ML17227A329
| ML17227A329 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 02/25/1992 |
| From: | Elrod S, Landis K, Michael Scott NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17227A327 | List: |
| References | |
| 50-335-91-27, 50-389-91-27, IEB-88-003, IEB-88-3, NUDOCS 9203100083 | |
| Download: ML17227A329 (27) | |
See also: IR 05000335/1991027
Text
pe REGII
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UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323
Report Nos.:
50-335/91-27
and 50-389/91-27-
Licensee:
Fl ori da
Power
& Light Co
9250 West Flagler Street
Miami,
FL
33102
Docket Nos.:
50-335
and 50-389
Facility Name:
St. Lucie
1 and
2
License Nos.:
and
Inspection
Conducted:
De ember 23,
1991 - January
27,
1992
Inspectors:
S.
A. lr', Senior Resident
Inspector
/j'
zs
gz
Date Signed
M. A.
ot,
ident Inspector
/
Approved by:
.
D.
L
dis, Section Chief
Division of Reactor Projects
Date Signed
S ss
Pz-
a'te Signe
SUMMARY
Scope:
This routine resident
inspection
was
conducted
onsite
in the
areas
of plant
operations- review, maintenance
observations,
surveillance
observations,
review
of nonroutine
events,
fire protection
review,
. and
followup of previous
inspection findings.
Results:
This
inspection
addressed
normal
at-power
activities
and
two
evolutions for repairs
conducted
on Unit 2.
Unit
2
passed
400
days
of
continuous
operation this inspection period.
Surveillance
and maintenance
were
well coordinated
with plant operations
in
a
number of areas.
One occasion
where
operators
did
not practice
meticulous
equipment
status
control
was
observed.
Within the areas
inspected,
the following violation was identified:
VIO 335/91-027-01
- Failure
to Follow Equipment
Control
Procedures,
paragraph
2.b.
Within the areas
inspected,
the following noncited violations were identified:
NCV 389/91-027-02,
Engineered
Safety
Features
Actuation
Channel
Out-of-
Service
Due to Personnel
Error, paragraph
6.a.
9203100083
920225
ADOCK 05000335
G
NCV 335/91-027-03,
Technical
Specification
required
plant
vent
stack
radiation
sampler
and monitor inappropriately out-of-service,
paragraph
6.b.
NCV 335/91-027-04
Failure to Follow Work Control Procedure,
paragraph
8.
REPORT
DETAILS
Persons
Contacted
Licensee
Employees
D.
- 'G
- J
- H.
C.
R.
R.
R.
- R.
'C.
L.
G.
A.
T.
L.
N.
C.
D.
J.
W.
D.
E.
Sager,
St. Lucie Plant Vice President
Boissy, Plant General
Manager
Barrow, Fire/Safety Coordinator-
Buchanan,
Health Physics Supervisor
Burton, Operations
Manager
Church,
Independent
Safety Engineering'Grou
Dawson,
Maintenance
Manager
.
Englmeier,
Nuclear Assurance
Manager
Frechette,
Chemistry Supervisor
Leppla,
Instrument
and Control Supervisor
McLaughlin, Licensing Manager
Madden, Plant Licensing Engineer
Menocal, Mechanical
Supervisor
Roberts,
Site Engineering
Manager
Rogers, Electrical Supervisor
Roos,
Services
Manager
Scott,
Outage
Manager
West, Technical
Manager
West, Operations
Supervisor
White, Security Supervisor
Wolf, Site Engineering Supervisor
Wunderlich,
Reactor Engineering Supervisor
p Chairman
Other
licensee
employees
contacted
included
engineers,
technicians,
operators,
mechanics,
security force members,
and office personnel.
NRC Employees
- S. Elrod, Senior Resident
Inspector
- M. Scott,
Resident
Inspector
- Attended exit interview
2.
Acro'nyms
and initialisms used
throughout this report are listed in the
last paragraph.
Review of Plant Operations
(71707)
Unit
1
began
the
inspection
period
returning
to
power following a
refueling outage.
The unit ended
the inspection
period in day
35 of power
operation.
Unit
2
began
and
ended
the
inspection
period
at
power,
day
417 of
continuous
power operation.
