ML17342B128
| ML17342B128 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 02/03/1988 |
| From: | Brewer D, Crlenjak R, Mcelhinney T, Schnebli G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17342B125 | List: |
| References | |
| TASK-2.F.2, TASK-TM 50-250-87-51, 50-251-87-51, IEB-87-002, IEB-87-2, NUDOCS 8802100116 | |
| Download: ML17342B128 (22) | |
See also: IR 05000250/1987051
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323
Report Nos.:
50-250/87-51
and 50-251/87-51
Licensee:
Florida Power and Light Company
9250 West Flagler- Street
Miami,
FL
33102
Docket Nos.:
50-250
and 50-251
License Nos.:
and
Facility Name:
Turkey Point
3 and
4
Inspection
Conducted:
November
23 - December
28,
1987
Inspectors
D.
R. Brewer
Senior Resident
Insp
tor
.
F.
McE hinn y, Resident
Inspecto
G.
'.
S
n li, Resi ent Inspector
at
Signed
2-
Pp
Date
igned
z/z, t~
Date Signed
Approved by:
r
R.
V. Crlenja
, Section Chief
Division of Reactor Projects
at
Signed
SUMMARY
Scope:
This routine,
unannounced
inspection
entailed direct
inspection
at
the site,
including backshift inspections,
in the areas
of annual
and monthly
surveillance,
maintenance
observations
and reviews,
engineered
safety features,
operational
safety, facility modifications
and plant events.
Results:
One violation with two examples for failure to meet the requirements
of Technical Specification 6.8. 1 was identified (250, 251/87-51-01).
aao
>00~1~
8SQ
Q~I
ADOCK 05000P50
8
REPORT
DETAILS
Persons
Contacted
Licensee
Employees
J.-.
S.
Odom, Vice President
"C. J.
Baker, Plant Manager
Nuclear
- L. W. Pearce,
Operations
Superintendent
"T.,A. Finn, Training Supervisor
J.
D. Webb, Operations
Maintenance
Coordinator
- W. R. Williams, Assistant Superintendent
Planned
Maintenance
D. Tomasewski,
Instrument
and Control (IEC) Department
Supervisor
J.
C. Strong, Electrical
Department Supervisor
- L. W. Bladow, Quality Assurance
(QA) Superintendent
E.
F. Hayes, Quality Control
(QC) Supervisor
"R. J. Earl,
QC Supervisor
"J.
A. Labarraque,
Technical
Department
Supervisor
R.
G.
Mende,
Operations
Supervisor
- J. Arias, Regulation
and Compliance Supervisor
R.
D. Hart, Regulation
and Compliance
Engineer
"G. Solomon,
Regulation
and Compliance
Engineer
J.
Donis, Engineering
Department
Supervisor
D.
E.
Meils, Chemistry
Supervisor
Other
licensee
employees
contacted
included
construction
craftsmen,
engineers,
technicians,
operators,
mechanics,
and electricians.
"Attended exit interview on December
31,
1987
Exit Interview
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
December
31,
1987.
The
areas
requiring
management
attention
were
reviewed.
No proprietary
information
was
provided to the
inspectors
during the reporting period.
Unresolved
Items (URI)
Unresolved
items
are
matters
about
which
more
information is required
to determine
whether
they
are
acceptable
or may involve violations of
requirements
or deviations
from commitments.
No unresolved
items
were
identified in this report.
Followup
on
Unresolved
Items
(URIs),
Inspector
Followup
Items (IFIs),
Inspection
and Enforcement
Information Notices (IENs), IE Bulletins (IEBs)
(Information Only), IE Circulars (IECs),
and
NRC Requests
(92701)
(Closed)
250,251/86-39-05.
The
licensee
failed to
complete fire
protection modifications
on several
Unit 4
raceways
and
several
common
seals
by the scheduled
completion date.
On October
10,
1986,
the licensee
submitted
a letter (L-86-410), which reported the items which
would not be completed
by the required dates of September
30 and October
1,
1986.
On November
3,
1986,
the licensee
provided
an update letter (L-86-
451)
on the outstanding
Unit 4 electrical
conduit protection
and
common
unit penetration
seal
work.
All remaining
open
items of this
URI were
completed
November
12,
1986.
