ML17345A658
| ML17345A658 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 04/24/1989 |
| From: | Butcher R, Crlenjak R, Mcelhinney T, Schnebli G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17345A655 | List: |
| References | |
| 50-250-89-12, 50-251-89-12, NUDOCS 8905100054 | |
| Download: ML17345A658 (19) | |
See also: IR 05000250/1989012
Text
0
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a RECy
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UNITED STATES
NUCLEAR R EGU LATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323
Report Nos.:
50-2SO/89-12
and SO-251/89-12
Licensee:
Florida Power
and Light Company
9250 West Flagler Street
Miami,
FL
33.'.02
Docket Nos.:
50-250
and 50-251
Facility Name:
Turkey Point
3 and
4
License Nos.:
and
Inspection
Conducted:
February
25,
1989 through March 31,
1989
Inspectors:
R.
C. Butcher,
Senior
Resi ent Inspector
ate
igned
T.
F. McElhinney, Resident
nspector
Da
e
igned
G. A.
S
ebli, Resid
t In pector
Approved by
R.
V. Crlenja
, Section
C
ef
Division of Reactor Projects
4'.
C
Da
e
S gned
ate
igned
SUMMARY
Scope:
This routine resident
inspector inspection entailed direct inspection
at
the
site
in
the
areas
of monthly surveillance
observations,
monthly
maintenance
observations,
engineered
safety
features
walkdowns, operational
safety
and plant events.
Results:
One violation was identified:
Failure to follow procedures
resulting
in valve 4-201B being
open
and draining
RCS water to the containment
sump.
One
licensee
identified violation
was
identified:
Failure
to
calibrate
a liquid radwaste
effluent line flow transmitter wit1in
ADM-021 frequency.
One unresolved
item" was identified in that Reactor Coolant
Pump
(RCP)
seal
injection throttle valve
4-297A was
open, contrary to GOP-305,
resulting in the inadvertent
increase
in drain
down water level.
"Unresolved
items
are
matters
about
which
more
information is
required
to
determine
whether they are acceptable
or may involve violations or deviations.
N'051OI.IO54
~~.A@42*
AEIOCK 0. OOOZCO
Q
REPORT
DETAILS
Persons
Contacted
Licensee
Employees
"T. Abbatiello, guality Assurance
Supervisor
J.
W. Anderson, (}uality Assurance
Supervisor
J. Arias, Senior Technical Advisor to the Plant Manager
L.
W. Bladow, guality Assurance
Superintendent
J.
E. Cross,
Plant Manager-Nuclear
"R. J. Earl, guality Control Supervisor
T. A. Finn, Training Supervisor
S. 'T. Hale,
Engineering Project Supervisor
R. J. Gianfrencesco,
Maintenance
Superintendent
V. A. Kaminskas,
Technical
Department
Supervisor
R.
G.
Mende, Operations
Supervisor
- J.
S.
Odom, Site Vice President
L.
W. Pearce,
Operations
Superintendent
"F.
H. Southworth, Assistant to Site
J.
C. Strong,
Mechanical
Department
Supervisor
M. Stanton,
Instrument
and Control Department Supervisor
"K. Van Dyne, Acting Regulatory
and Compliance Supervisor
M. B. Wayland, Electrical
Department
Supervisor
"J.
D. Webb, Operations - Maintenance
Coordinator
Other
licensee
employees
contacted
included
construction
craftsman,
engineers,
technicians,
operators,
mechanics,
and electricians.
"Attended exit interview on March 31,
1989
Note:
An alphabetical
tabulation of acronyms
used in this report is
listed in paragraph
12.
Followup on Items of Noncompliance
(92702)
A review
was
conducted
of the following noncompliances
to assure
that
corrective actions
were adequately
implemented
and resulted
in conformance
with regulatory
requirements.
Verification of corrective
action
was
achieved
through record reviews,
observation
and discussions
with licensee
personnel.
Licensee
correspondence
was
evaluated
to
ensure
that
the
responses
were timely and that corrective actions
were
implemented within
the time periods specified
i.n the reply.
