ML17227A682
| ML17227A682 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 12/23/1992 |
| From: | Elrod S, Landis K, Michael Scott NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17227A680 | List: |
| References | |
| 50-335-92-21, 50-389-92-21, NUDOCS 9301070294 | |
| Download: ML17227A682 (34) | |
See also: IR 05000335/1992021
Text
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UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.IIII.
ATLANTA,GEORGIA 30323
Report Nos.:
50-335/92-21
and 50-389/92-21
Licensee:
Florida Power
8 Light Co
9250 West Flagler Street
Miami,
FL
33102
'ocket Nos.:
50-335
and 50-389
Facility Name:
St.
Lucie
1 and
2
License Nos.:
and
Inspection
Conducte
Octobe
20 - November 23,
1992
Inspectors:
. A. Elr
,
Se
R sident Inspector
. A. Sco
,
R
ident Inspector
Approved by:
+~~
Cu +
K. D. Landis, Chief
Reactor Projects
Section
2B
Division of Reactor
Projects
/8 SS g~
Da e
S gned
/
zy'
Date Si
ned
z
Date Signed
SUMMARY
Scope:
This routine resident
inspection
was conducted
onsite in the areas
of
plant operations
review, surveillance
observations,
maintenance
observations,
fire protection review, review of special
reports,
review
of nonroutine events,
onsite followup of events,
followup of headquarters
and regional
requests,
followup of unresolved
items,
and followup of
corrective actions for violations
and deviations.
Backshift inspections
were performed
on October
29 and
November
1, 2,
5,
6,
12,
13,
and
18.
Results:
Plant operations
area:
Operators
planned sensitive plant evolutions
such
as surveillances
well
[paragraphs
3.b.(1)
and 4.a]
and responded
correctly to transients
as
demonstrated
by the planning for and response
to
a dropped
CEA during
a
surveillance
[paragraph 3.b.(l)], response
to a turbine control
oscillation [paragraph 3.b.(3)],
and response
to increased
power level
indication following replacement of several
resistance
temperature
detectors
[paragraph 3.b.(4)].
An operator error. during
an operational
surveillance started
a containment
spray
pump but the initial valve
9301070294
921223
ADOCK 05000355
8
lineup,
a procedural barrier to spraying the containment,
was adequate
and 'prevented
damage.
The licensee
conservatively
pursued
extensive
corrective action to preclude recurrence
[paragraph 3.b.(2)].
Surveillance
area:
A number of important surveillances
were performed in a professional
manner
[paragraphs 3.b.(1), 4.a.-d.].
In two instances,
the licensee
promptly repaired
and retested
Unit 2 main feed isolation valves after
they failed
a- surveillance
and within Technical Specification. time
limits.
This demonstrated
a strong communication
and. coordination
network.
Two maintenance
groups
were present for the surveillance test,
and they effectively supported
the repair
and subsequent
satisfactory
retest
[paragraphs
5.d
and S.e].
I
Haintenance
area:
Resistance
temperature
detector output drift of nonsafety-related
detectors
was discovered
by the
I&C department
during replacement
activities.
This condition had caused
Unit 2 to be operated
at slightly
over
100 percent
power for an undetermined
period of time.
Haintenance
shop testing .of the removed
components
demonstrated ability to find
causal
factors
and excellent coordination with the engineering division
[paragraph 3.b.(4)]
~
This issue is presently
unresolved
pending further
NRC evaluation.
Other maintenance
activities demonstrated
competent
shop
actions
and excellent coordination with operating
and test groups
[paragraphs
5.a-e].
Engineering
area:
The engineering division demonstrated
responsiveness
in their evaluations
of the significance of St. Lucie
2 operating
above the, licensed
power
level
and
the relationship of this condition to the safety'nalysis
[paragraph 3.b.(4)].
Reactor engineering
leadership
in performance of
core physics testing
was excellent
[paragraph 4.a].
Engineering
supported
HFIV nitrogen tubing/fitting leak repairs
by allowing the use
of TFE tape in sealing joint applications
[paragraph
S.e].
Engineering
corrective actions to violations were prompt
as
shown in plant change
157-292 to install
mud dauber
caps
on containment
sensing lines
[paragraph
12.g],
and studies to determine
what valves are actually
within the containment isolation boundary
[paragraph
10.]
Within the areas
inspected,
the following violation was identified:
VIO 335;389/92-21-07,
Failure to Adequately Haintain Containment
Vessel
Integrity, paragraph
10.'ithin
the areas
inspected,
the following unresolved
item was identified:
V
URI 389/92-21-06,
Operation
Above the Licensed
Power Level, paragraph
3.b.(4).
'
Within the areas
inspected,
the following non-cited violations were identified
associated
with events
reported
by the licensee:
NCV 335/92-21-01,
Low Temperature
Over Pressure
Technical Specification
Amendment
Implementation Failure,
paragraph
8.a.
NCV 389/92-21-02,
Failure to Implement
New Technical Specification
-Requirements
for Emergency
Bus Undervoltage,
paragraph
8.d.
NCV 389/92-21-03,
Hissed Surveillance
on
a Radiation Honitor Being
Returned to Service
Due to Personnel
Error, paragraph
8.e.
NCV 389/92-21-04,
Hissed Technical Specification Surveillance,
paragraph
8.h.
NCV 389/92-21-05,
Incomplete Technical Specification Special
Report,
paragraph
7.
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
R. Church,
Independent
Safety Engineering
Group Chairman
R. Dawson,
Maintenance
Manager
W. Dean, Electrical Maintenance
Department. Head
J.
Dyer, Plant guality Control Hanager
R. Englmeier, Site equality Hanager
H. Fagley,
Construction Services
Hanager
R. Frechette,
Chemistry Supervisor
J. Holt, Plant Licensing Engineer
C. Leppla,
Instrument
and Control Maintenance
Department
Head
L. HcLaughlin, Licensing Manager
G. Hadden,
Plant Licensing Engineer
A. Menocal,
Mechanical
Maintenance
Department
Head
J. Scarola,
Site Engineering
Manager
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. Wunderlich,
Reactor
Engineering Supervisor
Other licensee
employees
contacted
included engineers,
technicians,
operators,
mechanics,
security force members,
and office personnel.
NRC Personnel
- S. Elrod, Senior Resident
Inspector
- H. Scott,
Resident
Inspector
J.
Hoorman,
Senior Licensing Examiner
- Attended exit interview
and initialisms used throughout this report are listed in the
last paragraph.
2.
Plant Status
and Activities
Unit I began
and
ended the inspection period at power.
Power was reduced
for water box cleaning during November
8 - 9 and for a dropped
CEA on
October
22.
The
CEA dropped
due to
a
CEA control timer card failure
during
a routine surveillance
performance.
The unit ended
the period in
day
56 of power operation
since the September
28 turbine startup.
Unit 2 began
the inspection period at full power and
has run at power
since.
There were small
power reductions for a main turbine valve
malfunction that was repaired the
same day.
The unit. ended the period in
day
101 of power operation
since starting
up on August 13.
Operator license requalification examinations
were given from October
26 - November 6.
12 operators
and
12 senior operators
were examined.
The results will be published in Requalification Examination Report
335,389/92-301.
3.
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
'ire
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 that equipment
material conditions
were satisfactory:
Unit 2 EDGs,
Unit 2 4160 buses,
Unit
1 and
2 Startup Transformers,
and
Unit
1 and
2 HPSI pumps.
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 the following
tagouts
(clearances):
2-10-92
Unit 2 Governor Valve ¹4,
9913
Switching order for the return of the
1A and
1B
Startup transformers
-
October 29,
1992,
and
2-6-182
V3540,
shutdown cooling isolation valve.
(1)
On October 22, during
a monthly CEA motion surveillance test
per
OP 1-0110050,
Rev 26, Control
Element Assembly Periodic
Exercise,
Unit
1 had
a dropped
CEA event.
At 8:52 a.m.,
the
first CEA {number 33) selected
in the test
mode slipped
and
then subsequently
dropped.