This item is closed.
(Closed)
URI 250,251/86-33-07.
Adequacy
of the
fuse
control
program.
This unresolved
item will be administratively closed
and corrective action
on violation 250,251/87-39-01,
for failure to maintain control of fuses in
accordance
with
approved
procedures,
will
be tracked'his
item is
closed.
(Closed) IFI'50/84-23-19
and
251/84-, 24-19.
Provide
response
addressing
what reviews
are
being
done to assure
that design deficiencies
have not
occurred
in the routing of power to miscellaneous
relay rack equipment
which
may require safety-related
power sources'he
licensee
in letter
(L-85-321),
dated
August 20,
1985,
stated
that the design deficiency in
question
was identified during
an
engineering
review of the auxiliary
power
upgrade
("C-Bus" modification) at Turkey Point.
The licensee
has
also
performed
other'eviews,
such
as
the
System
Operability
Review
Program
(SORP)
and
the
Appendix
R Safe
Shutdown circuit review, that
included the consideration
of power to selected
safety-related
equipment.
This item is closed.
(Closed)
IFI 251/84-23-05.
Investigate
the
Spent
Fuel Pit Ventilation
System.
On January
29,.
1985,
Bechtel
Power Corporation
provided
a
response
on
the
spent
fuel pit ventilation
location.
Bechtel
recommended
that
a damper
be
added at the discharge
of Unit 4's exhaust
fan for
ALARA considerations.
Additionally, Bechtel
states
that
the
existing condition does
not constitute
an unreviewed safety question or a
potential
hazard
to the
public
because
the existing
isolation
provides
a physical
boundary to the Spent
Fuel Pit air space.
This'item
is closed.
(Closed)
IFI 250,251/84-18-06.
A number of discrepancies
in the
Spent
Fuel
Pool
area
were identified including physical
and procedural
discrep-
ancies.
In
an inter-office correspondence,
dated
January
14,
1985,
the
licensee
addressed
each
item.
A number .of procedures
were
developed
to govern the operation of the Spent
Fuel Pit, these
procedures
include,
3/4-OP-033 -
Spent
Fuel Pit Cooling
System,
3/4-OP-038. 1 Preparation
for Refueling Activities, 3/4-OSP-034.
1 - Spent
Fuel Pit Inlet and Exhaust
Operability
Test,
Spent
Fuel Pit Ventilation Exhaust
System
Air Flow Test,
3/4-0NOP-033.3
Accidents
Involving
New
or
Spent
fuel
and
3/4-ONOP-067.
Inadvertent
Release
of Radioactive 'Gas.
Additionally,
a
number
of
system
modifications
were
performed.
They
include the following:
installed
new level indications,
replacement
of
Spent
Fuel Pit Overhead
Crane
Access
Door Seal,
replaced
the air driven
transfer cart with an electrically driven transfer cart,
and the comple-
tion of a modification on Fuel Transfer System for crane
dual cable.
This
item is closed.
(Closed) IFI 250,251/86-30-03.
Review the engineering
evaluation of noise
in the
steam flow arid pressure
signals.
The licensee
'developed
a
Design
Equivalent Engineering
Package
to redesign
the supports for the Main Steam
Flow Transmitter
Lines
(DEEP 87-328),
dated October 6,
1987.
The packages
safety
evaluation
states
that this modification will reduce
the tubing
vibration problem which appears
to be causing
high spi king of the reactor
protection
system.
This item is closed.
(Closed)
IFI 250/84-22-04.
Items
(components,
system,
etc.) of signifi-
cance
which are
not included in the
Technical
Specifications
(TS) but
are in the the standard
TS will be identified and maintained
on
a priority
basis.
The licensee
has submitted to the
NRC its standard
TS for approval.
Additionally, procedure
O-ADM-701, Plant Work Order Preparation,
continues
prioritization methods
for all plant equipment
including time limits for
starting the work.
This item is closed.
Onsite
Followup and In-Office Review of Nonroutine Events
(92700/92712)
The
Licensee
Event
Reports
(LERs)
discussed
below were
reviewed
and
closed.
The inspectors verified that reporting requi'rements
had been
met,
root cause analysis
was performed, corrective actions
appeared
appropriate,
and generic applicability had been considered.