(Closed)
Violation 50-250,251/88-14-01,
concerning
material
for use
in
ICW gauge fittings was not properly controlled.
The licensee
responded
to
this violation
in letter
dated
August 29,
1988.
The
NRC
considered
the
response
and the actions
taken
to prevent
recurrence
to
be adequate.
This violation is closed.
(Closed) Violation 50-250,251/88-18-01,
concerning
the* failur e to follow
procedure
for rod control
system malfunction.
The licensee
responded
to
this violation in Letter
dated
September
30,
1988.
The
NRC
considered
their response
and
the actions
taken to prevent recurrence
to
be adequate.
This violation is closed.
Follow-up on Inspector
Followup Items
( IFIs) (92701).
(Closed)
Inspector
Followup
Item
50-250,251/88-11-03,
concerning
the
differences
in documentation
associated
with ICW gauge
assembly material.
This IFI was
subsequently
upgraded
to
a violation (50-250,251/88-14-01)
and therefore this IFI is closed.
Onsite
Followup
and In-Office Review of Written
Reports
of Nonroutine
Events
(92700/90712)
The
Licensee
Event
Reports
( LERs)
discussed
below were
reviewed
and
closed.
The inspectors verified that reporting requirements
had
been
met,
root
cause
analysis
was
performed,
corrective
actions
appeared
appropriate,
and generic applicability had
been considered.
Additionally,
the
inspectors
verified that
the
licensee
had
reviewed
each
event,
corrective actions
were implemented,
responsibility for corrective actions
not fully completed
was clearly
assigned,
safety
questions
had
been
evaluated
and resolved,
and violations of regulations
or
TS conditions
had
been identified.
When applicable,
the criteria of
Appendix
C,
were applied.
(Closed)
LER
50-251/87-19,
concerning
a
turbine
runback
caused
by
a
spurious
spi ke in the
RPI system
due to
a
loose
solder joint in
a cable
connector
for
Rod
E-5.
The
loose
solder joint was
repaired
and
the
connectors
for all remaining
were
inspected
and defects
identified.
This
LER is closed.
(Closed)
LER
50-251/87-25,
concerning
a
containment
and
control
room
ventilation isolation
due to high Rubidium in the containment following a
unit shutdown.
The event
was evaluated
to have
been
caused
by the rapid
shutdown of the unit and
subsequent
depressurization
as
a precautionary
measure
against
an approaching
hurricane.
An
leak rate calculation
was performed
and the results
showed
no unexpected
RCS leakage.
This
LER
is closed.
(Closed)
LER 50-250/88-02,
concerning
a reactor
coolant
system
pressure
decrease
caused
by
a malfunctioning pressurizer
spray valve.
The primary
cause of the event
was
a defective controller for pressurizer
spray valve
PCV-3-455B.
The controller
was
subsequently
replaced.
This
LER is
closed.
(Closed)
LER 50-250/88-04,
concerning
AFW initiation on low SG level due
to inadequate
monitoring of the
SG level
by the operator.
The root cause
of the event
was
the failure of the operator to monitor
SG level
due to
involvement
in other testing.
The operator
was
counseled
and the event
was discussed
with all other operations
personnel.
This
LER is closed.
5.
Monthly Surveillance
Observations
(61726)
The
inspectors
observed
TS required
surveillance
testing
and verified:
that
the test
procedure
conformed
to the
requirements
of the
TS,
that
testing
was
performed
in accordance
with adequate
procedures,
that test
instrumentation
was calibrated,
that limiting conditions
for operation
(LCO) were met, that test results
met acceptance
criteria requirements
and
were reviewed
by personnel
other than
the individual directing the test,
that
deficiencies
were identified,
as
appropriate,
and
were
properly
reviewed
and resolved
by management
personnel
and that
system
restoration
was
adequate.
For completed tests,
the
inspectors
verified that testing
frequencies
were met and tests
were performed
by qualified individuals.
The
inspectors
witnessed/reviewed
portions
of
the
following test
activities:
3-OSP-075.
1
Train
1 Operability
Verification
0-OSP-023.
