
located
inside different cabinets
than
those listed in the temporary
change.
The
inspector
gave
this
information
to the
on shift for
correction of the temporary
change.
On March
15,
the
2B1 circulating water
pump failed.
Prior to the
failure, the
pump
had
been restarted
at 9:05 a.m. following the
2B1
water box post-cleaning
return to service.
Subsequent
power ascension
was
stopped
at
90 percent for turbine valve testing
at
10:20
a.m.
At 1: 15
p.m.
operations
noticed
the main turbine
generator
megawatt output decreasing
and main condenser
back pressure
increasing.
Approximately two minutes later,
the operators
noticed
the
2B1 circulating
pump current
reduced
from the normal
220 to 270
ampere
range
to
130
amperes.
The control
room operators
began
a
and dispatched
other operators
to observe
the pump.
The non-licensed
turbine operator
and
an
SRO found that the
2B1
pump
had
an overheated
shaft
and gland area.
The area
was visibly warm.
The
pump
was shut
down at approximately
1:20 p.m.
Plant
power
was
stabilized at 85 percent at this time.
At 1:40 p.m.
on the
same
day,
a non-licensed
operator
observed that
the
2A MFP
had lost
some
amount of lubricating oil.
The reservoir
was
down about
5 gallons
when checked,
and oil was visible around
and
dripping from the
coupled
pump bearing.
Oil- was
added
to the
reservoir,
the
mechanical
maintenance
staff
was
called,"
and
the
predictive maintenance staff was called for an oil sample.
As
a conservative
measure,
at 2: 10 p.m., plant
power
was further
reduced
to approximately
70 percent
in case
there
was
a problem with
the
MFP.
The plant could not
be maintained
on line at this
power
should
a
MFP trip because
the
MFPs were only 60 percent
capacity
pumps,
however power was not reduced
below 70 percent
due to shutdown
margin restraints
and the
4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />
LCO time restraints
of TS 3. 1.3.6,
Regulating
CEA Insertion Limits.
If the
had tripped
from 70
percent
power,
the operators
planned
to quickly reduce
power to keep
the plant on line and temporarily enter the
TS
4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />
LCO.
Subsequent
2A MFP observation,
evaluation,
and oil sample laboratory
results
revealed
no
probable
pump problems.
No upward
trending
bearing
temperatures
were observed.
Vibration analysis
indicated
no
changes
in
pump vibration.
Oil sample
analysis
indicated
no oil
degradation.
The initial conclusion
drawn
was
that
pump
had
experienced
some
minor,
unexplained
Further analysis
would follow.
At 9:30 p.m., after the laboratory results
were
digested,
power
was
increased
to around
90 percent,
the
maximum
achievable
with the
missing
2B1 circulating
pump
and resulting
condenser
back pressure
limitations.
The circulating
pump
was carefully disassembled
to understand
its
failure mode.
The shaft
had cracked or cracked
and rewelded itself.
The shaft sleeve
on which the
packing
rode
had
been
heated
to the
point that portions of it had
been welded to the packing gland.
The
affected
parts
were
removed
to the licensee's
materials
laboratory
for further evaluation.
At the
the
licensee
thought that sufficient water lubrication and cooling was available
to the
pump packing
area
based
on feedback
from the non-licensed
operator
who
had started
the
pump at 9:05
a.m.
The licensee
is
continuing their review and root cause determination.
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 assure
that operations
and security
performance
remained
at acceptable
levels.
Shift turnovers
were
observed
to verify that they
were
conducted
in accordance
with
approved
licensee
procedures.
Control
room annunciator
status
was
verified.
Except
as noted below,
no deficiencies
were observed.
During this
inspection
period,
the
inspectors
reviewed
tagout
(clearance)
2-2-86 - 2B
Due to a need to reduce
condenser
tube fouling rates
and reduce the
overall
environmental
effluents,
the
licensee
has
obtained
an
,permit for use of
a chemical
agent to reduce
clam growth in the
plants'ntake
structures
and condensers.
The chemical
agent
would
be
an adjunct to the existing use of hypochlorite.
Hypochlorite has
had
a minimal effect
on the clams,
oysters,
and bivalves for which
the
chemical
agent
was targeted.
On March 4,
1992,
a contractor
began
injection of the
chemical
agent
into the Unit
1
intake
structures.
The injection period lasted
approximately
10 days.
The
trial period will be
18 months in duration with injections occurring
every
2 to 3 months.
The posting of required notices to workers
was reviewed
and was noted
to be satisfactory.
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.
Because
during the inspection period,
the
2B
EDG had
been
placed out
of service for PMs
and subsequently
returned
to service,
the
2A
was started
on February
27 for an idle start operational
check per
TS 3.8. 1. l.b.