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
and
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 we'e satisfactory:
Unit
1
ECCS space,
Unit 2 fan'ooms,
Unit
1
SFP area
and
FHB system,
and
Unit 2
SFP area
and
FHB system.
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
veri.fied.
Except
as noted below,
no deficiencies
were observed.-
During this i nspection
period,
the inspectors
reviewed the following
tagouts
(clearances):
1-12-2
Administrative Control of Equipment tags
44 - 52 for
valves
V08562 to V08570 on the "A" train MSIV, and
1-11-259
LS-14-2A, Level switch to
CCW surge tank.
On
December
23,
in Mode
1,
while transferring
the Unit
1
electrical
power
source
from the startup
transformers
to the
Unit
1 auxiliary transformers,
the
control
room operators
observed
indications of improper switchgear functioning.
After
the
transfer,
a current
reading
on
the A-train auxiliary
transformer
feed
ammeter
showed
the
auxiliary transformer
breaker
to be closed,
however,
the breaker position indicating
lights were both dimly lit.
Operators
also
observed
that the
startup
transformer
breaker
position lights
showed
that
the
startup
breaker
was still closed.
The operators
immediately
stopped
power ascension
activities,
notified their management,
and investigated
the condition.
They
determined
that both circuit breakers
were closed,
and that the
startup
transformer circuit breaker
would not
open remotely.
The
problem
was
found to be
a poor contact
in the auxiliary
transformer circuit breaker control circuit.
While troubleshooting
these circuit breakers,
the
operators
racked out the
1A startup transformer circuit breaker,
moved it
several
feet
away from the switchgear,
and tested it. It was
reinstalled within minutes.
TS 3.8. 1. 1. required,
in part,
two
physically independent circuits between
the offsite transmission
network
and
the onsite
Class
1E distribution system
be operable
while in Modes
1, 2, 3,
and 4.
The action statement
required,
in part,
return
to service
of inoperable circuits within 72
hours.
The licensee
met this time requirement.
However,
when
the
operators
racked
out the
lA startup
transformer circuit
breaker,
they did not declare it inoperable
per
TS 3.8. 1. 1 nor
did they log this action in the
TS Equipment Out-Of-Service
Log
per
OP 0010129,
Rev
18,
Equipment
Out of Service.
The licensee
stated that the reasoning
followed was the
same
as the reasoning
that allows temporary disablement of the
EDG start circuit while
manually rotating
the
EDG prior to surveillance
runs without
declaring it out of service
and testing
the other
EDG.
The
inspector
judged this logic faulty since safety considerations
allowed to support
required
surveillances
do not necessarily
apply
to
troubleshooting
and
repair.
Also,
the
actions
described
above
were not consistent
with known licensee
policy
and routine
inspector observations
of the
removal
fromservice
process:
Unit
1
TS 6.8. l.a requires that'ritten
procedures
shall
be
established,
implemented,
and maintained
covering the activities
recoranended
in Appendix
A of Regulatory
Guide 1.33, Revision 2,
February
1978.
Appendix A, paragraph
1 included procedures
for
equipment control
and for log entrys.
This was
implemented
on
site in part
by
OP 0010129,
Rev 18,
Equipment Out-0f-Service,
which required that all equipment required
by TS shall
be logged
in the Equipment Out-of-Service
Log when that equipment
has
been
determined
to
be inoperable.
Failure to declare
the A-train
offsite circuit out-of-service
and
log the condition in the
Equipment Out-of-Service
Log when that equipment
had
been
made
by
removing
the circuit breaker
was
a violation
of
TS 6.8. 1.
This is
VIO 335/91-027-01,
Failure to Follow
Equipment Control Procedures.
On January
19, the licensee
discovered lightly wetted lagging
on
Unit
2
valve
V12424,
the
4A heater
inlet valve
(nominally operating
at
330
degrees
F,
450 psig).-
This 24-
inch, carbon steel,
Pacific brand,
gate
valve was
a secondary
plant valve and not directly safety-related.
By January
21, the
was
removed,
exposing
a through wall pinhole leak in the
valve
body.