Additionally, the inspectors
verified that the
licen'see
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.
(Closed)
Technical
Specification
(TS)
exceeded
when
three charging
pumps were inoperable.
On September
25,
1986, while Unit 3
was at
100% power, with the
3A and
3B charging
pumps out of service for
maintenance,
the
3C charging
pump
was isolated during the testing of the
3B charging
pump.
The
3B charging
pump failed its acceptance
criteria,
resulting
in the
24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Limiting Condition of Operation being exceeded.
The cause of the failure was
a leaking relief valve
on
3C charging
pump.
The relief valve for
3C charging
pump
and
the
suction
valves
on
3B
charging
pump
were rebuilt.
Both
pumps
were satisfactorily
tested
and
returned to service.
This item is closed.
(Closed)
Both Emergency
Diesel
Generators
(EDG) Out of
Service.
The 'B'DG was out of- service for instrument calibrations
in
preparation
for performing its eight
hour test
run.
The 'A'DG was
started to verify its operability and,
when completing its test
run, it
would not stop.
An Event Response
Team was formed to determine
the cause
of the 'A'DG failure.
The
cause
was determined
to
be the governor
solenoid
was out of adjustment.
The governor
solenoid
was adjusted
and
the 'A'DG was declared
back in service
on
November
7,
1986.
Preventa-
tive
maintenance
procedure
0-PMI-023. 1,
Emergency
Diesel
Generator
Instrumentation
Calibration,
was revised to include the governor
solenoid
adjustment.
This item is closed.
(Closed)
Potential
4160 Volt Bus
and
Emergency
Diesel
Generator
Lockout.
On August 15,
1986, the licensee
discovered
two types-
of devices
whose postulated failure could adversely'ffect
the ability of
safety related
equipment
to perform their intended
safety function.
An
auxiliary overcurrent
relay
(174X/TDDO) located
on
each
4160 volt tie
breaker
could fail resulting
in the
opening of the
supply breakers,
including the
EDG breakers'dditionally,
failure of auxiliary switches
of the
EDG supply breaker
switch contacts
(1-1T or 3-3T) could provide
a
false input to the
EDG failure circuit in the load sequencer,
which would
block loading of the battery chargers.
The licensee
performed
a Temporary
System Alteration to disable
the
174/TDDO relays.
A training brief was
written to alert the operators
of the potential failures of the relays.
Emergency
Operating
Procedures
3/4-EOP-E-O,
Reactor
Trip
or
Safety
Injection,
and
EOP-ES-0. 1, Reactor Trip Response,
were revised to ensure
that the battery
chargers
are
energized
within 30 minutes.
This item is
closed.
(Closed)
Single Failure in the Control
Room Ventilation
System
(CRVS) May Result in Loss of Control
Room Ventilation
System.
The
licensee
determined that if a loss of power to the motor control center
(MCC) 3A occurred
and the transfer switch sticks between its two position
(MCC
3A and
MCC D),
no control circuit power will be available
and the
CRVS air conditioning compressors
and air handlers
would be disabled.
The
licensee
has taken the following corrective action;
0-OSP-200. 1,
Schedule
'of Plant Checks'nd
Survei llances,
has
been revised to verify operability
of the transfer
switch weekly; quick-connect
jumpers
have
been installed
around the control circuitry for the air conditioner compressor
units not
connected
during
normal plant operation;
Training Brief 186
was
issued;
the transfer
switch cover-plate
was modified to increase
clearance;
and
finally, PC/M 87-243, Transfer Switch Upgrade for OP-312A and
DP-412A was
developed
to provide
a permanent fix and the schedule for implementation
is being tracked in the integrated. schedules.
This item is closed.
Followup of 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 in the reply.
(Closed) Violation 250,251/86-39-01.
Inadequate
Procedure,
two examples.
Temporary Operating
Procedure
(TOP) 233, Functional Test of PC/M 84-209-
Power Mismatch Modification and
PC/M 84-211
Turbine Runback Modification
was inadequate
in that performance of procedure
steps
8.5 and 8.29 resulted
in
an
unplanned
actuation
of the reactor protection
system.
The
second
example
was that
no plant
procedure
existed
specifying
the
method
by
which fire doors
shall
be controlled.