The
2A EDG's
2A1
( 16 cylinder)
engine established
the
required fuel rack position for 450 rpm on the idle start test while
the
2A2 ( 12 cylinder) engine accelerated
to 900 rpm, carrying the
16
cylinder engine to the
same
speed - the engines
were coupled via the
common generator
between
them.
Appropriate annunciation lit.
The speed
adjusting
Bodine brand motor on the
2A2 engine's
governor
was
found missing
a brush.
This left the motor inoperative
and
locked in its last operating
position,
which had
been at its high
speed
stop.
Due to the Bodine motor problem,
the governor
was at its
high fuel rack stop (which would produce
900 rpm).
This position was
fortuitous
in that,
had
the
2A
EDG received
an
emergency
start
signal,
the generator
would have
loaded with required
emergency
bus
loads.
The screwed-on
brush
cap that held the brush spring
and brush against
the motor commutator
had loosened.
The brush
and cap were found atop
the governor
housing just beneath
the motor.
Speculation
was that
the externally threaded
cap
had
loosened
because
of diesel
running
vibration.
Work instructions
were
issued
and
implemented
that
evening
(February
24) to check tight all Bodine motor brush caps.
Oue to loss of governor control, the
2A EOG was declared
The
2B
was
started
on
February
28 within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />,
per
TS 3.8.l.l.b,
A special
report is due from the licensee within 30
days.
By the
end of the inspection
period,
the licensee
had obtained
a
telecon
from the governor vendor for a fix on the Bodine motors.
The
vendor indicated that currently the motors were being sold with a dot
of
RTV in the brush-cap-to-motor-body
joint to inhibit vibration
induced
loosing of the brush
cap.
At the
end of the inspection,
the
licensee
had received on-site
review committee
approval
for repair
instructions
to apply
a
dab of
RTV to the exterior of the screwed
joint.
,The remaining
brush
caps
were subsequently
verified to
be
tight.
The resident
inspectors
were collecting information regarding
the specific event for consideration
as
a generic issue.
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.
Observed
operator
deportment
and actions
during the recovery
phase of the
Unit 2 2B1 circulating water
pump loss were commendable.
Followup actions
on the transient
experienced
by the
2A NFP were thorough.
Staff actions
were timely in their support of plant operations.
3.
Survei1 l ance Observati ons
(61726)
Various
plant
operations
were verified to
comply with selected
TS
requirements.
Typical of these
were confirmation of TS compliance for
reactor coolant chemistry,
RWT conditions,
containment
pressure,
control
room ventilation,
and
and
DC electrical
sources.
The inspectors
verified that
testing
was
performed
in
accordance
with
adequate
procedures,
test instrumentation
was calibrated,
LCOs were met,
removal
and restoration
of the affected
components
were
accomplished
properly,
test results
met requirements
and
were reviewed
by personnel
other than
the individual directing the test,
and that any deficiencies identified
during
the testing
were properly reviewed
and
resolved
by appropriate
management
personnel.
The following surveillance tests
were observed:
a.
OP 2-2200050,
Rev 38,
Emergency
Diesel
Generator
Periodic Test
and
General
Operating Instructions,
28
b.
OP 2-2200050,
Rev 38,
Emergency
Diesel
Generator
Periodic Test
and
General
Operating Instructions,
2A EDG.
The
2A EDG test is discussed
in paragraph
2.c of this report.
c.
OP
1-2200050,
Rev 61,
Emergency
Diesel
Generator
Periodic Test
and
General
Operating Instructions,
lA EDG
d.
OP 1-0700050,
Rev 37, Auxiliary Feedwater
Periodic Test,
lA pump
e.
OP
2-0030150,
Rev 33,
Secondary
Plant Operating
Checks
and Tests,
Section
8. 1.4,
Turbine Valves.
During the turbine governor valve
tests
on
February
24,
paragraph
8. 1.4.k
(OP
2-0030150),
the
indicating lights
on the control
board did not react
as predicted.
The
"open" light did not extinguish
when three
of the four
governor
valves
went closed
(on the fourth valve,
the light went
out).
ISC personnel
indicated that the
"open" light was
operated
by the
snap-lock
valve position switches.
Often during long runs
between
operation of the valve position switches,
the switches
have frozen
due to corrosion buildup.
This
was described
as
an industry-wide
phenomenon.
I&C had
an operations-written
NPWO to repair
the
affected
switches.
Additionally, ISC had
been working with vendors
toward
potentially
replacing
the
snap-lock
switches
with
magnetic/reed
switches.
A
REA
was
to
be
submitted
to site
engineering
on the subject.
Not addressed
by the
procedure
were
the alternate
methods actually
used
by
operations
to verify valve
closure.