The
same
day,
the
licensee
downpowered
to
approximately
60 percent
power to investigate this leak,
and
also
investigate
a
TCW heat
exchanger
tube
leak
and
clean
condenser
waterboxes.
Ultrasonic
and magnetic particle testing
and inspection of the area
around the pinhole revealed that the
valve
base
material
was
sound.
Previous
inspection
of the
adjacent
pipe,
performed
during
the last outage,
revealed
no
degradation
from erosion.
The
licensee
concluded
that
the
pinhole
was
a casting flaw (porosity) that would not propagate.
A licensee
contractor
sealed
the pinhole
on January
23 with
a
leak repair plug and external
band following restoration of the
valve to normal operating
temperature.
Following these repairs,
the plant
was returned
to its normal configuration.
Permanent
weld repair using heat treatment,
was deferred until the April
1992 refueling outage.
On
the
morning
of January
26,
the
licensee
observed
a
lubricating oil leak
from
2B main feedwater
pump
instrument
tubing.
The 'tubing from the lubricating oil
pump di.scharge,
was
bent at
a point beneath 'a pressure
gage.
The cause
and time at
which the
bend
occurred
were
unknown.
Oil was leaking
from a
tubing fitting that
was
cracked
around
one-fourth
the
circumference.
The unit was
down-powered
to approximately
45
percent for replacement
of the tubing.
A new tubing assembly
was
preassembled
and
staged
prior to field work commencing.
Power
ascension
in the early afternoon
of the
same
day
was
uneventful.
c.
Technical Specification
Compliance
Licensee
compliance
with selected
TS
LCOs
was verified.
This
included
the review of selected
surveillance test results.
These
verifications
were
accomplished
by direct observation of monitoring
instrumentation,
valve positions,
and switch positions,
and
by review
of completed
logs
and records.
Instrumentation
and recorder
traces
were observed for abnormalities.
The licensee's
compliance with LCO
action
statements
was
reviewed
-on selected
occurrences'-
as
they
happened.
The inspectors
verified that related plant procedures
in
use were adequate,
complete,
and included the most recent revisions.
d.
Physical
Protection
The inspectors verified by observation
during routine activities that
security
program plans
were being implemented
as evidenced
by: proper
display of picture badges;
searching of packages
and personnel
at the
plant entrance;
and vital area portals being locked and alarmed.
The licensee's
attention
to plant conditions
and
prompt correction of
degradations
was
a
key factor in continued excellent plant performance.
The failure to declare
equipment
out-of-service for troubleshooting
and
maintenance
is considered
an isolated instance.
3.
Surveillance
Observations
(61726)
Various
plant
operations
were verified to
comply with selected
TS
requirements.
Typical of these
were confirmation of TS compliance for
reactor coolant chemistry,
RWT conditions,
containment
pressure,
control
room ventilation,
and
and
DC electrical
sources.
The inspectors
verified that
testing
was
performed
in
accordance
with
adequate
procedures,
test
instrumentation
was calibrated,
LCOs were met,
removal
and restoration
of the affected
components
were
accomplished
properly,
test results
met requirements
and
were reviewed
by personnel
other than
the individual directing the test,
and that
any deficiencies
identified
during the testing
were properly
reviewed
and
resolved
by appropriate
management
personnel.
The surveillance tests
discussed
in the following
paragraphs
were observed:
a.
OP 2-0110050,
Rev ll, Control
Element Assembly Periodic Exercise.
b.
18C
1-0700051,
Rev
Actuation System Monthly
Functional
Test.
c.
OP 2-0700050,
Rev 26, Auxiliary Feedwater'eriodic
Test,
Data Sheets
"A" and "8", for the
2A and
2B pumps.
OP 2-2200050,
Rev 37,
Emergency
Diesel
Generator
Periodic Test
and
General
Operating Instructions:
During this surveillance,
performed
on
December
26,
1991
the
performed well, however
one of the two solenoid-operated
valves that
refi 1 1
the
fuel
day
tanks
failed
to function
automati cal ly'.
Independent
local
and
remote
tank level
alarms
functioned properly
and
manual
valve operation
was easily
accomplished
and successful.
The
operator
replaced
a
blown fuse
and
the circuit functioned
correctly during subsequent
automatic
operation.