1
Diesel Generator Operability Test
O-OSP-074.3
Standby
Pumps
Available Test
O-OSP-074.4
Standby
Pumps/Cranking
Diesel's Test
On March 6,
1989,
during performance
of 3-OSP-075. 1, Auxiliary Feedwater
(AFW) Train
1 Operability Test, revision
dated
September
20,
1988,
the
A
AFW pump governor oil level
was
found out of sight high.
A Plant
Work
Order
(PWO)
was initiated to drain
some of the oil out of the governor
while the
pump was operating.
The oil was drained to the proper level in
the sightglass
and the test
was completed satisfactorily.
The inspectors
questioned
the
licensee
as to the
adequacy
of the governor oil filling
method
when
ILC department
draws
a
sample.
The vendor
manual
(Woodward
Governor)
recommends
that the oil level
be at the mark on the sightglass
with the
pump operating.
Oil level
should
be visible in the sightglass
under all other conditions.
The vendor further stated that the oil must
never
be
above
the line where
the
case
and
column castings
meet.
Oil
above this level will be churned into foam by the flyweight head.
The
department periodically drains
an oil sample
from the
AFW pump governors
for oil analysis,
This draining is accomplished
by a
PWO.
The inspectors
reviewed
some
of the instructions
contained
on
these
PWOs
and
found
varying degrees
of instructions listed.
Some instructions
gave
a specific
oil level while others
directed
I&C personnel
to return oil level
to
normal.
The inspectors
believe that non-specific instructions
on the
PWO
could lead to improper oil level
in the
AFW pump governors
such
as
was
found
on the
March 6,
1989,
surveillance
test.
The other
item noted
by
the
inspectors
is that
3-OSP-075. 1,
step
7. 13,
has
the operators
check
governor oil level prior to running the
pump by verifying that the level
is above the line in the sightglass.
This check verifies that the minimum
level is present,
however, it does
not verify if too much oil is present.
Therefore
the
pump could
be
started
with too
high of
a
level
in the
governor.
The
inspectors
will followup
on this
issue
via Inspector
Fol 1owup Item (IFI) 50-250,251/89-12-01.
On
March 27,
1989,
the
licensee
discovered
that
the liquid radwaste
effluent line flow transmitter,
FT-1064,
was
out of calibration.
The
operators
placed
Process
Radiation Monitor (PRM)
R-18 out of service
and
restricted
any
furt'her liquid releases
until
the
flow channel
was
calibrated.
The flow transmitter
was calibrated
and returned
to service
on
March 29,
1989.
The
flow transmitter
was
previously calibrated
on
April 11,
1987.
Technical
Specifications
(TS),
table
4. 1-3,
item 2.a,
specified
the liquid radwaste
effluent line flow rate
monitor channel
calibration frequency
as
each
refueling.
Since this flow transmitter is
common
equipment,
the
licensee
performed
the calibrations
based
on the
Unit 3 refueling
cycles.
However,
Administrative
Procedure
(ADM)-021,
Technical Specification
Implementation
Procedure,
revision dated
March 13,
1989,
table 4.3.6,
requires
that the
channel
calibration for FT-1064
be
performed
at least
once
per
18 months.
Considering
the
25 percent
grace
period from the last performance
date,
the flow transmitter
was required
to
be calibrated
by February
27,
1989.
TS 6.8. 1 requires
that written
procedures
and administrative policies shall
be established,
implemented
and maintained that meet or exceed
the requirements
and
recommendations
of
Appendix
A of USNRC Regulatory
Guide 1.33
and Sections
5. 1 and 5.3 of ANSI
N18.7-1972Property "ANSI code" (as page type) with input value "ANSI</br></br>N18.7-1972" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process..
ANSI
section
5. 1
requires
that
procedures
be
followed.
ADM-021, Technical Specification
Implementation
Procedure,
revision dated
March 13,
1989,
requires
that
the
requirements
of the
Interim
TS
be
complied with unless
the requirements
are either
waived in accordance
with
ADM-021, or are less restrictive than the current
TS.
Table 4.3.6 of the
Interim
TS
requires
that
the liquid radwaste
effluent line flow rate
monitor
be calibrated at least
once per
18 months.