An
and
a
non-licensed
operator
were at the valves
when
they were cycled to
observe
proper operation.
Valve test lights
on the vertical
control
board
changed
state.
Also, the digital
readout
ceased
downward trending at 0.6 to 2.0 percent
closed (this indicated closed
but due to cold calibration of the valve position indication absolute
zero indication did not occur with the valve hot).
A change to this
procedure
was instituted to
add
the alternate
means
of verifying
valve closure.
f.
OP
1-0700050,
Rev
Periodic Test,
1B
pump.
During the surveillance of the
1B
AFW pump, it was observed that one
of the motor's
louvered exit covers
was installed with the louvers
opening
upward.
Since there
was
no rain catch or lip above this
cover, this would tend to invite rain water entry when the
pump was
not operating.
Subsequent
review showed that,
due to construction of
the motor housing,
water would only enter the shielding
shroud
and
still would not gain direct entry to the motor windings or bearings.
Standing
water in the internal
shroud
volume would tend to induce
rust
degradation
of the
shroud.
The
louver installation
was
subsequently
corrected.
The surveillances for this period were fully'acceptable
with the exception
of the
2A EDG.
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
service;
quality
control
records
were
maintained;
activities
were
accomplished
by qualified
personnel;
parts
and
materials
used
were
properly certified;
and
radiological
controls
were
implemented
as
required.
Work requests
were
reviewed
to determine
the
status
of
outstanding
jobs
and
to
assure
that
priority
was
assigned
to
safety-related
equipment.
Portions
of
the
following maintenance
activities were observed:
a.
NPWO 7162/63
"C" subchannel
Low Level
S/G Failed Surveillance
1-1400050
b.
NPWO 7185/64
Unit 2 Annunciator
Power Supply Logic Housing Failure
c.
NPWO 4733/61
Repack
Charging
Pump
1C
d.
NPWO 4633/66
4160
V Switchgear
2B3 (SB) Feeder to Bus
2AB.
Per
NPWO
instructions,
the feeder
breaker
from the "B" side safety
4160 Volt
switchgear
was
removed
and replaced
in a routine manner.
The removed
breaker
would
be
overhauled
by
a
vendor
as
had
the breaker that
replaced it.
A spare
breaker
was
overhauled
and readied for this
pre-outage activity.
The effort was part of attempt to complete the
Unit
2
4160 Volt breaker
nine-year
overhaul
cycle.
The
feeder
breaker
was
not carrying
any load at the
time of the transfer.
Operations
personnel
who racked
the
breakers
out
and in utilized
procedure
OP 2-0910023,
Rev 5, Transfer Electrical
Alignment on the
4160V and
480Y Load Center
2AB Buses.
The replacement
breaker tested
sati sfactorily.
e.
NPWO 4610/61
Dragon Valves Model Numbers
10615
and 10905,
Inspect
for Loose Packing Nuts
f.
NPWO 2729/62
Dragon Valves in ECCS
Rooms
NPWOs e.
and f. above, for Dragon valves,
were followed this report
period
due to
an event
found during the last report period
and
discussed
in report
335,389/92-04.
Several
of the safety-related
vent
and drain valves in the Unit
1
room were found with their
packing retaining
nuts
less
than
hand tight.
Based
on tightening
instructions
provided
by the vendor,
these
NPWOs direct checking the
tightness of the nuts in both units.
The
observed
maintenance
activities
were satisfactory
and controlled
appropriately.
5.
Fire Protection
Review (64704)
During the course of their normal tours,
the inspectors
routinely examined
facets of the Fire Protection
Program.
Normally the inspectors
reviewed
transient fire loads,
flammable materials
storage,
housekeeping,
control
of hazardous
chemicals,
ignition source/fire risk reduction efforts, fire
protection
system surveillance
program, fire barriers,
and fire brigade
qualifications.
The fire protection
program
seemed
to be working well during this period.
6.,
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.
The events
discussed
in paragraph
2 (annunciator
problems, circulator pump
failure,
and
EDG failure) were
handled
promptly with active
management
overview.
7.,
Followup of Inspector Identified Items (Units
1 and 2) (92701)
a.
(Closed - Units
1 and
2)
URI 335,389/91-201-01,
Pre-operational
Test
Review.
This
URI identified
several
ICW
system
pre-operational
test
anomalies.
The licensee
reviewed
the following discrepancies
to
ensure that system capabilities
were
known:
10
Inconsistences
were found in flow and differential pressure
data
at different points in the test
although
the system
alignment
was apparently
the
same.
The
licensee
attributed
this to modulation
of temperature
control valves during the test which may have changed
the system
parameters.