Operations
appropriately entered
off-normal procedure
ONOP 1-0110030,
Rev 28,
CEA Off-Normal
Operation
and Realignment,
and reduced
power to 70 percent.
The
CEA 33 control timer card
was verified to be failed,
causing the dropped
CEA.
The licensee installed,
tested,
and
adjusted
a replacement
timer card prior to returning the
CEA to
its current group height level.
Operations retrieved the
dropped
CEA without exceeding
associated
TS 3. 1.3. 1 and 3. 1.3.6
time constraints.
CEA testing
was resumed
and satisfactorily
completed
on October 23.
In-House
Event Report 92-068
was
generated
on the event:
(2)
On October
25 at ll:05 p.m., during the performance of a weekly
Unit 2 surveillance test,
an operator inadvertently manually
started
the
2B Containment
Spray
pump.
The operator
had
been
performing
AP 2-0010125,
Containment
Spray Flow Control Valve
Cycling.
The procedure directs the operator to shift the
pump
switch from "Auto" to "Off", cycle the
FCV, then return the
pump switch to "Auto".
The operator
placed the
pump switch in
"Run" vice "Off".
The switch was in the wrong position for
less
than
one second prior to the operator realizing his error
and returning the switch to the. correct position,
however the
pump
had started.
With the associated
FCV in its
normally-closed position,
no water was sprayed into the
containment.
The licensee
found that the episode
was not
reportable
per
-
3 and
The inspectors
agreed with this finding.
The licensee
was pursuing the following corrective actions:
operations
management
counseled *the individual
on the
importance of self-verification of control board actions;
training staff will evaluate
the adequacy of training;
licens1ng staff was generating
information
LER 389-92-007;
a human performance
enhancement
system evaluation is
planned;
and,
AP 2-0010125 will'e revised to enhance
operator action
regarding
switch operations.
The licensee
took this relatively minor problem seriously
and
was following its corrective actions to completion.
On October 26, the licensee
reduced Unit 2 power by about
10
percent to facilitate correction of a main turbine
DEH control
system malfunction.
Governor valve number
4 position began to
oscillate to the point that the
DEH control
system did not
acknowledge
the valve's position.
The control
system shifted
all the governor valves from automatic sequential
operation
mode to automatic single valve operation
mode
as
a fail-safe,
measure.
Reactor
power decreased
40 to 50
MW, which operations
adjusted for without any problems.
In a controlled manner,
operations
reduced
power to about
90 percent to shut the number
4 governor valve and to allow work on the associated
valve
controls.
The
I8C maintenance
group investigated
and found that the
solenoid pilot valve for the number
4 governor
was operating
erratically,
inducing oscillations in the governor valve.
Per
NPWO 0464/64,
ILC replaced
the solenoid pilot valve within
hours of the initial problem.
The reactor
and turbine remained
in operation with the unit output at approximately
90 percent
power.
The
IKC group displayed their competence
during the
replacement.
On November 5,
1992,
in the process of replacing Unit 2 train
"A" main feedwater
RTDs at power, the licensee
discovered
what
appeared
to be
a positive temperature
indication drift or shift
associated
with the old RTDs.
This drift meant that actual
temperature
was lower than previously indicated,
and
thus reactor
power was higher than previously calculated.
The
licensee
replaced five of the six main feedwater
RTDs in both
trains with new calibrated
RTDs of a different brand.
Following RTD replacement
in each train,
power was reduced
(by
8
MWe on 'November
5 and another
6 MWe,on November 6).
The
,
total reduction
was aout 1.6 percent of full power.
Licensee
engineering
evaluation
JPN-SPSL-92-1908
dated
November
16,
1992,
assessed
the as-found
accuracy of the feedwater
RTDs and
concluded that the unit was operating within its licensed
parameters
and that the health
and safet'y of the public were
not affected
by the inaccurate
RTDs.
Pending further inspection this subject will be followed as
389/92-21-06,
Potential
Operation
Above the Licensed
Power
Level.
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
veri fied 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.
Operators
planned sensitive plant evolutions well and responded
correctly
to transients.
One operator error that inadvertently started
a
pump
had minimal plant safety
consequences
but was strongly addressed
by the
licensee.
4.
Surveillance
Observations
(61726)
Various plant operations
were verified to comply with selected
TS
requirements.
Typical of these
were confirmation of TS compliance for
reactor coolant chemistry,
RWT conditions,
containment
pressure,-
control
room ventilation,
and
AC and
DC electrical
sources.
The inspectors
verified that testing
was performed in accordance
with adequate
procedures,
test'nstrumentation
was calibrated,
LCOs were met,
remova'l
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
~
The inspectors
witnessed
the Unit 2 performance of OP 3200051,
Rev
10, At Power Determination of Hoderator Temperature Coefficient,
on
October
29.
TS 4. 1. 1.4.2 requires that
HTC be determined
at several
frequencies
and thermal
power conditions, during each fuel cycle.
The condition being met in this instance
was to perform the test
within 7
EFPD after reaching
a rated thermal
power equilibrium boron
concentration of 800
ppm.
Since this test involved suspending
certain
TS as allowed by TS
4. 1. 1.4.2,
and was considered
an infrequently performed test,
pre-
planning
and pre-briefing were conducted
per AP 0010020,
Rev 2,
Conduct of Infrequently Performed Tests or Evolutions at St. Lucie
Plant.
The briefing by the Operations
Supervisor
was thorough,
including identification of the participants,
conduct .of the test,
expected
plant responses;
criteria for stopping the test,
and
responses
to unexpected
during the test.
The briefing
met all the licensee
requirements
in procedure
Attachment l.
The surveillance test
was performed
smoothly by the operators
and
was witnessed
by th'e reactor engineer,
assisted
by the
STA.
TS
suspensions
were logged
and the action statements
followed.
The
completed test procedure
was also reviewed
by the inspector.
HTC,
found to be -10.0586
pcm/degree
F,
was within TS limits of +3 to -30
pcm/degree
F.
The inspector
had
no further questions.
b.
OP 1-2200050B,
Rev 3,
1B Emergency Diesel
Generator
Periodic Test
and General
Operating Instruction
V
c.
OP 1-0910023,
Rev 4, Transfer Electrical Alignment on the 4160 Volt
lAB and
480 Volt Loads
d.
IEC 2-1400050,
Rev 23, Reactor Protection
System Honthly Functional
Test
N
All surveillances
were competently performed in a timely manner.
5.
Haintenance
Observation
(62703)
Station maintenance
activities involving selected
safety-related
systems
and components
were observed
or 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:
'
a.
NPWO 7839/63
- Replace
"B3" power supply socket in the "B" channel
of Unit
1
RPS for Low Flow trip function.
b.
NPWO 5756/65
- Troubleshoot
and replace if required the motor to
Unit
1
HV 08-03,
1C
AFW steam
admission valve.
c.
NPWO 5586/66
- Inspect motor leads in electrical
connection
box of
the Unit 2 2A LPSI motor.
This
NPWO controlled the inspection of the
2A LPSI
pump motor cable
to motor lead electrical
connection.
The joint met the requirements
of FCR 2-4099E.
This
FCR along with FCRs
on certain other motor
l.ead connections
were not added to the operating
drawings during
plant construction,
which was typical of the level of detail during
that time frame.
The licensee
was considering
incorporating the
older group of FCRs into their design basis to assist
in maintenance
performance
and to increase
the level of detail in the design basis.
d.
NPWO 9235/64
-
HCV 09-lA Accumulator Schrader
Valve Repair.
A leaking Unit 2 HFIV nitrogen accumulator valve placed the HFIV in
an
LCO on November
15.
The leak was repaired prior to exceeding
the
4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />
LCO time limit.
e.
NPWO 0556/64
-
HCV 09-2B Accumulator tubing/fitting repair.
This Unit 2
NPWO contro'lied the repair of a slow leak in a nitrogen
tubing to fitting joint.
The repairs did not require entry into an
LCO.
Subsequent
surveillance testing of the HFIV required
LCO
entry.
Repair efforts were well planned
and professional.