The
licensee
revised
procedure
and
successfully
performed
the functional test.
The
licensee
developed
procedures,
ASP-31, Breaching of Fire Protection
System
and Fire
Rated
Assemblies
and
O-SMM-016.6,
Fire
Door Inspection,
to help control
fire doors.
Additionally, fire doors
have
been
painted
red
and
signs
requiring closure
have
been placed
on them.
This item is closed.
(Closed)
Violation 251/86-33-05.
Failur e to follow AP-0103.4,
In-Plant
Equipment
Clearance
Order
and
AP-0103.32,
Reactor
Cold Shutdown
Condi-
tions.
The individual involved in failure to follow procedure
AP-0103.4
was counseled
and shift briefing, to reemphasize full compliance with the
equipment
clearance
procedure,
was
given to all operators.
Procedure
AP-0103.32
was
revised
to clarify the
requirements
for Residual
Heat
Removal
(RHR) loop operability.
This item is closed.
(Closed)
Violation 250,251/86-33-04.
Drawing
5610-T-D-18B,
Revision
1,
Steam
Break Protection,
was not accurate.
Drawing 510-T-D-18B was revised
on July 22,
1986, to correct
the inaccuracies.
Additionally, under the
Performance
Enhancement
Program
the
licensee
is updating all drawings
under the select
system review.
This action is tracked
by the Integrated
Schedule.
This item is closed.
(Closed)
Violation 250,251/86-33-03.
Adequate
procedures
did not exist
to control
deluge
system
valve
line-ups,
including
pressure
switch
isolation valves.
0-OP-016. 1, Fire Protection
Water System,
was revised
to incorporate
deluge
system
valve line-ups.
Additionally, drawings
on
the fire protection
system
wer'e revised to reflect the valve line-ups.
This item is closed.
(Closed) Violation 250,251/86-33-02.
The licensee failed to take adequate
measures
to assure
that conditions
adverse
to quality were promptly iden-
tified and corrected,
in that
a Unit 3 pressure
transmitter
495 failed
for 20
seconds
and the actions of ONOP-0208. 14, Deviation or Failure of
Reactor
Protection
and
Safety-Related
Hagan
Instrumentation
Channels,
were not implemented
and the licensee
failed to evaluate
the potential
for additional
losses
of all
control
room
lighting.
The, licensee
completed
the following actions;
the instrument
loop was checked out and
the affected transmitter
was replaced,
additionally, the transmitter
was
returned
to
the
vender
for examination;
ONOP-0208. 14
was
revised
to
clarify the requirements
for channel
spiking; the train of control
room
emergency
DC lighting that
had failed was repaired
by July 22;
1986,
and
the
DC lighting that
was out of service for modifications
was returned
to service
July 19,
1986;
and finally, shift briefings
were
held
in
October
1986.
This item is closed.
h
7.
(Closed) Violation 250/85-24-03.
Failure to perform the accumulator
concentration
analysis
prior to heating
up
above
200
degrees
F.
This
violati on
wi 1 1
be
admini strati vely cl osed
and
the
corrective
acti on
tracked
under the corrective actions for violation 251/87-35-01,
which is
a repeat of the above violation.. This item is closed.
(Closed)
Violation 250,
251/87-44-03.
Two examples
of failure to meet
the requirements
of
TS 6.8. 1.
Example
one,
on
numerous
occasions
shift
relief turnovers
were not documented
in the
Reactor
Operator's
logbook
and checklists
were
not properly
and thoroughly completed
as required
by
AP-0103.2, Shift Turnover Requirements.
Example
two, actions
were taken
under
the
guidelines
of Procedure
O-ADM-207, Operation Instructions
in
the
Event of
a Situation
not Addressed
by Procedures,
which were
not
promptly recorded
in the Plant Supervisor's
logbook.
This violation with
two examples is administratively closed
and will be opened
under violation
250,
251/87-51-01.
For
further
detai
1
of
the
violati on
refer
to
inspection report 250, 251/87-44.
Monthly and Annual Sur'veillance Observation
(61726/61700)
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.
e'he
inspectors
witnessed/reviewed
portions of the following test activities:
4-OSP-075.