Subsequent
review
showed that, following the tank level alarm,
the
12 cylinder engine
was capable of almost
two hours of operation with no operator action.
The surveillance
test
required
one
hour of operation
plus
a
few
minutes for startup,
and
shutdown.
The licensee initially credited
operator
action
concerning
fuel
transfer
and
considered
the
surveillance satisfactory.
Subsequent
inspector
review of Unit
2
TS 3/4.8. 1
showed
that
TS
surveillance
step
3 required that the operator "verify that the fuel
transfer
pump
can
be started
and transfers
fuel
from the storage
system to the engine-mounted
tank."
The inspector
reviewed
1. 108,
Rev
1,
and
determined
that
the
surveillance
would
be considered
a valid test
per criterion e.(3),
which, involved
a successful
start,
successful
loading to at least
50
percent of full load,
and continued operation for at least
one hour.
Since these
two criteria are not always compatible
and
TS 4.8.1 deals
directly with TS operability, the inspector questioned
the licensee's
determination.
The licensee,
then reclassified
the surveillance
as
failed, carried
out required
TS actions,
and though troubleshooting
could find
no faulty components,
replaced
the
alarm module since
these
had failed
more frequently than other components.
Since
the
degree of operator
action allowed during surveillances
was not clear,
the inspector
intends
to clarify it through correspondence
with NRC
Region II and Headquarters
staffs.
OP 3200051,
Rev 8, At Power Determination of Moderator Temperature
Coefficient:
'nit
1 following post-refueling startup,
and
Unit
2
near
300
ppm
concentration
per
TS 4.1.1.4.2.
This test is
an infrequently performed evolution per
AP 0010020,
Rev
0, Conduct of Infrequently Performed Tests or Evolutions at St. Lucie
Plant.
The
required
pre-evolution
briefings
were excellent
and
oversight
and attention
to detail
by management,
SROs,
RCOs,
and the
reactor
engineers
was meticulo'us.
Both tests
reached, satisfactory
conclusions.
The
above
tests
were carried
out satisfactorily with good coordination
among
the participating
groups,
non-licensed
operators,
and
licensed
operators.
f.
OP 2-2200050,
Rev 38,
Emergency
Diesel
Generator
Periodic Test, for
the
28
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'ystems
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'utstanding
jobs
and
to
ensure
that
priority
was
assigned
to
safety-related
equipment.
Portions
of
the
following maintenance
activities were obs'erved:
a.
NPWO 4874/65
provided work control instruction for the
of the
1A
ICW MFA relay (f4 on
CMD 832);
b.
NPWO
6843/64
provided
work
control
instruction
for
the
troubleshooting
and. subsequent
testing of the pressurizer
pressure
SIAS module
BA 106
on channel
"HA";
c.
NPMO
6939/63
provided
work control for the
troubleshooting
and
calibration of FT 2212-1 loop for the Unit
1 charging
header flow;
d.
NPWO
4870/65
provided
work control for the
troubleshooting
and
component
replacement
of the "in sync" light on the
1C instrument
bus
inverter;
e.
'PMO 6880/64 provided work control for the removal
and calibration of
1102D, Unit 2
"HD" channel
RCS pressure,
that
had drifted in its
calibration;
and,
5.
f.
NPWO 6894/64 provided work control for the troubleshooting
and repair
of 2C
AFW pump discharge
flow recorder
FR 09-2C.
l
The
above
observed
activities
were
performed
acceptably
with
good
interface with operations
personnel.
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'oads,
flammable
materials
storage,
housekeeping,
control
of
hazardous
chemi ca 1 s,
and fire barri ers.
The observed fire protection'ctivities
and fe'atures
were acceptable.
6.
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
w'as closed.
a.
(Open - Unit 2)
Engineered
Safety, Features
Actuation
Channel
Out of Service
Due to Personnel
Error.
This
LER reported
a licensee-identified
TS violation where
channel
"0" had been
placed in bypass
in lieu of the required tripped
state
when taken out of service.
The channel
remained
in this state
for 69 hours7.986111e-4 days <br />0.0192 hours <br />1.140873e-4 weeks <br />2.62545e-5 months <br />,
exceeding
the
or be placed
in trip" statement
of 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.