The
engineering division supported this repair by allowing the use of
TFf thread sealing tape in this location which provided
a positive
seal for this application.
The above maintenance
activities were carried out'atisfactorily.
The
Unit 2 HFIV (valve style not installed
on Unit 1) work did not indicate
preventive maintenance
problems.
6.
Fire Protection
Review (64704)
During the course of their normal tours,
the inspectors routinely
examined facets of the Fire Protection
Program.
The inspectors
reviewed
transient fire loads,
flammable materials
storage,
housekeeping,
control
of hazardous
chemicals,
ignition source/fire risk reduction efforts,
and
Fire protection efforts for this period were satisfactory.
A new service
building fire main branch
was partially connected
with the existing plant
system.
Compensatory
measures
were highly visible during this connection
activity.
7.
Review of Periodic
and Special
Reports
(90713)
(Closed
- Unit 1)
FPL Special
Report L-92-217, dated July 27,
1992.
This special
report per
TS 4.8..1.1.3 discussed'a
non-valid failure of the
, 1A EDG on July 1.
The
EDG faile'd to continue operating during
a test
because
a coolant temperature
switch indicated
a high engine temperature.
The switch was replaced
and the
EDG satisfactorily tested.,
The licensee
evaluated that the switch would be bypassed
during emergency
operation of
the
EDG, therefore
would not prevent
a safety function from occurring.
The inspector
agreed with the licensee's
evaluation.
This was discussed
in IR 335/92-11,
paragraph
4.n.
TS 4.8. 1. 1.3 required reports of EDG failures to address
the items
recommended
in regulatory position C.3.b of RG 1. 108,
Rev 1, August,
1977.
This report addressed
all the items except
item (6) "define the
current surveillance test interval."
The licensee
is submitting
a
revised report.
There
was
no safety significance to this oversight.
This violation of TS 4.8. 1. 1.3 is not being cited because it was
an
isolated
case of low safety significance
and the licensee's
efforts in
correcting the violation met the criteria specified in Section VII.b of
the enforcement policy.
This oversight is identified as. closed
NCV 389/92-21-05,
Incomplete
Technical Specification Special
Report.
8.
Onsite Followup of Written Nonroutine Event Reports
(Units
1 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
(Closed)
Low Temperature
Overpressure
Protection
[LTOP] Setpoint
Helow Technical Specification Limit Due to Personnel
Error.
This
LER reported
a licensee-identified violation of TS 3.4. 13.
While reviewing
an implementing'rocedure
change for LTOP TS
amendment
104, the licensee,
in error,
made
a non-conservative
additional
change to the
new setpoint values
being implemented.
This error existed for less
than
a month.
This
TS change
was
intended to cover operation
between
10 and
15
EFPY.
The plant had
not yet, reached
10
EFPY during this time and operations
were found
to be within the approved
5 -
10
EFPY parameters.
The licensee
completed
the corrective actions stated
in the
LER
within the time limits discussed.
The appropriate
implementing
procedures
were corrected
'and administrative
documents
were changed.
Though Unit 2 was not directly effected, its
LTOP setpoints
were
found to be satisfactory.
This
LER is closed.
This violation is not being cited because
the licensee's
efforts in
identifying and correcting the violation met the criteria specified
in Section VII.b of the enforcement policy.
This event is identified as closed
NCV 335/92-21-01,
LTOP Technical
Specification
Amendment
Implementation Failure.
(Closed)
Inadvertent Actuation of Reactor
Protection
System During Mode
3 Testing
Due to Personnel
Error.
With all
CEAs inserted into the core except
one undergoing testing,
and with one Nuclear Instrument
(NI) channel
in "trip" (needed
repair),
an operator selected
the wrong trip test potentiometer
on
the other NI channel
and caused
a reactor trip.
All safety
functions were already satisfied prior to the trip.
No TS
violations were identified.
All corrective actions of the
LER were completed.
Self verification
has
been
a subject for operator training and is revisited
periodically per the routine inspection
program.
The tripped NI
that required repair
was repaired
and is in service.
Based
on the
completion of corrective actions, this
LER is closed.
(Closed
- Unit 1)
a
Turbine Generator
Loss of Load Signal
due to Equipment Failure.
This
LER addressed
a reactor trip occurring
on September
24,
1992.
The event
was fully discussed
in IR 335,389/92-20,
paragraph
3.a.(4).
The
LER accurately
described
the event.
This
LER is
closed.
(Closed
- Unit 2) .LER 389/90-02,
480
VAC Bus Degraded
Voltage Relay
Setpoint
Below Technical Specification
Minimum Due to design Error.
This
LER reported
a licensee-identified violation of TS 3/4.3.2
and
Table 3.3-4.
While performing
a design
change
review on July 13,
1990,
the licensee
found
a slightly non-conservative
difference in
setpoints for 480
VAC emergency
bus degraded
voltage relays.
The
setpoints
provided
by engineering for use in 1983 were 89.3 percent
of rated voltage
as
opposed
to 90 percent
subsequently
established
by a
TS amendment.
The existing condition was evaluated
by the
licensee to be still bounded
by the existing engineering
safety
analysis.
The licensee
completed corrective actions stated
in the
LER,
including reviews of other setpoints
on both- reactor units.
The
quality control group, corporate
engineering,
and the technical-
support staff performed the reviews.
The quality assurance
staff
audited the set point reviews (report 90-782),
concluding that the
=-
process
was completed.
Aside from the
some additional
checks that
were performed,
the reviews revealed
no additional
problems.
Based
10
on the licensee's
corrective action,
the limited severity of the
problem,
and the isolated nature of the problem. This
LER is closed.
This violation is not being cited because
the licensee's.efforts
in
identifying and correcting the violation met the criteria specified
in Section VII.b of the enForcement
policy.
This issue is identified as closed
NCV 389/92-21-02,
Failure to
Implement
New TS Requirements
for Emergency
Bus Undervoltage.
(Closed
- Uhit 2)
on
a Radiation
Monitor Being Returned to Service
Due to Personnel
Error.
This
LER reported
a licensee-identified violation of TS 4.3.3. 1,
which required the "B" main steam line radiation monitor receive
a
post-maintenance
channel calibration
and channel
functional test
prior to being returned to service.
The monitor was released
for
service
on July 25,
1990, following a power supply repair without
being calibrated
and functionally tested.
The event
was primarily a personnel
error but contributing causes
were department
interfaces.
IEC planners
prepare
the work order,
IEC technicians
repair the instrument,
the chemistry department
tests it, and operators
place it in and out of service.
Procedure
gI ll-PR/PSL-4, Instrumentation
and Control Test Control,
was
upgraded
in Rev 25, section
5.4
and Appendix
B (the required testing
matrix) to direct coordination with the chemistry department prior
to releasing
monitors for service.
This violation is not being cited because
the licensee's
efforts in
identifying and correcting the violation met the criteria specified
in Section VII.b of the enforcement policy.
This event is identified as closed
NCV 389/92-21-03,
Hissed
Surveillance
on
a Radiation Monitor Being Returned to Service
Due to
Personnel
Error.
This
LER is closed.
(Closed
- Unit P)
Inadvertent Actuation of Engineered
Safeguards
Equipment During Time Response
Testing
Due to Personnel
Error.
This
LER reported
a personnel
error in that
a technician
pushed
an
incorrect
push button during
a safeguards
test.
The event
was
discussed
in IR 389/90-28,
paragraph
2.b.
Operators,
having
been
pre-briefed,
recognized that the wrong equipment
had actuated
and
terminated
the test,
realigned
equipment,
and verified plant
conditions.
No plant damage
had occurred.
Other corrective actions
included
a human factors review and
a control
room design review in
the area.
The inspector
had
no further questions.
This
LER is
closed.
.11
(Closed
- Unit 2)
Inadvertent Actuation of Auxiliary
Equipment During,Monthly Testing
Due to Test Instrument
Malfunction.
This
LER reported
an instance
where
2B and
2C
AFW pumps started
when
not supposed
to during the
AFAS monthly functional test..