1
Train
1 Operability Verification.
4-0SP-075.2
Auxiliary FeedwaterTrain
2 Operability Verification.
4-0SP-075.6
Auxiliary Feedwater Train
1 Backup Nitrogen Test.
4-0SP-075.7
Train
2 Backup Nitrogen Test.
0-OSP-075. 11
Inservice Test.
No violations or deviations
were identified within the areas
inspected.
Maintenance
Observations
(62703/62700)
Station
maintenance
activities of 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:
that- LCOs were met while components
or systems
were removed
from service;
that approvals
were obtained prior to initiating work; that activities
were
accompl.ished
using
approved
procedures
and
were
inspected
as
applicable;
that procedures
used
were
adequate
to control
the activity;
that
troubleshooting
activities
were
controlled
and
repair
records
accurately
reflected
the maintenance
performed;
that
functional
testing
and/or
calibrations
were
performed
prior to returning
components
or
systems
to service; that
gC records
were maintained; that activities were
accomplished
by qualified personnel;
that parts
and materials
used
were
properly certified; that, radiological controls were properly
implemented;
that
gC hold points
were established
and
observed
where required;
that
fire prevention controls
were
implemented;
that outside
contractor
force
activities were controlled in accordance
with the approved
gA program;
and
that housekeeping
was actively pursued.
a.
Unit 3 and
4 Condensate
Storage
Tank (CST) Holddown Nuts
On
November 5,
1987,
with both units
in
Mode 5,
a
me'mber of the
Technical
Department 'identified
loose
nuts
on Unit 4
CST anchor
bolts.
Subsequently,
the
same
condition
was
found to exist with
the Unit 3
CST.
Plant
Work Order
(PWO)
WA873091022
was immediately
generated
to document the
problem
and questioned
CST seismic struc-
tural
integrity
and
operability.
Non-Conformance
Report
(NCR)
87-0240
was written
on
November
12,
1987,
to identify the
problem
to engineering
for
an
as-found
evaluation
and corrective
action.
Engineering
provided
an .initial
assessment
of
operability
on
November
16,
1987,
which stated:
"The condensate
storage
tanks are
not required to be operable
when the units are in Mode 5.
Therefore,
there is
no operability concern.
Disposition
NCR prior to leaving
Mode 5."
The disposition contained
in the
NCR required
measurements
of the, existing
condition for later evaluation
and
the
immediate
corrective
actions
required to repair the
nonconforming
condition.
The
NCR was also
entered
on the
gC NCR-Open
Item Status
Report with
an action
due date of November 28,
1987,
and
a note to complete prior
to Mode 4.
Unit 4 entered
Mode 4 at
1315
on
November 29,
1987,
then
Mode
3
't
0430
on
November 30,
1987.
At 0001
on
December
1,
1987, it was
discovered
that
the corrective
actions
for the
had
not
been
accomplished.
Engineering
was
immediately contacted
for short term
corrective
action to determine
the
since
the unit had
left Mode
5 without implementation
of the requirements
of the first
disposition of the
NCR.
Engineering
provided additional
corrective
actions required to ensure operability until an in depth analysis
was
conducted
to determine operability in the as-found condition.
These
actions required that all anchor nuts
be torqued to
a
snug tight fit,
then
each
anchor bolt/nut could
be worked
one at
a time to return
them to their original design configuration without affecting tank
operability.
The corrective
actions
were
completed
and
the
data
requested
by
the initial disposition
on the
NCR was returned
to engineering
to
allow for later determination
of tank'perability in the as-found
condition.
The licensee's
Technical
Department
formally requested
the. Engineering
Department,
by memorandum
dated
December
10,
1987, to
expedite
the as-found evaluation to ensure
compliance with Technical
Specification
3. 19. 1. 1
and
3.0.4
were
met.
In addition,
10 CFR Part 50.72 requires
a licensee
to notify the
NRC if they discover
a
condition while the
reactor
is
shutdown,
that,
had it been
found
while the
reactor
was
in operation,
would
have
resulted
in the
nuclear
power plant being in
a condition outside its design
basis.
The engineering
evaluation
was
completed
on
December
23,
1987,
and
determined that both
in their as-found condition.