Since
the intent of this portion of the test
was to
obtain
system flow characteristic
data for modeling
purposes,
the
parameter
changes
were found not to be significant.
The
inspector
had
no further questions
on this point.
Minimum acceptable
flow was not maintained at all times during
the test.
The licensee
evaluated
this
and determined
that the intent of
the stated
minimum flow was to approximate
expected
flow rates
and that operation
below this value did not affect the test.
The inspector
had
no further questions
on this point.
The pre-operational
test did not establish travel stops
on flow
control valves to prevent
pump runout.
The licensee
determined
that travel
stops
were
used at
some
point
during
the
pre-operational
testing
phase
and
not
documented
as
such.
The licensee
could not determine
exactly
when
and
why they were
used other than to address
the concern
with pump runout which apparently
developed
during the testing.
The
licensee
recently
implemented
modifications that control
runout flow by use of orifices and negated
the requirements for
FCV travel
stops.
The inspector
had
no further questions
on
this point.
Valve settings for the backup source of lubrication water to the
ICW pumps were not established.
't
The licensee
referenced
FSAR section 9.2. 1 which stated that the
backup
source
of lubrication (domestic
water
system)
was only
required during initial
ICW pump startup
[when the
ICW system
would
be
empty]
and
was
not
needed
for restart
of
a
pump
following loss of offsite power.
The licensee
determined that
valve settings for the domestic water system were not required.
The inspector
had
no further questions
on this point.
There
were significant differences
in differential
pressures
recorded for
ICW strainers.
The licensee
attributed differences
to strainer cleanliness
or
reading
inaccuracies
and
concluded
that the differences
did not affect the test results.
The'nspector
had
no further
questions
on this point.
11
The inspector
concluded
that
the licensee
adequately
reviewed
the
anomalies
and that they did not significantly affect the
outcome of
the pre-operational
test.
b;
(Closed
-
Units
1
and
2)
Deficiency
Item 335,389/91-201-01,
~
Incomplete
and Inaccurate
FSAR Discussions.
The inspector
reviewed
the following discrepancies
regarding
discussions
of the
ICW system:
Valves NY-21-2 and MV-21-3 were described
in the
FSAR as having
been
upgraded
(Unit 1) or qualified (Unit 2) for submersible
service
yet
were
subsequently
determined
during
inspection
91-201 not to be qualified for submersible
service.
The
license
provided
some
evidence
in the
form of memos,
requisition
forms,
motor test
recor'ds
and material
receipts
which suggested
that submersible
qualified motors
may have
been
installed at
some point several
years
ago.
The licensee
could
not,
however,
provide positive documentation.
Nevertheless,
the
licensee
had cooeitted to install submersible qualified
NOVs and
controls
did
not exist
or
were
not effective
to
ensure
submersible
qualification
was maintained.
In this case,
the
licensee
deviated
from a written commitment in that the valves
were
not maintained
as qualified for submersible
service
as
stated
in the
FSAR.
The licensee
subsequently
determined
that the valves
were not
required to be qualified for submersible
operation
on the basis
that
a flooding event
and
a design
basis
accident
occurring
simultaneously
was
not within the plant design
basis.
The
inspector
reviewed
the licensee's
draft 50.59 evaluation while
on site
and the final versions after they were issued,
and did
not identify any further concerns.
The licensee
indicated that
they
planned
to correct
the
FSAR.
This deviation
from
a
commitment
is not being cited
because
subsequent
operational
philosophy regarding
hurricanes
and
subsequent
modifications to .
Unit
1
ICW pumps to delete
the water lubricating
system
have
negated
the safety significance.
(2)
CCW temperature
control
valves
TCV 14-4A and
14-4B fail open
upon loss of in'strument air but were not described
in the Unit
1
CCM section.
The licensee
provided the inspector with sections
of the
which adequately
described
valves
TCV 14-4A and
14-4B (sections
7.3.1.3.2
and 9.2.1.5,
table 9.2-2,
and figure 9.2-1).
The
inspector
had
no further questions
on this point.
IN
12
(3)
ICW
valves
21-3A
and
38
isolated
the
non-essential
lubricating water header
upon SIAS but were not described
in the
FSAR.
(5)
The licensee
provided
the inspector with
FSAR table 7.3-2
and
figure 9.2-1a,
which described
valves
FCV 21-3A and 21-38.
The
inspector
had
no further questions
on this point.
The
FSAR incorrectly
referenced
a
deleted
section
which
described
recirculation
operation
between
the
discharge
and
intake canals for biofouling control.
The licensee
pointed out that recirculation
was proposed at one
point in time and actual modifications
had
been initiated, but
subsequently
terminated.
and
9.2-1e
accurately depicted
the as-built status.