The
licensee
found that the condition was caused
by an intermittent
grounding fault inside the test meter case.
Though the vendor did
not specify use of an ungrounded
meter,
the licensee
changed
the
applicable
procedure to require it.
The inspector
reviewed
procedures
1-0700051,
Rev 12,
and 2-0700051,
Rev 15, Auxiliary
Feedwater Actuation System Monthly Functional Test.
They had both
been
changed to require in Section 8, Materials
and Equipment
Required,
that
a battery-powered digital multimeter
be used.
- This
LER is closed.
(Closed
- Unit 2)
Missed Surveillance for Safety
Injection Tank Wa'ter Level
and Pressure
Channel
Functional
Test
due
to personnel
error.
This
LER reported
a licensee-identified violation of TS 4.5. 1.2.a.
The licensee
discovered
a missed monthly functional check
surveillance'our
days after the
25 percent
grace time had expired.
They promptly performed the functional check with a satisfactory
result.
The licensee
followed up this event in CAR N-91-074.
The
root cause
was found to be personnel
error but
a strong contributor
was the scheduling
program not providing for system supervisors
to
be absent
and not providing for a positive check that the
surveillance
was actually performed.
The inspector
checked
procedure
1400190,
Rev 8,- I'&C Department Testing
and Surveillance
Schedule,
and found that the scheduling
form had
been modified to
address
alternate
supervisors
and confirmation that each test
had
been
completed.
The current schedule
was posted
in the hall where
I&C supervisors'ffices
were located
and was obviously in use.
This violation is not being cited because
the licensee's
efforts in
identifying and correcting the violation met the criteria specified
in Section VII.b of the-enforcement
policy.
This event is identified as closed
NCV 389/92-21-04,
Missed
Technical Specification Surveillance.
This
LER is closed.
(Closed,- Unit 2)
Containment
High Pressure
Channel
"C" Inoperable
due to being capped.
I
This event
was cited
as
a violation of NRC requirements
in IR
389/92-07
and was reported
by this .LER.
The
LER was timely and
properly characterized
the event.
The event is being followed up
under
VIO 389/92-07-03.
This
LER is closed.
(Closed
- Unit 2)
Manual Trip .Due to Low "A" Steam
Generator
Level.
12
This event occurred
on July 8,
1992,
and was discussed
in IR
335,389/92-11.
The
LER accurately reported the event.
This
LER is
closed.
(Closed
- Unit 1)
Unplanned Actuation of Auxiliary
System
Components
Due to Personnel
Error While
Troubleshooting
a Problem Discovered
During Monthly Surveillance.
While troubleshooting
at
100 percent reactor
power,
a technician
pulled the wrong fuse in the AFAS channel
"D" cabinet
and started
the
1C
AFW pump.
Both the steam
admission
and trip/throttle valves
opened.
No water was injected into the steam generators.
The licensee
found the major contributor to the error was that the
vendor manuals
were unclear concerning
the types
and locations of
various fuses.
The inspectors
reviewed the licensee
actions listed
in the
LER.
The changes
to the applicable
AFAS technical
manuals
clarified the types
and locations of fuses in the cabinet.
All
other licensee
actions
were completed.
No TS or procedures
had
been
violated
and
no other systems
had
been effected.
This
LER is
closed.
'l.
(Closed
- Unit 1)
Diesel
Generators
Administratively
Declared
Out of Service
Because
of Particulate
Contamination
in the
Diesel
Fuel Oil Due to Procedure
Deficiencies.
This
LER reported
a licensee-identified
violation of TS 4.8. l. 1.2.d
involving the failure to correctly identify or employ
a chemical
reagent
used in
EDG fuel oil particulate determination.
A
particulate-contaminated
fuel oil shipment
was not detected,
was
introduced into the site's fuel oil storage
system,
and resulted
in
technical
inoperability of three of four fuel oil storage
tanks
and
EDGs.
This event
was cited as
a violation of NRC requirements
in IR
335,389/91-22,
VIO 91-22-01.
See also paragraph ll.j of this
report.
The corrective actions stated
in the
LER text have
been completed.
The inspectors
have observed all phases
of fuel oil sampling,
filtration, and onsite analytical testing.
The inspectors
judged
that the licensee's
actions
should reduce the probability of
recurrence.
This
LER is closed.
Licensee corrective action completion for the
above
LERs was
satisfactory.
9.
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.
13
Licensee followup of events
discussed
in paragraph
2 was
seen
as timely
and effective.
Followup of Unresolved
Items (Units
1 and 2)
(92701)
(CLOSED - Units
1 and 2)
URI 335,389/91-16-01,
Containment Integrity.
This issue
was unresolved
pending further
NRC review.
The issue
has
subsequently
been reviewed
by the
NRC staff at both Region II and
Headquarters.
NRC review concluded that the licensee
had violated
NRC
requirements
in this area
as described
below.
This URI is
administratively closed.
This URI addressed
a condition occurring
on July =30,
1991.
The licensee
had initiated the Reactor Auxiliary Building Fluid Systems
Periodic
Leak
Test
on containment
spray train "A" per
OP 1-1300054,
Rev 15,
same title.
This procedure essentially
isolated the
CS system at the containment
operated
the
pump via recirculation to the Refueling
Water Tank to pressurize
the system,
which would then
be inspected for
leaks;
then restored
the system to the normal configuration.
The-
procedure
referenced
Primary Coolant Sources
Outside
Containment,
as the basic requirement
being met by the test.
Other
TS
LCOs that would be entered
were not referenced.
The procedure
required that
CS drain valve I-V07163, located in the
Auxiliary Building on the containment
vessel
side of test
boundary valve
I-MV-07-3A, be opened
and all water drained
from the spray
header prior
to starting the
CS pump.
This was to ensure that test
boundary valve
leakage
was detected
promptly to preclude
spraying the containment.
Valve I-V07163 was partially opened
and
had drained water for about three
hours
when the inspector questioned
the licensee's
compliance with TS 3.6. 1. 1.
TS 3.6. 1. 1 required that containment vessel'ntegrity
be
maintained in modes .1, 2, 3,
and 4.
This specification's
action
statement
required that, if without containment
vessel
integrity, then
containment
vessel
integrity must
be restored within one hour or the unit
be in Hot Standby within the next six hours.
When notified of the
concern,
the licensee
promptly shut the valve then restored
the
CS system
to the normal configuration while reconsidering
the test.
The inspector
considered
that the
TS 3.6. 1. 1 action statement
was inadvertently entered
but not exceeded
because
a normal unit shutdown could be accomplished
within the four hours remaining in the action statement.
After due consideration,
the licensee
stated that they had not actually
been in TS
LCO Action Statement
3.6. 1. 1, Containment
Vessel Integrity,
because:
The only valves involved in containment
vessel
integrity were those
identified by number in the
TS or perhaps
the
The licensee
stated that they believed that the
NRC had previously considered
the
situation
when the facility license
was issued
and,
by not
'pecifically
identifying in the
TS the vent
and drain valves or
other fittings, had determined
them to be too small to be
considered.
The licensee specifically stated that all vent, drain,
and test valves
and fittings located in the containment penetration
areas
were not required to be secured
in position
and were not
required to be surveillance
checked at least
once per
31 days per
Additionally, during the
ILRT, the containment
spray check valve
and
flow control valve had
been tested
as
a pair using
ILRT pressure.
[These valves were not separately
tested.
The drain valve in
question
was between
them.]
Subsequent
NRC staff review and onsite inspection
found that:
The essential
element of CONTAINMENT VESSEL INTEGRITY, that was not
adequately
maintained
(as defined in TS definition 1.7),
was
as
follows:
CONTAINMENT VESSEL
INTEGRITY shall exist when:
a.
All containment
vessel
penetrations required to be closed
during accident conditions
are either:
1.
Capable of being closed
by an
OPERABLE containment
automatic isolation valve system,
or-
2.
Closed
by manual
valves,
blind flanges,
or
deactivated
automatic valves
secured
in their closed
positions,
except
as provided in Table 3.6-2 of
'pecification
3.6.3.1 (for Unit 1) or Specification
3.6.3 (for Unit 2).