Contrary to the above,
FT-1064
was
not calibrated within the specified
frequency,
and
a waiver
was
not
obtained
in
accordance
with
ADM-021.
This's
a violation,
however,
no notice of violation will be issued
since thi s item meets
the
criteria
specified
in
Appendix
C, for
a licensee
identified
violation.
No violations or deviations
were identified in the areas
inspected.
Monthly Maintenance
Observations
(62703)
Station
maintenance
activities
on safety related
systems
and
components
were
observed
and
reviewed
to ascertain
that
they
were
conducted
in
accordance
with approved
procedures,
regulatory guides,
industry codes
and
standards,
and in conformance with TS.
The following items
were considered
during this review,
as appropriate:
LCOs
were
met while
components
or
systems
were
removed
from service;
approvals
were
obtained
prior
to initiating work; activities
were
accomplished
using approved
procedures
and
were
inspected
as applicable;
procedures
used
were
adequate
to control
the activity; troubleshooting
activities
were controlled
and repair
records
accurately
reflected
the
maintenance
performed;
functional
testing
and/or
calibrations
were
performed prior to returning components
or systems
to service;
gC records
were
maintained;
activities
were
accomplished
by qualified personnel;
parts
and materials
used
were properly certified; radiological controls
were properly
implemented;
gC hold points
were established
and
observed
where
required;
fire
prevention
controls
were
implemented;
outside
contractor
force activities
were
controlled
in
accordance
with the
approved
gA program;
and housekeeping
was actively pursued.
The
inspectors
witnessed/reviewed
portions of the following maintenance
activities in progress:
Repair of 4A HHSI pump.
Troubleshooting
"A" AFW pump
T&T valve.
Troubleshooting Unit 4
PORV Backup Nitrogen Regulators.
No violations or deviations
were identified in the areas
inspected.
Operational
Safety Verification (71707)
The inspectors
observed
control
room operations,
reviewed applicable
logs,
conducted
discussions
with control
room
operators,
observed
shift
turnovers
and
confirmed operability
of instrumentation.
The inspectors
verified the operability of selected
emergency
systems,
verified that
maintenance
work orders
had
been
submitted
as required
and that followup
and prioritization of work was
accomplished.
The
inspectors
reviewed
tagout
records,
verified compliance with TS
LCOs and verified the return
to service of affected
components.
By observation
and direct interviews,
verification
was
made
that
the
physical security plan was being implemented.
Plant
housekeeping/cleanliness
conditions
and
implementation
of
radiological controls were observed.
Tours of the intake structure
and diesel, auxiliary, control
and turbine
buildings
were
conducted
to observe
plant equipment conditions including
potential fire hazards, fluid leaks
and excessive
vibrations.
The
inspectors
walked
down accessible
portions of the following safety
related
systems to verify operability
and proper valve/switch alignment:
A and
B Emergency Diesel
Generators
Control
Room Vertical Panels
and Safeguards
Racks
Intake Cooling Water Structure
4160 Volt Buses
and
480 Volt Load and Motor .Control Centers
Unit 3 and
Platforms
Unit 3 and
4 Condensate
Storage
Tank Area
Area
Unit 3 and
4 Main Steam Platforms
On
March 29,
1989,
the
licensee
shut
down Unit 3.
At 4:53 p.m.,
power
reduction
was initiated per
GOP-103,
Power Operation
to Hot Standby,
and
the unit
was
taken off line at 8:30 p.m.
Unit
4 was already
in cold
shutdown for
a refueling outage.
Unit 3
was
taken off line while the
licensee
assures
itself
of
the
effectiveness
o'f its
operator
requalification training program.
This action
was
taken
as
a result of
deficiencies
identified during requalification testing the previous week.
A Confirmation
of Action Letter
dated
March 30,
1989,
confirms
the
licensee's
commitment
to
take
Unit
3 off line until the
licensee
can
perform special
evaluations
to demonstrate
that operators
not involved in
the
recent
requalification testing
meet
performance
requi elements.
This
effort is expected
to be completed within one week.