The inspector reviewed
the
licensee's
currently
proposed
FSAR correction.
The
inspector
determined
that this error
did not
represent
a
significant concern.
The
FSAR did not
include
aspects
of the
sel f-lubrication
modification on the
2A
ICW pump.
The inspector
determined
that
a weakness
existed with promptly
closing out the design
change
package
in order to ensure that
the
FSAR is
updated.
The licensee
conducted
a review
and
determined this to be
an isolated
example.
Section
9.2.7
of the
FSAR incorrectly described
the
UHS by
discussing
only two of three intake pipes.
The inspector
found that
FSAR section 9.2.3
and figure 9.12-1b
describe
the three intake pipes for the
UHS.
(Closed
-
Units
1
and
2)
Deficiency
Item
335,389/91-201-02,
Inadequate
Training Materials.
Several
examples
of inaccurate
or incomplete descriptions
of the
ICW
System
were identified in training documents.
Examples
included the
following;
strainer
mesh sizes
were incorrect,
ICW self-lubrication modification
was
not
implemented
in all
training documents
in a timely manner,
documents incorrectly described
cross-connected
operation of the
ICW system,
documents
omitted unit 2 specific
TCV closure limits,
13
some setpoints
were inaccurate,
and
listings did not match verbatim the control
room .
The inspector
reviewed
the deficiencies
and determined
that while
weaknesses
may exist for ensuring
accurate
training materials,
the
deficiencies
were minor in nature
and did not represent
a safety
significant
concern.
The inspector
reviewed
corrected
training
materials
including
an 'RCO Self Study Test
on Cooling Water Systems
(0704201)
and
a
SNPO
Lesson
Text on Component
Cooling Water System
0511016).
The inspector additionally determined that other training
material deficiencies
were being adequately
addressed.
It appears
that the licensee's
Administrative Procedure
AP005766,
Training
Resources,
Information
and
Material
Control,
was
not
followed in that review of plant modifications for incorporation into
training material
was not adequate
and resulted in the discrepancies.
This
NRC identified violation is not being cited
because
criteria
specified
in Section
VII.B of the
NRC
Enforcement
Policy
wer e
satisfied.
This is identified
as
NCV 335,389/92-05-03,
Inadequate
Training Materials.
(Closed - Units
1 and 2) Deficiency Item 335,389/91-201-03,
ICW Pump
C and Header Inoperability.
This item involved potential inoperability of the
C
ICW pump
due to
not
adequately
demonstrating
operability
of
the
pump
and its
associated
actuation circuitry.
The licensee
determined that the
C
ICW pump start feature
on SIAS was
not required to be tested
because
during condi tions when the
pump was
required
to
be operable,
the
pump would
be running
and would not
require
an auto start signal.
The inspector
questioned
the licensee
concerning
a Loss of Offsite
Power
actuation
signal
and
reviewed electrical
logic drawings
to
determine if the
C
ICW pump
was
adequately
tested.
The inspector
determined
that following a Loss of Offsite power,
the
C
pump would
trip and later
be
sequenced
back after the
bus
was energized
by the.
diesel
generator.
The logic associated
with this, including relays
and
contacts,
was
not
tested
at
any periodicity.
Technical
Specification surveillance
4.8. 1. 1.2.e.4 requires
in part that
a loss
of offsite power be simulated every
18 months
and that auto-connected
shutdown
loads
be verified to energize
through the load sequencer.
Test procedures
failed to adequately
demonstrate
the ability of the
C
ICW
pump
logic, to
perform
this
function.
This
is
335,389/92-05-04,
Failure to Adequately
Test the
C Intake Cooling
Water
Pump.
14
(Closed - Units
1 and 2) Deficiency Item 335,389/91-201-04,
Inservice
Testing
IST Deficiencies.
One concern
involved the testing of manual
valves
SB-21211
and
SB-21165.
The licensee's
IST program
dated
January
3,
1990
identified these
valves to be exercised
quarterly.
The licensee
subsequently
determined
that these
valves were not required
by
Section
XI to be in the program
and
never initiated testing
on
them.
The licensee
did not obtain prior
NRC approval
for this
change.
Prior approval
is
not required
as indicated
in the
response
to question
62 of the October
25,
1989
NRC letter,
Minutes of the Public Meetings
The
concern
was that the licensee failed to update their IST program
and
inform the NRC'f the
change;
The inspector
reviewed
further guidance
in the referenced
letter (question
61) which
indicated that the
NRC staff should
have the current
IST program
being
implemented.
The inspector
determined that this example
represented
a weakness
in not maintaining
an accurate listing'f
all valves in the program.
However, in that these
valves were
never required
by the code to be tested
and were inadvertently
added
to the list, the licensee's
failure to promptly revise
their
program
does
not
represent
a significant
concern.