.The difference
between
"bypass"
and
"trip" positions for the
RAS channels
is that the resulting trip
logic is two out of three
when bypassing
one channel
and one out of
three
when tripping one channel.
The
licensee
had
completed
or initiated the following corrective
action via the in-house corrective action
systems
as stated
in the
LER text:
counselled
the responsible
licensed
personnel;
issued
open item notice 91-26 (2) requesting training department
evaluation of the event
as
a training item;
repaired
the faulted channel;
issued
open
item notice
91-26
(4) requesting
review of the
equipment out of service
process;
and,
issued
open
item notice
91-26
(5) for human factors
oriented
modification of the bypass
key.
The tentative
due date for items 91-26-(2),
(4),
and
(5) above is
March
1,
1992.
The last
two actions
above
are also
addressed
by
Corrective action request
1'22691
from the
gA department
on site.
The
channel
bypass
key will be modified to have
a chain
and
instruction tab attached.
The instructions will remind the operator
of the appropriate
TS instruction and required deviation log entry to
be
made
when the
key is used.
The
human factors
approach
to
bypass
key use
should provide
a positive reminder of proper usage.
LER 389/91-06 will remain
open
pending corrective action completion.
Failure
to trip the
RAS signal
as
required
by
TS is closed
389/91-027-02,
Engineered
Safety
Features
Actuation
Channel
Out of
Service
Due to Personnel
Error.
It is not being cited
because
the
licensee's
corrective
actions
associated
with this event
met
NRC
Enforcement Policy Section
V.G criteria for not issuing
a Notice of
Violation.
b.
(Closed - Unit 1)
Removal
of the Plant
Vent Stack
Monitors From Service Resulted
in a Condition Prohibited
by Technical
Specification.
This
LER reported
a licensee-identified
TS violation where the plant
vent
stack
particulate
sampler;
sampler,
and
noble
gas
activity monitor
was
taken
out of service
without initiating
appropriate
TS 3.3.3. 10 required alternate
sample collection.
With
the unit in
Mode 6, this condition existed for approximately
12
hours.
During this time period, there
were
no activities that could
have resulted
in an abnormal
gaseous
release.
The root cause
was
a cognitive personnel
error by utility licensed
operators
for referencing
an inappropriate
TS requirement pertaining
to radiation monitoring instrumentation.
TS 3.3.3. 1 required
one
channel
of noble
gas effluent monitor of the plant vent system to be
in service
during
Modes
1,2,3,
and
4.
TS 3.3.3. 10 required
particulate,
and
noble
gas monitoring at all times via the
sampler/monitor
or
by grab samples.
The
stated
corrective
action
of the
LER were
completed.
The
licensee's
corrective
actions
associated
with this event
met
NRC
Enforcement Policy Section
V.G criteria for not issuing
a Notice of
Violation. It is identified as closed
NCV 335/91-027-03,
TS Required
Plant
Vent
Stack
Radiation
Sampler
and
Monitor Inappropriately
Out-of-Service.
The
above
events
indicated
a minor lack of attention
to detail
by the
operations
department.
Per the information on similar events
provided in
the
LER text,
these
types of operator oversight
had
been occurring
on
a
two
to
three
year
cycle.
When
implemented,
the
human
factored
modification of the
bypass
key
should
reduce
the likelihood of
operator error.
7.
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
10
health
and
safety
received
primary consideration.
Potential
generic
impact
and trend detection
were also considered.
The operational
actions
observed
and
reviewed
during this period
were
acceptable
and addressed
in other portions of this report.
Followup of Inspection Identified Items
(GE
HFA Relay Failures
to Latch)
(Units
1 and
2) (92701)
~Sno sis
Engineered
safety features
and loss of offsite power testing at the St.
Lucie site
have
identified
HFA relay failure-to-latch
conditions
contrary to
GE Service Letter
190.1
and
a resultant
10CFR Part
21
notification
GE Service Letter 190. 1 stated that,
for older latching relays
in Class
1E service, utilities should perform
certain latch tests
and replace
relays failing the test with new
HFA -1xx
(Century Series)
relays manufactured after November
1, 1987.