Per the
10 CFR 50 Appendix A requirements
for containment isolation,
the area
between
the first automatic
or locked isolation valve
outside containment
and the first automatic or locked isolation
valve inside containment
in a line penetrating
containment is
included in the design basis for containment
vessel
integrity.
and 4.6.1.1 apply.
CS drain valve I-V07163 was in the section of pipe included in
containment
vessel
integrity: it drained the
CS line (that
penetrated
containment)
between
the first automatic isolation valve
inside containment
(a check valve)
and the first automatic isolation
valve outside containment.
CS drain'alve
I-V07163 was
a manual
one-inch valve,
was the only valve or isolation device in the drain
line,
and drained to the floor in the Containment
Room
in the Auxiliary Building.
The valve had
no mechanical
device to
. seal
or lock it closed.
Other similar containment penetration
vent,
drain,
and test valves in Unit
1 and Unit 2 also
had
no mechanical
devices to seal
or lock them closed.
10CFR Part 50, Appendix J, defined
a containment isolation valve
as
any valve which is relied
upon to perform
a containment isolation
15
function.
The
NRC staff considered
any valve which isolates
a
containment penetration,
no matter
how small, to be
a containment
isolation valve and that therefore
CS drain valve I-V07163 was
a
containment isolation valve and
TS 3.6. 1. 1 and 4.6. 1. 1 applied.
TS 4.6. 1. l.required that
CONTAINMENT VESSEL
INTEGRITY be
demonstrated
at least
once per 31 days
by verifying, in part, that
all containment
vessel
not capable of being closed
by
'PERABLE containment
automatic isolation valves
and required to be
closed during accident conditions are closed
by valves, blind
or deactivated
automatic valves
secured
in their closed
positions,
except for those inside Unit
1 containment
or listed in a
certain
TS table.
"Secured
in their positions" in the't Lucie TS applied to manual
valves,
blind flanges,
and deactivated
automatic valves.
Standard
Review Plan section 6.2.4,
Containment Isolation System, referring
to closed
manual
valves, blind flanges,
and deactivated
automatic
valves,
equated
"secured
in their position"
and "sealed closed".
These
items should
be under "administrative control" to ensure that
they could not be inadvertently
opened.
Administrative control
includes
mechanical
devices to seal
or lock the fitting closed,
or
prevent
power from being supplied to the valve operator.
The licensee failed to maintain
CONTAINMENT VESSEL
INTEGRITY prior
to November 23,
1992,
in that Containment
Spray drain valve I-V07163
and other non-automatic
containment
vessel
closure
devices
in both units,
such
as
manual
valves or blind flanges,
while
closed,
were not secured
in their closed positions
as required.
They were not secured
in that there
were
no mechanical
devices to
seal
or lock them closed.
During this time, Units
1 and
2 were
operated
in Mode 1.
The licensee failed to implement the
31 day surveillance
requirement
of Unit
1
and Unit 2 TS 4.6. 1. 1 prior to November 23,
1992.
The
licensee
had
no procedures
to implement the check of all the vent,
drain,
and test valves being secured
in their closed positions.
Additionally, the licensee
had
no approved
complete list of
containment
vessel
penetration fittings and
had
no approved
complete
containment
vessel
boundary drawings suitable for
developing
such procedures.
Incomplete listings did exist.
Many
major valves were listed in TS Table 3.5.2,
Containment Isolation
Valves,
and the Unit 2 UFSAR had sketches
showing the local leak
rate test alignments.
The Unit 2 UFSAR sketches
also included in-
l'ine valves oth'er than isolation valves with no differentiation
between
the two categories,
Implementing procedures,
including surveillance
procedures
AP 1-
0010125,
Rev 87,
and 2-0010125,
Rev 40,
and associated
1-
0010125A
and 2-0010125A did not include the vent, drain,
and test
'alves.
16
Standard
Review Plan section 6.2.6,
Containment
Leakage Testing,
regarding leak testing of vent, drain,
and test valves,
states
that
... test,
vent,
and drain connections that are
used to 'facilitate
local leak testing
and the performance of the containment
integrated
leak rate test should
be under administrative control,
and should
be
subject to periodic surveillance,
to assure their integrity and
verify the effectiveness
of administrative controls.
This system
had
a Class
per
UFSAR Section 6.2.4.2,
Containment Isolation System Design.
Class
E was for lines designed
to be open following a
LOCA to mitigate the effects of the, accident.
They were to have either:
a 0
b.
a check valve in series with a remote manually actuated
valve, or
a remote manually actuated
valve or check valve and
a closed
seismic
Class
I system outside containment.
The
CS system
was
a closed Seismic Class
I system outside
containment with a check valve inside containment.
Opening drain
valve I-V07163 in the containment penetration
area did not meet the
"closed seismic
Class
I system" part of the requirement.
Failure to implement
TS 3.6. 1. 1 and 4.6. 1. 1 is
a violation, VIO
335,389/92-21-07,
Failure to Adequately Maintain Containment
Vessel
Integrity.
ll.
Foll'owup of Headquarters
and Regional
Requests
(Units
1 and 2)
(92701)
a
0
(Open
- Unit 1, Closed
- Unit 2) 335,389/P21-90-005,
Broken Swing
Arms for Check Valves.
This
10 CFR 21 Report concerned
broken cast
swing arms for Borg-
Warner Co. pressure
seal
type check valves.
The swing arms
exhibited hot cracks,
porosity, weld repair,
and inadequate
heat
treatment.
They were manufactured for nuclear service
and were not
commercial
grade
items subsequently
dedicated for nuclear service.
These valves were installed in the
AFW system at another plant.
The St.
Lucie plant was listed
as possibly having
some of these
items.
FPL reviewed this concern
under feedback of operating
experience
program FOP-90-023.
Eight valves were originally identified, four
in Unit
1 and four in Unit 2.
Three were inspected
using visual
and
dye penetrant
techniques
as 'follows:
.
UNIT
.
VALVE
gCIR NO.
RESULTS
1
V-07269
M91-735
SATISFACTORY
1'-07270
M91-736
SATISFACTORY
0
17
b.
C.
V-3215
35612
SATISFACTORY - the swing arm was
stainless
steel
vice the material
described
in the
10 CFR 21 report.
Following the recognition that the Unit 2 valves did not actually
fit the
10 CFR 21 report description,
the licensee
canceled further
inspections
on Unit 2 valves V-3225, 3235,
and 3245.
Unit
1
V-12174
and V-12176 are scheduled for inspection during
the Spring,
1993, refueling outage
per
NPWO 3640/61.
This item is
closed for Unit 2 but remains
open for Unit
1 pending the licensee
completing the inspections.
(Closed - Units
1 and 2) 335,389/P21-91-006,
Trip Tappets
for Terry Steam Turbine
Pump Drivers.
This
10 CFR 21 Report addressed
a condition where the "molded head"
type overspeed trip tappet
heads
swelled under high temperature
and
humidity, then
bound
up because
of the loss of clearance
between
the
head
and
a guide.
A redesigned
tappet incorporated
a metal
guided
surface
and greater clearance.
St.
Lucie Units
1 and
2 each
have
a
Terry turbine in the
AFW system.
The licensee
addressed
this issue
under feedback of operating
experience
program FOP-89-143.
The older model tappets
were
replaced
per Unit
1
NPWO 2351/61,
completed
October 21,
1991,
and
Unit 2
NPWO 1592/62,
completed
June
13,
1992.
The inspector
reviewed the
NPWO records
and confirmed that the spare
tappets
held
in stores
were changed
to the
new part.
This item is closed.
The inspectors
responded
to
a
NRC Region II survey request
received
on November 2.
The survey purpose
was to assess
the effectiveness
of QA organizations.
The survey areas
included the
QA organization,
program, relationship to other .assessment
organizations
such
as
ISEG,
CNRB, etc.,
and effectiveness.
The survey
was returned
on
November 3,
as required.