Additionally, the licensee
was able to show the inspector that
these
valves
were in fact exercised
on
a quarterly basis during
surveillance
testing of
ICW
pump discharge
check
valves
per
Administrative Procedure
1-0010125A,
Surveillance
Data
Sheets.
The licensee
planned to correct
the program.
The inspector
had
no further questions
on this point.
(2)
'A second
concern
involved the testing
frequency of the valves
TCV-14-4A and
14-4B
on Unit 1.
The licensee
had
been testing
the valves during cold shutdown.
The valves were classified
as
Category
B power operated
valves.
Code requirements
for testing
include stroke valve timing every three months.
The licensee's
program
valve table specified
a test
frequency
of cold
shutdown
and referenced relief request
VR-35.
VR-35 requested
relief from timing the valve
and provided
a basis
indicating
that
measurements
of valve closure
times
are not practical.
VR-35 did not request
nor provide
a basis for testing the valve
at
the
reduced
frequency
of cold
shutdown.
Further,
YR-35
stated
that alternate
testing
would
be
done
on
a quarterly
frequency.
The licensee's
program
was
approved
on
an interim basis
on
,
October
17,
1990.
This granted relief to exempt valve timing
for the valves.
No approval
was granted for a
reduced
test
frequency.
The
inspector
concluded
that
the
licensee's
submittal
was
inconsistent.
The
NRC granted relief from valve timing.
Therefore,
the valves
were required
to
be tested
every three
15
months.
This is identified as
a violation of the requirements
of the l icensee
'
IST program,
Fai lure to Test
TCV-14-4A and
14-4B every three months.
This is VIO 335/92-05-05,
Failure to
Test Certain Valves quarterly
as Required
by the Inservice Test
Program.
The
inspector
reviewed
the licensee's
revised
submittal
of
October
23,
1991 which included revision
3 to relief request
VR-35.
Further errors
were identified with the request in that
the
requirements
for check
.valve tasting
were incorrectly
referenced.
Additionally, it was not clear whether the licensee
considered
the valve to be power operated
or fail safe.
8.
Followup of Headquarters
and Regional
Requests
(92701)
During the
inspection
period,
a
survey
on
maintenance
backlog
was
performed for the
NRC Region II Office.
9.'eview of Component
Cooling Water Temperature
Control System (Part of the
Intake Cooling Water System)
(92701)
a ~
While reviewing Unit
1
ICW system operation,
the inspector
observed
that:
(a)
ICW TCVs I-TCV-14-4A and
B had
a failure mode that may not
have
been previously evaluated,
and (b) the air-operated
controls for
the temperature
control valves
may not have the proper qualifications
for the safety functions performed.
If instrument air were lost:
The temperature
control valves
themselves
and their spring-open/
air-close Bettis operators
were designed
to fail open,
and were
Seismic Category
I and safety-related.
The qualification status
of the remaining air-operated
control
components
would not matter.
If instrument air were not lost:
The temperature
control valves themselves
and their spring-open/
air-close
Bettis
operators
did
not
have
physical
stops
preventing them'rom'eing
shut to less
than
some
minimum
accident flow position.
Failure
modes of the air-operated
controls for the temperature
control valves did not appear to be analyzed.
The air-operated
controls for the
temperature
control
valves
were
considered
by the
licensee
to
be non-safety-related
and
non-seismic.
The Unit
1
components
were located in exposed
locations
on the
CCW platform.
16
b.
A detailed control
system audit followed.
The inspector
approached
the review by:
reviewing
FSAR requirements
and statements;
reviewing
system
modifications
and
associated
analyses,
either
planned
or
accomplished,
that were not in the
FSAR;
reviewing the
component
vendor
manuals for potential
design input; reviewing the physical
installation;
determining
what surveillance
or maintenance
program
elements
have
been
applied to these
components;
and determining if
these
components
are
being
used
to
accomplish
an
actual
safety-related
purpose.
c.
Control System Audit Results:
(1)
The
FSAR review basically
found that the only instrument air
failure discussed
was total loss of instrument air.
There'as
also
a failure
mode listed
where
one of the
two temperature
control valves
would fail to open (for undefined reasons).
The
temperature
control
valves
themselves,
and the attached
Bettis
brand operators,
were identified as safety-related
and qualified
for seismic
category I, but the Bailey valve positioner s, the
associated
pneumatic
TICs,
and the related
pneumatic relays
and
regulating valves
(reducers)
were not designed
as safety-related
or seismic.
Control
components
were
found to actually
be
non-safety-related
per
analysis.'2)
Plant
change
PCM 005-190,
not yet included
in the
FSAR,
was
reviewed.