On March 2,
1989, with Unit 4 in
Mode 5. and drained
down to the reactor
vessel
the Unit 4 Reactor Control Operator
(RCO) noted
an increase
in the
draindown level.
Investigation
by the operators
found that
the
increase
in level
was
due to unisolating
the
"A" Reactor
Coolant
Pump
(RCP)
seal injection isolation valve (4-298G).
The "A" RCP seal injection
throttle valve (4-297A), which is upstream
of 4-298G,
was
found
open
on
its backseat.
Valve 4-297A was required to be tagged closed in accordance
with
General
Operating
Procedure
(GOP)
4-305,
Hot
Standby
to
Cold
Shutdown,
under
a
cold
shutdown
clearance.
The
licensee
was still
investigating
this
incident
at
the
end
of this
inspection
period,
therefore,
this
item will
be
tracked
as
Unresolved
Item
(URI)
50-250,251/89-12-02.
No violations or deviations
were identified in the areas
inspected.
Plant Events
(93702)
The following plant events
were reviewed to determine facility status
and
the
need for further followup action.
Plant
parameters
were
evaluated
during transient
response.
The significance of the event
was
evaluated
along with the
performance
of the
appropriate
safety
systems
and
the
actions
taken
by the
licensee.
The
inspectors
verified that
required
notifications were
made to the
NRC.
Evaluations
were performed relative
to the
need for additional
NRC response
to the event.
Additionally, the
following issues
were
examined,
as
appropriate:
details
regarding
the
cause
of the event;
event chronology; safety
system performance;
licensee
compliance with approved
procedures;
radiological
consequences,
if any;
and proposed corrective actions.
At
8: 15 a.m.
on
March 9,
1989,
the
licensee
declared
and
terminated
simultaneously
an
unusual
event after finding
Unit 4 drain valve
201B
open
and draining reactor
coolant to the containment
sump.
Unit 4 was
in
cold shutdown
and the licensee
was filling and venting the reactor coolant
system
per
4-0P-041.8.
Section
5.2.2. 15
requires
increasing
reactor
pressure
to
125 psig.
Due to the slow response
on pressure
increase,
at
5:45 a.m.,
an N.O.
was instructed to look for leaks or misaligned valves.
At
6: 15 a.m.,
valve
4-201B,
letdown
orifice
downstream
drain,
v:as
discovered
open with
a tygon tube
vent rig installed.
The tygon tubing
was
routed to drain to the containment
sump.
The valve
was
immediately
closed.
The Unit 4 containment
level
instrumentation
was
out of
service
for maintenance.
Health
physics
reported
the
containment
level
was at
67
inches
following this event
which corresponds
to
a
inventory of approximately
9926
gallons.
The leak rate
was originally
estimated
at approximately
39.8
gpm.
Later calculations
indicate the leak
rate
was
probably closer to
11
gpm.
Based
on
an estimated
39
gpm, at
6:58 p.m.
per
the
log,
emergency
notification
should
have
been
initiated per the licensee's
Emergency
Plan
Implementing
Procedure
(EPIP)
20101.
Paragraph
3.2 of
20101,
requires
declaration
of an
unusual
event if reactor coolant
system water inventory indicates
leakage
greater
than
10
gpm.
The licensee's
promptness
on reporting this event will be
discussed
in
Inspection
Report
50-250,251/89-08.
The
licensee
has
initiated
an
Event
Response
Team
(ERT)
to
review
the
circumstances
regarding
this
event
and
determine
the
cause
and
recommend
corrective
actions to prevent recurrence.
Preliminary investigation
has
shown that
a
drain rig was installed
on valve
201B on December
3,
1988, to permit work
on valves
CV-200A and
C.
No documentation
exists
showing this drain rig
was
ever
removed.
On January
13,
1989,
an
LLRT for valves
200A,
B and
C
was conducted
which required valve
201B to
be closed
and/or
capped.
The
clearance
for this test did not address
the
201B valve.
On January
17,
1989, operations verified valve
201B closed with independent verification.
Again
on
March 5,
1989,
operations
verified
valve
201B
closed
with
independent
verification.