For Class
1E
service, field adjustment
was not an option,
and
vendor
manual
GEK-45486
provided
no
instructions
for adjusting
the
latching function.
All
latching-type relays manufactured after November 1, 1987, would be checked
for the condition at the factory.
Not only'ave older (but field tested)
HFA latching
relays
subsequently
fa'iled to function reliably while
installed in safety systems,
so have relays manufactured after November
1,
1987.
Use and Function of Latchin
Rela
s at St. Lucie
St. Lucie Unit
1 had
14
and Unit 2 had
6 safety-related
latching
HFA 154
series
relays.
The
14 Unit
1 Class
1E latching relays
served:
3
CCM pumps
1A, 18,
1C;
3
ICM pumps
lA, 1B,
1C;
2 Reactor cavity cooling fans
2 Auxiliary building supply fans
2 Reactor support cooling fans
2
room exhaust
fans
.1
HVS 2A, 2B;
1
HVS 4A, 4B;
1
HVE 3A, 3B; and
1
HVE 9A, 9B.
The
6 Unit 2 Class
1E latching relays
served:
3
CCW pumps
2A, 2B,
2C; and
3
ICM pumps
2A, 2B,
2C.
The primary purpose
of
loss of power,
control
were
running
when
loss
automatically restarted
these
latching relays
was
to preserve,
during
a
system
knowledge
o'f which individual
components
of power occurred.
These
components
would be,
when power returned.
These
relays mechanically latch closed
when operated
and are electrically
reset
by
a small coil.
Some
models at other sites
could also include
a
manual
reset
button.
The relays
were mounted
on vertical surfaces
and the
11
plate-shaped
armature
operated
in
a horizontal
direction rather
than
"up-and-down."
Closing force
was
provided
by
an electromagnetic
coil,
opening
force
was
provided
by
a spring.
The U-shaped
latch,
which sat
above the top edge of the plate-shaped
armature,
had
a roughly rectangular
notch in the end
on each side.
The notches
were about
1/8 inch wide by
1/8
inch
deep.
When
the
relay
actuated,
the
armature
would
move
horizontally and the latch
be pulled down by another spring - trapping the
armature in both notches.
Previous
Failures of Rela
s to Reliabl
Latch
based
on
a
10
CFR Part
21 notification, identified
potential latch engagement
problems affecting series
51B (151B),
54 (154),
71b
(171B),
and
74
(174) latching relays.
The bulletin focused
on the
relays failing to remain closed
[as during seismic events, etc.]
At St.
Lucie, the failure to remain latched
would result in no automatic signal
to start
and
would require
operator
action
to carry out the safety
functi on.
In the fall of 1990,
The
2B
ICW
pump relay failed to latch in service
during
a
LOOP test.
The relay had insufficient clearance
between
the
U-shaped latch
and the armature.
This relay was replaced
under
NPWO
5553/62.
Recent
licensee
inquiry found that this relay's
date
code
was
14GT (July 1981).
In the fall of 1991,
the
1A
ICW
pump relay failed to latch in service
during
a
LOOP test.
The relay
had insufficient clearance
between
the
U-shaped
latch
and the armature.
This relay was adjusted
to meet the 1/32
inch criteria under
NPWO 4473/65.
The licensee
then reinspected
all 20
Class
1E relays
under
NPWOs
2287/66
and
4950/65
per Bulletin 88-03
requirements.
Four additional
relays
latched
intermittently or
had
insufficient latch engagement.
Relays failing the inspection were:
Date
Code
14UC (July 1988)
Date
Code
14UC (July 1988)
Date
Code
14TC (June
1988
Date
Code
14VC (August 1988)
Date
Code
14FU (June
1982)
1A
ICW pump
1B
CCW pump
1
HVS
2B
1
HVE 3B
2B
CCW pump
This
was
25 percent
of the
Class
1E latching relays installed
at St.
Lucie.
The licensee,
being
unsure
whether
the
relay settings
were
drifting or had
been initially mis-set,
planned
to monitor them again in
the Spring of 1991 during the next Unit 2 refueling outage.
inspections
were
performed
at St.
Lucie in
1988
and
reported
complete
by
FPL letter L-88-392 of September
22,
1988.