The
PCN was
performed
on Unit
1 in the fall of 1991.
Its
main
purpose,
per
the plant
maintenance
staff,
was to
replace
obsolete
non-safety-related
control
components
with
newer
safety-related
control
components.
The
maintenance
department
focus
when requesting
this
change
was
on maintenance
and availability of parts,
having nothing to do with the system
safety analysis.
However,
the engineering
analysis
applied to
the modification stated
very strongly that these
were required
to
be safety-related
to function in the
case
of an accident
without loss of instrument air.
This analysis
included
a markup
of the
FSAR deleting
the statements
that the control circuits
were
not safety-related
and
adding
statements
that they were
safety-related
and
had to function following an accident.
This
analysis
applied to:
TICs, which produced
an air pressure
signal
representing
a
temperature
measurement
Air pressure
limiting relays
in the TIC signal
path, since
the
TCVs closed
on increasing air pressure
and these relays
established
the minimum TCV opening
(most closed position);
and
The
common air pressure
regulator that reduced
the supply
air to the operating air pressure
for the
and air
pressure limiting relays.
17
The
above
analysis
stated
that this installation
included
a
positive valve position stop going closed
and
a positive valve
position stop going open, with the valve operating
range
between
those
stops.
Thus,
the valves
were
open far enough for safe
shutdown flow yet restrained
from exceeding
pump runout flow.
This was found to be in error.
The minimum valve position stop
was not
a hard stop at all, it'as established
by the pneumatic
control
system air relay setting discussed
above.
While perhaps
open
enough for safe
shutdown, it was less
than
the minimum
system accident
(LOCA) flow. It was
based
on cavitation in the
pipe
and
downstream
of the valve
and
was
not
based
on safe
shutdown or accident flows.
(4)
(5)
The actions
taken
by the utility did not address
the presently
non-safety-related
Bailey positioners,
or Fisher
volume booster
relays,
or Fisher air reducer
valves
mounted
on
the
themselves.
A future
PCM, also
based
on obsolete
equipment
upgrade,
is planned to address
them.
The vendor
manual
and physical
installation
review found that
both the TIC and the air relay. vendor manuals specified limiting
air pressures
significantly less
then the air supply pressure.
Both the original
and the newly-installed reducing valves vendor
manuals
required that, if components
downstream
could be damaged
by upstream
pressure,
then
a full flow relief valve must
be
installed.
There
were
no relief valves installed in this
new
design.
Interviews of instrumentation
and control staff personnel
showed
that TIC control
loop equipment
was
on
an
18 month inspection
and calibration cycle.
The inspector
concluded
from literature
and installation reviews
that
the utility has
been
depending
on non-safety-related
components,
that were installed in a manner contrary to vendor
manual
requirements
and did not
have
a specific failure mode
analysis,. to control the functioning of the safety-related
TCVs.
The non-safety-related
components
were not backed
up by physical
minimum valve position stops.
The engineering
evaluation of PCM
005-191
appeared
to
have
identified
a previously
unreviewed
safety
question
concerning
a previously
unrecognized
failure
mode.
d.
Subsequent
Licensee Actions
When the inspector inquired about further actions that would appear
to be warranted
upon the licensee
recognizing
the subject conditions
during
Summer,
1991,
the
licensee
subsequently
stated
that last
summer's
analysis
was in error,
though it had
been
signed
by a number
of engineers,
had
been
reviewed
by the Facility Review Group - the
18
technical
specification
onsite
safety
review
group,
and
the
modification had subsequently
been completed
on 'Unit 1.
New material
provided included
a special
study of the licensing
basis
and
a probabi listic risk assessment.
The licensee
stated
that the text of PCM 005-190 would be rewritten.
Interviews
with licensee
engineers
found that
the
licensee
considered
the licensed
basis
of St.
Lucie to not include
a
seismic event coincident with a
LOCA - which would challenge
the
ICW system
from
a heat
removal
basis.
A seismic
event is
postulated
coincident with
a
need for safe
shutdown - which
would not require
more
than
normal
heat transfer to the
ICW
system.
The licensee
stated that it was
common nuclear design practice
to use air system relief valves
only if the components
did not
bleed air during normal operation - these all did normally bleed
air.
The licensee
stated
that there
are
no specific
standards
for
qualification of air-operated
control
components,
therefore
highly reliable commercial
equipment
was satisfactory.
e.
Conclusion
At this point, further review is required to determine if the
should
be
safety-related
or
not.
This
matter
is
335,389/92-05-06,
Evaluation of whether
or not air controls for
Temperature
Control Valves should
be safety related,
pending further
NRC review of basic requirements.
10.