The above Part
21 Reports
(items a.
and b.) were satisfactorily followed
by the licensee.
12.
Followup of Corrective Actions for Violations and Deviations
(Units
1 and 2)(92702)
a 0
(Closed
- Units
1 and 2)
VIO 335,389/90-13-01,
Failure to Ensure
Quality at Least Equivalent to That Specified in the Original Design
Basis or Requirements
- Three
Examples.
adequately
to this Notice of
Violation.
(1)
The Unit
1 containment
maintenance
hatch drawbridge
was being
supported
in its stowed position
by
a chainfall vice the
required seismically designed
bolted angle supports.
18
The licensee
changed
GMP M-0311 to identify r'emoval
and
replacement
nf the drawbridge bracing during opening
and
closing of the containment
equipment hatch.
Subsequently,
the
inspectors
have witnessed
both Unit
1 and
2 drawbridges
being
properly positioned
on several'occasions
(2)
When unable to find approved
mounting detail drawings for
hydrogen sampling system containment isolation solenoid valves,
the
shop engineers
informally designed
and installed
significantly different
mountings'he
licensee
addressed
the personnel
error involved here
and
also determined that the installation detail
dt awing did not
'adequately reflect
a modified mounting configuration resulting
from a
PCM.
The inspector
reviewed drawing 8770-8-231,
sheet
27-2,
Rev 7, Instrument Installation Details,
which now
included the mounting details for the seven
containment
isolation valves.
Subsequent
to this violation, the inspectors
.
have inspected field conditions several
times prior to
containment closure.
The valves
have
been
mounted per the
drawing.
(3)
The licensee
used
carbon steel
nuts
on the
1A
ICW pump
casing-to-pump stuffing box joint vice the specified
316
stainless
steel
nuts.
In addition,
a single rubber gasket,
vice the required
f1 a'nge insulation kit, was installed
on
a
safety-related
lubricating water flanged joint'.
These
were found to be personnel errors'n
addition to
counseling
and correcting the specific problems,
the licensee
also verified fastener
hardware
on
a random selection of 11-
safety-related
valves
and
5 safety-related
pumps to see if the
fastener
problem was wide spread.
gC/PSL
LTR BK No.
196, dated
July 16,
1990,
and attached
gC Report
32006 documented
satisfactory 'conditions.
The licensee
also
changed
the
material control
program to add increased
accountability
and
responsibility..at the foreman/supervisor
levels
Based
on the inspecto'r's
review of the licensee's
corrective
actions, this item is closed'
b.
(Closed
- Units
1 and
2)
VIO 335,389/90-23-01,
Failure to Control
Material in Safety-Related
Repairs.
This violation involved two examples of failing to control- materials
used for 'safety-related repairs'ne
example
was the use of
unapproved
replacement
wire material
during
a
RPS selector
switch
replacements
The other example
was the use of an unapproved
sealant
on
a mechanical
seal. leak.
to the Notice of Violation.
The two.
items were evaluated
by engineering
and judged acceptable,
however
19
the wire was replaced with vendor-recommended
wire anyway.
The
licensee
determined that these
items,
along with VIO 335,389/90-30-
'lc, were
symptoms of a more fundamental
condition.
The maintenance
manager
issued
an interim letter describing the requirements.
Specific confirmation that all maintenance
personnel
reviewed this
letter was observed
by the inspector.
Subsequent
permanent
action
included:
gI 8-PR/PSL-l,
Rev 17, Identification Control of Haterials,
Parts,
and Components,
established
the licensee's
plan for
controlling material
used in the plant.
This incorporated
the
material
contained
in the maintenance
manager's initial letter.
AP 0010432,
Rev 62, Nuclear Plant
Work Orders,
provided
specific accountability
and direction to foremen/supervisors
concerning materials
used
on
a job.
These
program changes
appear to be effective.
This item is closed.
{Closed - Unit 2)
NCV 389/90-31-01,
Use of Unapproved
Procedures
for
PH of 2C
AFW Pump Governor.
This
NCV involved
a
PH that had not been
FRG approved
several
months
before.
The procedure
was subsequently
approved
and
a revision
has
'ince
been
FRG approved
and issued.
The licensee
also
has
changed
the corrective action request
system to adjust for a company
reorganization.
The inspectors
have frequently interfaced with the
current corrective action request
system
and found it to function
very well.
This item is closed.
(Closed
- Unit.1) VIO 335/91-22-02,
Loss of Containment Integrity
During Refueling.
This licensee-identified violation of TS 3.9.4.c.
involved the
issuance
of a "clearance" for work on
a
CCW relief valve inside
containment
[meaning that the system
was safe to work on] but not
issuing the
NPWO authorizing the start of work.
Unit
1 was being
refueled at the time.
Shop personnel,
thinking that they had
permission,
removed the valve.
This opened
a small flow path into
containment,
violating the refueling TS.
Licensee letter L-92-36 responded
to the Notice of Violation.
In
addition to counseling,
discussion
during training, etc,
the
licensee
changed
the equipment clearance
form per
OP 0010122,
Rev
51,
In Plant Equipment Clearance
Orders,
to require
by checkoff,
specific safety review for several
considerations,
such
as system
redundancy,
sensitive
system status,
mode related or not,
and
containment penetration.
The inspector
concluded that this highly
visible focus will improve coordinated
work control
and strengthen
the procedural
bar riers.
This item is closed.
20
e.
(Closed
- Unit 1) VIO 335/91-22-03,
Failure to Haintain
RCS In-
Process
Cleanliness
Controls.
This licensee-identified violation of Unit
1 TS 3.4.7 involved the
failure to control the quality of water used
by
a diver while high
pressure
water jet cleaning the reactor vessel
Domestic
water was used,
introducing into the
exceeding
the
TS
limit of 150 ppb.
Licensee letter L-92-56 responded
to the Notice of Violation.
In
addition to restoring the
RCS to proper chemistry conditions
and
performing
an engineering
evaluation of the consequences,
the
licensee
concluded that the cleaning evolution was inadequately
controlled
and, took several
steps to improve controls:
Since part of the root cause
involved connecting
the hose to
a
domestic water connection vice
a demineralized
water
connection, i.e., recognizing the correct system,
the licensee
added placards to the point of application,
the service
(domestic)
water hose connections,
warning that the water
cannot
be introduced internally into certain
named
systems,
and
neither internally nor externally into certain other
named
systems.
Additionally, placards
were
made for demineralized
and primary water systems stating that the water cannot
be
added to borated water
systems without specific permission.
Also, primary water placards
stated that it was radioactively
contaminated.
The inspector
has
observed
a number of these
placards installed about the plant.
The licensee shifted high pressure
water blasting inside
containment
from a "skill of the trade" activity to one
proceduralized
by GHP-06,
Rev 0, High Pressure
Water Blasting
Inside th'e Reactor
Containment Building.
While the procedure
has safety precautions
and communications
options, it focuses
on discussion with operations
concerning
proposed
water sources
prior to water blasting.
The licensee
changed
the Unit
1 and Unit 2 reactor vessel
maintenance
sequence
procedures
to include specific notes
at
the appropriate
locations to invoke the maintenance
procedure
for high pressure
water blasting.
The inspector
reviewed
procedures
1-H-0015,
Rev 21,
and 2-H-0036,
Rev 13, both titled
Reactor
Vessel
Haintenance
- Sequence
of Operations,
and found
the notes appropriate.
The inspector judged that these
upgrades will decrease
the
likelihood of this event repeating.
This item is closed.
f.
(Closed
- Unit 1) VIO 335/92-04-01,
Failure to Properly Store
Flammable Hateri als.
21
This violation involved alcohol being stored in plastic containers,
in a crew box, in a safety-related
electrical
equipment
room.
FPL responded
to this violation in letter L-92-99 and supplemented
the response
in letter L-92-125.
The licensee
immediately removed
the flammable material to an authorized
area
and stored it in safety
cans
in a flame-proof cabinet.
They then inspected
other crew boxes
and work areas,
found several
additional
examples,
and corrected
them.
The inspector'bserved
these activities in progress
at the
time.