Three of
20 relays, for the
2A, 2B,
and
2C
CCW pumps,
were previously
154E relays
and tested
satisfactory.
Four of the remaining
17 failed the inspection
and were replaced with 154E relays.
These four were for the
2A and
2B
ICW
pumps,
1HVS 2B,
and
1A ICW pump.
12
Evaluation of NRC and Vendor Literature
Subsequent
to the test failures,
the licensee
found that very
new relays
not only had full, rather
than
1/32 inch, latch
engagement
but also
had
about
1/32
inch additional
available
armature
movement after latching.
FPL-GE staff conversations
confirmed this
as
a standard
practice.
Inspector
review found that
NRC Bulletin 88-03 attached
Figure-2 did not
show the correct location of the 1/32 inch latch engagement,
did not show
the notch in the
end of the latch,
and did not discuss
additional
armature
movement
toward the coil with the latch engaged.
Figure-2 did show shims
[items
114,
1,17
(use
as required)] behind the latch mounting screw.
"Use
as required" is contrary to the options in the vendor
manual
and Service
Advice Letter.
GE stated
in vendor
manual
GEK-45486 that
HFA 154 Series
relays
are
cal,ibrated
at the factory
and
under
normal
conditions will require
no
further adjustments.
Oetailed field adjustment
of the latch
was
not
addressed.
The manual
did address
several
other adjustments, if required:
Contact burnishing;
Changing
contacts
from
Normally-open
to
.Normally-closed
and
vice-versa;
Adjustment of coil pickup voltage
(a spring tension adjustment);
Ensuring all contacts
open or close
simultaneously
with 3/64 inch
wipe
when in the
operated
position - contact
arms
may
be
bent
slightly to accomplish this;
and
Check to see that the armature
latches
in when operated
by hand
and
opens readily when reset.
GE service letter
190. 1,
which
the bulletin
was
based
on,
added
a
requirement:
When latched,
both latch legs
must
engage
[overlap] the armature
by
1/32 inch.
GE service letter 190; 1 also
added
two adjustment
checks:
The clearance
between
the top of the molded contact carrier
and the
top of the relay armature
must
be 1/32 inch minimum.
With the armatur'e fully depressed
against
the pole piece,
check that
the latch is fully rotated
by pulling up
on the latch assembly - no
motion is allowed.
The latch
mechanism
was
mounted
to the
case
in the
same
manner
as
a
contact.
Adjustment
by shimming to obtain proper latching did not appear
13
to
be difficult, and in fact this is what the factory did.
The biggest
problem
was
that
the
vendor
manual
did not
have directions
and part
. numbers,
nor did it recommend
a periodic
reinspection
of the latch
function.
t
The inspector
concluded that the
GE .manufacturing
conditions resulting in
the .service letter
and
NRC Bulletin
may not
have
been corrected,
thus
-these failures to latch could
be
a
symptom of
a generic
safety
problem.
Additionally, recently obtained
information supported
the conclusion that
the inspection criteria disseminated
by
may well have
been
incorrect
or subsequently
changed.
NRC review with the
vendor
appears
appropriate
and
has
been requested
via
NRC Region II.
The licensee's
corrective
actions
following reinspection
of the relays
initially included repair of one relay along with replacement
of the other
ones.
While the
sketch
accompanying
showed
"use
as
necessary"
and
the
repair
was clearly within the skill
and
capabilities
of the
experienced
relay
engineer
making the repair,
the
vendor literature
only addressed
replacement
of relays
and
the plant
repair
procedures
and
NPWO, did not specifically authorize
the actions
taken.
Unit 2
TS 6.8. l.a required that written procedures
be established,
implemented
and maintained
covering the activities
recommended
in Appendix
A of Regulatory
Guide '1.33,
Revision
2,
February
1978.
Appendix A,
paragraph 9.e,
includes
procedures for obtai ning permission to work.
This
was
implemented
on site
by
AP 0010432,
Rev 57, Nuclear Plant Work Orders,
which required that all corrective maintenance
work be authorized
through
the
NPWO
and
conform
to
equality: Instructions,
Administrative,
and
Maintenance
Procedures.