On March 8,
1989,
at 3:00 p.m.,
the licensee
initiated fill and vent of the
RCS,
per 4-0P-041.8,
and control
valves
CV-200A,
B and
C were
opened
which would allow
RCS water to fill the
piping which valve
201B drains.
Paragraph
3. 1 of 4-0P-041.8
requires
the Chemical
and Volume Control System
be operable
or in operation.
Calculations
indicate
valve
201B was
open at the time
CV 200A,
B, and
C
were
opened
permitting
RCS water to drain to the containment
sump.
On
March 9,
1989, at 6: 15 a.m.,
valve 201B was found open
as stated earlier.
Operations
had conducted
procedure
OSP-041. 1, Reactor Coolant System
Leak
Rate Calculation,
on March 8,
1989, at 5:30 p.m.,
and
March 9,
1989, at
5:00 a.m.,
and failed to identify that valve
201B was
open
and draining
RCS water.
TS 6.8. 1 requires that written procedures
and administrative
policies
shall
be established,
implemented
and maintained that
meet or
exceed
the
requirements
and
recommendations
of Section
5. 1 of
ANSI
N18.7-1972Property "ANSI code" (as page type) with input value "ANSI</br></br>N18.7-1972" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process..
ANSI
N18.7-1972Property "ANSI code" (as page type) with input value "ANSI</br></br>N18.7-1972" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process.,
section
5
~ 1.2
specifies
that
procedures
shall
be followed.
Operating
Procedure
4-0P-047,
CVCS-Charging
and
Letdown,
requires
valve
'-201B
to be closed
as its normal position.
Contrary to the above,
valve
201B was found open with no written clearance
to place
the valve in the
open position.
Failure to follow procedures
and maintain valve
201B in
the closed position will be identified
as violation 50-250,251/89-12-03.
Problems
with configuration control
have
been identified in previous
NRC
inspection
reports
and
have resulted
in violations being
issued.
Due to
NRC
concerns
in this
area
and
since
a root
cause
has
not yet
been
identified, this will be cited as
a separate
violations
9.
Installation
and Testing of Modifications (37828)
An
inspection
was
conducted
to
ascertain
the
licensee's
methods
of
assuring that'esign
changes
and modifications
meet the
requirements
of
Technical
Specifications,
and
Appendix B,
Criterion III.
Each
of the
PC/M
packages
contained
a written safety
evaluation
which concluded
that
the
change
could, be
implemented without
prior
NRC
approval
under
the
provisions
of
Each
modification resulted
in the respective
system,
as described
in the
FSAR,
being
changed
to provide
increased reliability or maintainability.
None
of the
PC/Ms required
change
to the facility Technical
Specifications.
The
inspectors
verified
by direct observation
that the
work was being
performed
by
qualified
workers
and
in
accordance
with
approved
instructions
and drawings contained
in the work package.
The installation
of the
hardware
was verified to
be
in
accordance
with the
as-built
drawings.
Installation, preoperational,
and startup testing
were adequate
to ensure
that the
system/equipment
met the
performance
requirements
of
the design criteria.
The following modification was reviewed during this
inspection
period:
PC/M 87-100,
Turkey Point Unit 4 Reactor Cavity Seal
Replacement
(REA-TPN-86-83).
This
PC/M provided for the
replacement
of the Unit
4 reactor
cavity seal
system
and the install-ation of
a restraint
system
for the reactor cavity seal
ring plate in its storage location.
The
seal
system
was modified to provide redundant
passive
seals
to prevent
leakage
in excess
of 50
GPM, which is well within the
capacity of the two 75
GPM reactor
pumps
and also provides
an acceptable
rate of level decrease
in the reactor cavity/spent
fuel
pool levels (2 inches/hour)
allowing for adequate
operator
response
time.
This modification also
provided
an inflatable
seal
to reduce
primary seal
leakage
to as
low as practical (less
than
1
GPM) for housekeeping
and- ALARA concerns.
The non-safety
related
inflatable
seal
is also
provided with
a
continuous
pressurization
system.
The
package
also
addressed
the
replacement
of twelve reactor cavity seal ring anchor bolts with
grout-in-place
type anchor bolts.