Exit Interview (30703)
The inspection
scope
and findings were summarized
on March 30,
1992, with
those
persons
indicated in paragraph
1 above.
The inspector described
the
areas
inspected
and discussed
in detail
the inspection findings listed
below.
Proprietary material is not contained
in this report.
Dissenting
comments
were not received
from the licensee.
Item Number
Status
Descri tion and Reference
335,389/92-05-01
open
335,389/92-05-02
closed
335,389/92-05-03
closed
IFI - Seismic gualification of Racked
Out
Circuit Breakers,
paragraph
2a.
NCD - Failure to Maintain Submersible
Valve
gualifications
as Described in the
FSAR, paragraph
7b.
NCV - Inadequate
Training Materials,
paragraph
7c.
19
Item Number
Status
Descri tion and Reference
335,389/92-05-04
open
VIO - Inadequate
Test of ICW Pump,
paragraph
7d.
335/92-05-05
open
VIO - Failure to Test Certain Valves
quarterly
as
Required
by the
Inservice Test Program,
paragraph
7e.
335,389/92-05-06
.
open
335,389/91-201-01
cl osed
URI - Evaluation of whether or not air
be
safety related,
paragraph
9e.
URI - Preoperational
Test Review, paragraph
7a.
335,389/91-201-01
closed
335,389/91-201-02
closed
335, 389/91-201-03
closed
335,389/91-201-04
closed
Deficiency Item - Incomplete
and Inaccurate
FSAR Discussions,
paragraph
7b.
Deficiency Item - Inadequate
Training
Materials,
paragraph
7c.
Deficiency Item -
ICW Pump
C and Header
Inoperability, paragraph
7d.
Deficiency Item - Inservice Testing
Deficiencies,
paragraph
7e.
11.
Abbreviations,
and Initialisms
ANSI
ATTN
CFR
CWO
EC
Alternating Current
(system)
American National Standards
Institute
Administrative Procedure
Code American Society of Mechanical
Engineers
Boiler and Pressure
Vessel
Code
Attention
Cubic Centimeter
Component
Cooling Water
Control Element Assembly
Code of Federal
Regulations
Construction
Work Order
Direct Current
Digital Electro-Hydraulic (turbine control
system)
Demonstration
Power Reactor
(A type of operating license)
Emergency Coordinator
Emergency
Core Cooling System
Emergency
Diesel Generator
Emergency
Operating
Procedure
Environmental
Protection
Agency
Emergency
Plan Implementing Procedure
20
FLO
FRG
GL
gpm
Hz
ISC
ICW
IFI
JPN
LCO
MY
NCD
NPF
NPWO
NRC
ONOP
OP
pslg
PSL
QI
RCO
REA
Rev
rpm
SAMA PMC
Engineered
Safety Feature
Flow Control Valve
ABASCO Standard Specification for an
FPL Project
Failure Modes
and Effects Analysis
The Florida Power
8 Light Company
Facility Review Group
Final Safety Analysis Report
[NRC] Generic Letter
Gallon(s)
Per Minute (flow rate)
Heat Exchanger
Hertz (cycle per second)
Instrumentation
and Control
Intake Cooling Water
[NRC] Inspector Followup Item
Institute for Nuclear
Power Operations
InService Testing
(program)
(Juno
Beach)
Nuclear Engineering
TS Limiting Condition for Operation
Loss of Coolant Accident
Letter of Instruction
Main Feed
Pump
Motor Operated
Valve
1
Motorized Valve
Non Cited Deviation
Non Conformance
Report
Non-cited Violation (of NRC requirements)
Nationa1 E1ectrical Manufacturers Association
Nuclear Production Facility (a type of operating license)
Nuclear Plant Supervisor
Nuclear Plant Work Order
Nuclear Regulatory Commission
NRC Office of Nuclear
Reactor Regulation
Off Normal Operating
Procedure
Operating
Procedure
Plant Change/Modification
Preventive
Maintenance
Pounds
per square
inch (gage)
Plant St. Lucie
Quality Assurance
Quality Instruction
Reactor Control Operator
Request for Engineering Assistance
Revision
Revolutions
per Minute
Reactor Protection
System
Reactor Turbine Generator
Board
A Type of silicone rubber
Radiation
Work Permit
Refueling Water Tank
Standard of Unknown Origin
Safety Train 8
~
'
21
SNPO
St.
TQR
TS
Spent
Fuel
Pool
Safety Injection Actuation System
Senior Nuclear Plant [unlicensed] Operator
Senior Reactor [licensed] Operator
Saint
Temperature
Control Valve
Temperature
Indicator Controller
Topical equality Requirement
Temperature
Recorder
Technical Specification(s)
[NRC] Unresolved
Item
Violation (of NRC requirements)