Repair of the relay violated
AP 0010432.
The
licensee
took action
to replace
the relay in question
even
though it .
functioned
properly,
review
shop
decisions
involved,
and
change
maintenance
procedure
0960066,
Rev 4,
General
Electric
Type
HFA Relay
Testing
and
Setup
Procedure,
to address
latch
adjustment.
Based
on
frequent
observations
of licensee
maintenance
actions,
the
inspector
judged that this was
an isolated event.
This violation is not being cited
because
of
,lack of safety
significance
and
because
the
licensee's
corrective actions
met
NRC Enforcement Policy Section
V.A criteria for not
issuing
This is closed
NCV 335/91-027-04,
Failure
to Follow Work Control Procedure.
Followup of Inspector Identified Items
(Attendance at
FRG Meetings)
(Units
1 and 2) (92201)
The
inspector
had
previously
observed
that
the
gA and
ISEG staffs
frequented
FRG meetings
as observers.
The licensee
management
viewed this
as inhibiting candid conversation
and
asked
the
two groups
to reconsider
their needs.
After several
months,
the inspector
again reviewed this area
to determine if this policy change
had
a detrimental effect
on gA and
ISEG
operations.
Interviews with supervisors
of both organizations
revealed
that they
had
each
analyzed their operations
and determined
that routine
"observation" of FRG meetings
was not central
to their planned activities.
Additionally, the Site guality Group had provided
a regular
FRG member,
so
14
important information
was readily available,
and audited
the
FRG
on
an
annual
basis.
The inspector
concluded
that the activities of these
two
groups
were
not adversely
affected
by not frequenting
FRG meetings
as
observers.
10.
Followup of Headquarters
and Regional
Requests
(Units
1 and 2)(92701)
During this inspection period,
the
NRC staff had the resident
inspectors
complete
a survey
on the containment
hatch closure
equipment at this site.
The licensee
actions
in this area
were acceptable.
11.
Exit Interview (30703)
The inspection
scope
and findings were
summarized
on January
31,
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
335/91-027-01
389/91-027-02
Item Number
Open
VIO - Failure to Follow Equipment Control
Procedures,
paragraph
2.b.
Closed
NCV - Engineered
Safety
Features
Actuation
Channel
Out of Service
Due to
Personnel
Error, paragraph
6.a.
Status
Descri tion and Reference
335/91-027-03
Closed
NCV - TS Required Plant Vent Stack
Radiation Sampler
and Monitor
Inappropriately Out-of-Service,
paragraph
6;b.
335/91-027-04
Closed
NCV - Failure to Follow Work Control
Procedure,
paragraph
8.
12.
Abbreviations,
and Initialisms
ATTN
CFR
CWD
Alternating Current
(system)
Administrative Procedure
Attention
Component Cooling Water
Code of Federal
Regulations
Control Wiring Diagram
Direct Current
Demonstration
Power Reactor
(A type of operating license)
Emergency
Core Cooling System
.
15
FHB
FT
HFA
HYE
HVS
ICW
LCO
LER
NPF
NPWO
NRC
OP
ppm
psi 9
RCO
Rev
SFP"
TCW
TS
V IO
Emergency
Diesel
Generator
Engineered
Safety Feature
Fuel Handling Building
Flow Transmitter
General Electric Company
A GE relay designation
Heating
and Ventilating Exhaust (fan, system,
Heating
and Ventilating Supply (fan, system,
e
Intake Cooling Water
TS Limiting Condition for Operation
Licensee
Event Report
Level Switch
NonCited Violation (of NRC requirements)
Nuclear Production Facility (a type of operati
Nuclear Plant Work Order
Nuclear Regulatory
Commission
Operating
Procedure
Part(s)
per Million
Pounds
per square
inch (gage)
Quality Assurance
Recirculation Actuation Signal
Reactor Control Operator
Reactor
Coolant System
Revision
[NRC] Regulatory Guide
Refueling Water Tank
Spent
Fuel
Pool,
Safety Injection Actuation System
Senior Reactor [licensed] Operator
Turbine Cooling Water
Technical Specification(s)
Violation (of NRC requirements)
etc. )
tc.)
ng license)