10
In addition to the
PC/M the following procedures
were reviewed to ensure
this
new seal
design
was included:
O-GMM-043.6, Reactor
Vessel
Cavity Seal
Ring Installation
r
4-OP-038. 1, Preparation
for Refueling Activities
4-0P-201,
Filling/Draining the
Refueling
Cavity
and
the
Transfer Canal.
During the review of this PC/M,
one concern
was identified in that testing
of the
passive
seals
subsequent
to the initial installation test
may not
be adequate.
This item was discussed
in Inspection
Report
88-39
and
was
promptly corrected
by the licensee.
No violations or deviations
were identified in the areas
inspected.
10.
Management
Meeting (94702)
On March 16,
1989,
the bi-monthly NRC/FPL Management
Meeting was conducted
at the site.
This
was
the
tenth
in
a
series
of'eetings
which were
initiated by Enforcement
Action (EA) 87-85
issued
in October
1987.
The
meeting
was attended
by
NRC Regional
and
Headquarters
Management
and
Site
and
Corporate
Management.
The topics of discussion
included:
Plant
Status;
RHR draindown event of of January
19,
1989; Thimble tube cracks
on
Unit 3 seal table;
procurement of spare
parts for maintenance;
maintenance
improvement efforts;
and
new security initiatives.
11.
Exit Interview (30703)
The
inspection
scope
and
findings
were
summarized
during
management
interviews
held throughout
the reporting
period with the Plant Manager
Nuclear
and selected
members of his staff.
An exit meeting
was
conducted
on
March 31,
1988.
The
areas
requiring
management
attention
were
reviewed.
No proprietary
information
was
provided
to
the
inspectors
during the reporting period.
The inspectors
had the following findings:
50-250,251/89-12-01,
Inspector
Fol 1 owup Item.
Possible
improper
oil level in the
AFW pump governor.
(Paragraph
5)
50-250,251/89-12-02,
Unresolved
Item.
seal
injection
throttle
valve
4-297A in the
open
position
contrary
to
4-305,
resulting
in inadvertent
increase
in drain
down water
level.
(Paragraph
7)
50-250,251/89-12"03,
Violation.
Failure
to follow procedures
resulting in valve 201B being
open
and draining
RCS water to the
containment
sump.
(Paragraph
8)
Licensee
Identified Violation.
Failure to calibrate the liquid
radwaste
effluent
line
flow transmitter
at
the
frequency
specified
by ADM-021.
(Paragraph
5)
11
12.
and Abbreviations
ADM
a.m.
ANSI
CCTY
CFR
DP
ERT
ICW
IEB
IFI
LCO
LER
LIV
NO
NRC
'ONOP
OP
OTSC
PC/M
p.m.
PNSC
RCO
TS
Administrati ve
ante
meridem
American National
Standards
In
Administrative Procedures
American Society of Mechanical
Component
Cooling Water
Closed Circuit Television
Code of Federal
Regulations
Containment
Spray
Differential Pressure
Emergency Notification System
Emergency
Plan
Implementing
Pr
Event
Response
Team
Florida Power
& Light
Final Safety Analysis Report
High Head Safety Injection
Intake Cooling Water
Inspection
and Enforcement
Bul
Inspector
Followup Item
Limiting Condition for Operati
Licensee
Event Report
Licensee Identified Violation
Local
Leak Rate Test
Loss of Coolant Accident
Maintenance
Procedures
Non-conformance
Report
Nuclear
Operator
Net Positive Suction
Head
Nuclear Regulatory
Commission
Off Normal Operating
Procedure
Out of Service
Operating
Procedure
On the Spot
Change
Protected
Area
Plant Change/Modification
post meridiem
Plant Nuclear Safety
Committee
Plant Supervisor
Nuclear
Physical
Security Procedures
Quality Assurance
Quality Control
Reactor Control Operator
Pump
Reactor
Coolant System
Residual
Heat
Removal
Senior Reactor Operator
Technical Specification
Temporary
System Alteration
Unresolved
Item
stitue
Engineers
ocedure
letin
on