The licensee
took a number of steps to prevent further
noncompliance,
including:
Following a staff survey to determine needs,'he
licensee
procured
about
50 flammable storage
cabinets for use throughout
the site.
Added standard
service contract requirements
that contractors
must obtain
a flammable storage
cabinet for any flammable
products they
use.'rovided
for crew box identification and for access
to all crew
boxes
by the fire and safety inspectors.
Added inspection of crew boxes to the fire equipment
and
systems
inspection check-off sheet.
Addressed
storage of flammable material
in at least the safety
meetings
on June
11, July 17,
and August 13,
1992.
gCIR IE92-810 documented
a
gC surveillance of the site chemical
control
program (including flammable storage)
on August 27,
1992.
The
gC inspector
found the large
number of areas
~inspected satisfactory.
The inspector
has monitored these
changes
throughout the period
subsequent
to the violation and has also toured the area with the
fire inspectors.
The inspector
concludes that the licensee
has
been
very responsive
to the Notice of Violation and that the flammable
storage.
program is much improved.
This item is closed.
g.
(Open
- Unit 2) VIO 389/92-07-03,
Isolation of Containment
Pressure
Sensing
Line Without Placing Effected Instrumentation
Channels
in
TRIP or BYPASS.
This violation involved the inadvertent
capping of a small
instrument line inside containment.
.Since it was not planned,
the
licensee
did not take actions to place affected instrumentation
in
BYPASS 'or TRIP.
The inspector
had identified several
contributors
i.ncluding:
Lack of plain identification of the tubing stubs sticking into
containment.
'2
Lack of protection of the open tubing ends to prevent insect
entry or the insertion of debris.
The exposed
threads
on the tubing ends inviting the
installation of a cap.
Lack of periodic surveillance to demonstrate
clear passage
through atmospheric
sensing tubing.
Lack of a check prior to entering
a mode where atmospheric
sensing
is required.
to the Notice of Violatiori.
In
addition to the licensee
removing the cap,
the licensee
evaluated
the maintenance
and operating history, performed
a
PRA,
and
performed
an engineering
analysis.
Since the system is
a "2 of 4
channel
to operate"
system,
the inspector concurred with the
licensee's
finding,that the safety significance of capping
one line
was small.
h
Other corrective actions
included the following:
The inspector
observed
the licensee
performing
a pressurized
air test of all other Unit
1 and Unit 2 containment
pressure
transmitter
sensing lines
on Hay 7,
1992,
per Unit
1
NPWO
7340/63
and Unit 2
NPWO 7452/64.
The inspector also observed
the initial performance of ILC
Procedure
1400205,
Rev 0,
on Unit 2 per
NPWO 8158/64.
This
initial performance
was receiving full-time jobsite supervision
by an
I&C supervisor.
The supervisor properly stopped
the work
twice to correct procedure errors with temporary
changes
prior
to proceeding.
The licensee installed
mud dauber
caps
on Unit 2 sensing lines
per
NPWO 7613/64
and
PCH 157-292M.
The inspector confirmed
their presence
du}ing a containment
inspection prior to Unit 2
entering
Mode
4 on June
21,
1992.
The inspector
observed
the sensing line labels
added inside
Unit 2 containment during
a containment
inspection prior to
Unit 2 entering
Mode
4 on June
21,
1992.
The licensee
changed
AP 0010728,
Post" Outage
Review, Section
8.3,
Mode
4 prerequisites,
to require
an
I&C signature that
Procedure
1400205 is completed prior to entering
mode
4 during
a startup.
The inspector
observed this in procedure revision 9.
Items remaining to be inspected
are:
Drawing changes for both Unit
1 and 2.
23
Mud dauber
cap installation for Unit
1 during the Spring,
1993,
refueling.
Tagging of Unit
during the Spring,
1993,
outage.
Performance
of IEC 1400205
on Unit
1 during the Spring,
1993,
outage.
Corrective action to" date is adequate,
however this item remains
open pending review of drawings
and Unit
1 items.
h.
(Closed
- Unit 2) VIO 389/92-07-04,
Failure to Follow the Procedure
for Setting
Safety Valves.
This
TS violation involved the use of gages with inadequate
accuracy
to set
SG code safety valves,.
The two gages
were both labeled
as
being outside the procedural
requirements,
-which was not questioned,
and
one
was actually outside the procedural
requirements.
to this Notice of Violation.
Immediate corrective action included obtaining proper gages,
repeating
the testing already
accomplished,
and then completing the
setting in the required
manner.
This was verified by the inspector
at the time.
Additional-corrective action
was
based
on the licensee
recognizing
that they
had confused
the gage accuracy
requirements
for setting
code safety valves to +/-
1 percent of the setpoint with the less
stringent
accuracy
requirements
for pump
and valve testing.
additional corrective aetio'ns
included:
Procedure
GNP-0705
was revised to clarify accuracy
requirements,
place the requirements
in the various procedure
sections,
and
add both
a management
approval point and
a
OC
hold point to verify proper gages.
The acceptable
setpoint
range
was reduced to account for possible
gage inaccuracy.
The
inspector
reviewed
GNP-0705,
Rev 19.
Procedure
GMP-02,Rev 5,
Use of %TE by Mechanical
Maintenance,
was revised to spec'ify the required
gage accuracies
for several
purposes.
Procedure
GNP-0017,
Rev 25, Pressurizer
Safety Valve
Maintenance,
had
been
changed to address
gage
accuracy
and
range requirements,
Procedure
GMP-0810,
Rev 12,
Bench Testing of*Safety Relief
Valves,
had
been
changed
to include the requirement that gage
accuracy,
range,
and type
be proper
and
added
the requirement
that the supervisor
and
gC verify the selected
gage.
24,
The licensee
has
made widespread
program evaluations
and changes
to
address
this violation.
Performance
is routinely monitored
as part
of the inspection
program.
This includes -routinely planned
inspections
during the Spring,
1993, refueling outage.
This -item is
closed.
(Closed
- Unit 2) VIO 389/92-11-01,
Failure. to Restore
Peripheral
Components to Service Following Equipment Modification.
This violation involved failure of one [assist]
shop to restore
a
seismic conduit support after removing it to provide another
[principal] shop access
to complete
a modification in the area.
FPL responded
to this violation by .letter L-92-244, dated
September
9,
1992.
FPL evaluated
the as-found conditions
and found that the
subject conduit
and component
had
been operable while not attached
to the support.
The licensee
found that there were two reasons
for
the violation:
AP 0010432,
Nuclear Plant Work Orders,
lacked guidance to
planners
concerning
work order planning
on seismic structures,.
The procedure
was changed to include planning guidance
and
a
post work check for reinstallation of seismic
components.
Personnel
error
on the part of the maintenance
workers
and
" supervisors.
Maintenance
department'supervisors,
planners,.
foremen,
and journeymen
were refreshed
in this area during
refresher training completed
by September
30,
1992.
The inspector
reviewed the licensee's
response,
reviewed
AP 0010432,
Rev 62, Nuclear Plant Work Orders,
reviewed the operability
calculation,
and reviewed the training'records
and lesson
plans with
the maintenance
training supervisor.
The inspector
concurred with
the licensee's
evaluation
and corrective actions.
This item is
closed.
(Closed
- Units
1 and 2) VIO 335,389/91-22-01,
Failure to Translate
TS Requirements
for Fuel Oil Testing.
This licensee-identified violation of TS 4.8. 1. 1.2d involved the
failure to correctly identify or employ
a chemical
reagent
used in
EDG fuel oil particulate determination.
A particulate-contaminated
fuel oil shipment
was not detected,
was introduced into the site's
fuel oil system,
and resulted
in technical inoperability of three of
four fuel oil tanks.
Licensee letter L-92-36 responded
to the Notice of Violation.
In
- addition to correcting procedure
C-121,
"Determination of
Particulate
Contamination;
and
Check for Clear
and Hright Appearance
with Proper Color Diesel
82 Fuel Oil", to identify the correct
reagent,
the licensee
performed the following:
25
The licensee
returned the fuel oil storage
tanks to particulate
specification without violating the
TS time constraints.
A
contractor recirculated
and filtered the storage
tanks.
An outside contractor reviewed the corrected analytical
procedure
and confirmed the procedure to be technically correct
beyond the action stated
in corrective action letter L-92-36,
the licensee
purchased
a portable fuel oil filtration skid for
routine plant use.
This skid has
been
used to receive
and
process
fuel oil shipments
as
an enhancement
to TS
requirements.
The inspector judged that the correcti.ve, actions will decrease
the
likelihood of this event repeating.
This item is closed.
The inspectors
found the corrective actions fot those violations to be
significant and to be .focused
on the generalized
conditions
and root
causes
vice just the specific instance of violation.
13.
Exit Interview
The inspection
scope
and findings were summarized
on November 24,
1992,
with those
persons
indicated in paragraph
1 above.
The inspector
described
the areas
inspected
and discussed
in detail the inspection
results listed below, except for VIO 335/92-21-07,
Failure to Adequately
Maintain Containment
Vessel
Integrity.
Proprietary material is not
contained
in this report.
Dissenting
comments
were not rec'eived
from the
licensee
on November
24.
VIO 335,389/92-21-07
was discussed
with the licensee during telephone
conversations
between
FPL management
and
NRC Region II management
on
December
1,
1992.
The inspection
scope
and findings concerning
335,389/92-21-07
had" previously
been
summarized
during the exit interview
for IR 335,389/92-16
on August 10,
1992.
Dissenting
comments
from the
licensee
on August
10 regarding that violation are stated
below:
The only valves involved in containment
vessel integrity were those
identified by number in the
TS or perhaps
the
The licensee
stated that they believed that the
NRC had previously considered
the
situation
when the facility license
was issued
and,
by not
specifically identifying in the
TS the vent
and drain valves or
other fittings, had determined
them not required to be under the
TS
controls.
The licensee specifically stated that all vent, drain,
and test valves
and fittings located in the containment penetration
areas
were not required to be secured
in position
and were not
required to be surveillance
checked
at least
once per
31 days per
The
NRC carefully considered
the licensee's
position
on this matter but
concluded that the licensee
was incorrect
and
had
been in violation of
the subject
TS.
Item Number
335/P21-90-005
389/P21-90-005
Status
open
closed
P21-
P21-
Descri tion and Reference
Broken Swing Arms for Check Valves,
paragraph ll.a.
Broken Swing Arms for Check Valves,
paragraph
11.a.
335,389/P21-91-006
closed
335,389/90-13-01
closed
P21-
VIO-
Overspeed Trip Tappets for Terry
Steam Turbine
Pump Drivers,
paragraph
ll.b.
Failure to Ensure guality at Least
Equivalent to That Specified in the
Original Design Basis or Requirements
'- Three
Examples,
paragraph
12.a.
335)389/90-23-01
389/90-31-01
335,389/91-22-01
335/91-22-02
335/91-22-03
335/92-04-01
389/92-07-03
389/92-07-04
389/92-11-01
closed
closed
closed
closed
closed
closed
open
closed
closed
VIO-
NCV-
VIO-
VIO-
VIO-
VIO-
VIO-
VIO-
VIO-
Failure to Control Haterial in
Safety-Related
Repairs,
paragraph
12.b.
Use of Unapproved
Procedures
for PH
of 2C
AFW Pump Governor,
paragraph
12.c.
Failure to Translate
TS Requirements
for Fuel Oil Testing,
paragraph l2.j.
Loss of Containment Integrity During
Refueling,
paragraph
12.d.
Failure to Haintain
RCS In-Process
Cleanliness
Controls,
paragraph
12.e.
Failure to Properly Store
Flammable
Haterials,
paragraph
12.f.
Isolation of Containment
Pressure
Sensing
Line Without Placing Effected
Instrumentation
Channels
in TRIP or
BVPASS, paragraph
12.g.
Failure to Follow the Procedure for
Setting
Safety
Valves,
paragraph
12.h.
Failure to Restore
Peripheral
Components
to Service Following
Equipment Hodification, paragraph
12.i.
27
335/92-21-01
389/92-21-02
389/92-21-03
389/92-21-04
389/92-21-05
closed
NCV -
LTOP Technical Specification
Amendment
Implementation Failure,
paragraph
8.a.
closed
NCV - Failure to Implement
New TS
Requirements
for Emergency
Bus
paragraph
8.d.
closed
NCV - Hissed Surveillance
on
a Radiation
Monitor Being Returned to Service
Due
to Personnel
Error, paragraph
B.e.
closed
NCV - Hissed Technical Specification
Surveillance,
paragraph
8.h.
closed
NCV - Incomplete Technical Specification
Special
Report,
paragraph
7.
389/92-21-06
open
335,389/92-21-07
.= open
URI - Operation
Above the Licensed
Power
Level, paragraph 3.b.(4),
VIO -- Failure to Adequately Maintain
Containment
Vessel Integrity,
paragraph
10.
Abbreviations,
and Initialisms
A/E
AFM
ATTN
CCM
CFR
CNRB
DDPS
F
FCR
FOP
Alternating Current
Architect/Engineer
Auxiliary Feedwater Actuation System
(system)
Administrative Procedure
Attention
Corrective Action Request
Component
Cooling Mater
Control
Element Assembly
.-
Code of Federal
Regulations
Company Nuclear Review Board
Containment
Spray
(system)
Direct Current
Digital Data Processing
System
Digital Electro-Hydraulic (turbine control
system)
Demonstration
Power Reactor
(A type of operating license)
Emergency
Core Cooling System
Effective Full Power
Days
Effective Full Power Years
Engineered
Safety Feature
Fahrenheit
Field Change
Request
'low
Control Valve
Feedback of Operating
Experience
Program
.
FRG
GHP
IKC
ICW
IR
ISEG
JPN
LCO
LER
LTR BK
H&TE
MFIV
HTC
HW
HWe
HWt
NI
No.
NPF
NPWO
NRC
ohm
ONOP
OP
PCH
ppb
ppm
PSL
QCIR
QI
RDT
Rev
,SG
28
(system)
e Electrical Generator]
eactor]
operating license)
blication)
The Florida Power
5 Light Company
Facility Review Group
Final Safety Analysis Report
General
Maintenance
Procedure
Hydraulic Control Valve
High Pressure
Safety Injection (system)
Instrumentation
and Control
Intake Cool,ing Water
Integrated
Leak Rate Test(ing)
[NRC] Inspection
Report
Independent
Safety Engineering
Group
(Juno
Beach)
Nuclear Engineering
TS Limiting Condition for Operation
Licensee- Event Report
Loss of Coolant Accident
Low Pressure
Safety Injection (system)
Low Temperature
Overpressure
Protection
Letter Book
Measuring
5 Test
Equipment
Hain Feed Isolation Valve
. Moderator Temperature
Coefficient
Hotorized Valve
Megawatt(s)
Megawatt(s),
Electrical
[Energy from th
Megawatt(s),
Thermal
[Energy from .the
R
Nuclear Instrument
Number
Nuclear Production Facility (a type of
Nuclear Plant
Work Order
Nuclear Regulatory
Commission
Nuclear Regulatory
(NRC Headquarters
Pu
Unit of Electrical
Resistance
Off Normal Operating
Procedure
Operating
Procedure
Plant Change/Modification
PerCent Milli (0.00001)
Part(s)
per Billion
Part(s)
per Million
Plant St. Lucie
Quality Assurance
Quality Control
Quality Control Inspection
Report
Quality Instruction
System
Reactor Drain Tank
Revision
[NRC] Regulatory
Guide
Reactor Protection
System
Resistive
Temperature
Detector
Refueling- Water Tank
'team Generator
St.
,TFE
TS
VAC
.
29
Saint
Shift Technical
Advisor
Temperature
Element
A Type of Teflon
Technical Specification(s)
Updated Final Safety Analysis Report
[NRC] Unresolved
Item
Volts Alternating Current
Violation (of NRC requirements)