The inspectors
conducted
several
discussions
with responsible
licensee
personnel
in Maintenance,
Operations,
Engineering
and guality Control
to determine
the root cause
and corrective actions
to prevent
mode
changes
without all work being completed.
The discussions
indicated
that this was
an isolated occurrence
and although the licensee
has
a
program to track NCRs, versus
Mode required by, it may not have
been
sufficient as the problem did occur.
When this issue
was identified
by the licensee,
gC immediately modified the format of the
NCR-Open
Item Status
Report to-include
a separate
column for the required
Mode
versus
a
note
as
previously
discussed.
In addition, all
General
Operating
Procedures
(GOPs)
which direct
Mode
Changes,
will
be
modified to
include
a
step that
ensures
all maintenance,
testing,
NCRs, etc.,
are complete
and verified prior to the
Mode change.
The
inspectors
consider
that these
changes will prevent
recurrence
of
this issue.
Unit 4 Intake Cooling Water
Pump
(ICW) Troubleshooting
At 1535
on
December
18,
1987, 'with 4A and
4C
ICW pumps in service,
Unit 4 experienced
the
loss
of the
4C
pump.
Several
attempts
to
start
the
4B pump failed.
At that point both the
4B and
4C
pumps
were declared
and the licensee
commenced
a unit shutdown
in accordance
with Technical Specification 3.0. 1.,
although
the
4A
ICW
pump
was
capable
of supplying all
loads.
The
ICW system at
Turkey Point consists
of 3 pumps that can feed two
ICW headers.
The
4A ICW pump is powered
from the
4A 4160 volt safety-related
bus.
The
4B and
4C
ICW pumps are
powered
from the
4B 4160 volt safety-related
bus.
At that
time both
the
A and
B
emergency
diesel
generators
(EDGs)
were
and
capable
of
supplying
reliable
onsite
emergency
power
to their
respective
busses.
At this
time
NRC
Region II was contacted
regarding
the application
of discretionary
enforcement
to allow the licensee
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to return the
4B and
4C
ICW pumps
to service.
This
24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> extension
was
granted with the
stipulation that
upon
any evidence
of common
mode failure the unit
would be immediately shutdown.
The current Technical
Specifications
require all three
ICW pumps to
be
and allow only
one
ICW pump to
be
for 24
hours.
The specifications
do not allow any credit for ICW electrical
trains.
Additionally, they
do not provide
an action
statement
for
this condition
so
a unit shutdown
commenced
approximately
one
hour
after declaring the
4B and
4C
ICW pumps out of service
The Standard
Technical
Specifi'cations
(STS),
including the
FPL submitted
version
under the
Performance
Enhancement
Program,
would allow 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> of
operation with one
ICW train out of service.
An extensive, 'coordinate
effort was
undertaken
by the licensee
to
restore
the
two inoperable
pumps to service.
Investigation into the
. failure of the
4C
ICW pump revealed
the
upper coupling
had broken.
The material
used for this coupling (17-4
pH)
had previously
been
identified by the licensee's
engineering
department
as
susceptible
to corrosion failure'nd were being replaced
on
a per
pump basis with
made of Nitronic 50 which is much less susceptible
to this
type 'of failure.
The previous fai lure which identified this problem
was documented
in
A review of documentation
deter-
mined all the couplings
on the running
4A ICW pump
had previously been
replaced
with the
new material.
The investigation
into the failure
of the
4B
ICW pump revealed that the bronze
bushing at the stuffing
box
had
bound to the shaft.
Evaluation into this failure is sti 1 l
ongoing.
The
upper coupling
on the
4C
ICW pump was
replaced with
the
improved coupling material.
The
4C
ICW pump was satisfactorily
tested
and placed back in service early in the morning of December
19,
1987,
thus relieving the requirement for discretionary
enforcement.
The
4B
ICW pump
was
replaced with a spare
pump.
This
pump was then
satisfactorily
tested
on
the
afternoon
of
December
19,
1987,
and
placed
back
in service
prior to exceeding
the current
Technical
Specifications
action statement
and the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> extension
allowed
by
the discretionary enforcement.
No violations or deviations
were identified within the areas
inspected.
9.
Engineered
Safety Features
Walkdown (71710)
The inspectors
performed
an inspection
designed to verify the operability
of the Unit 3 and
4 Component
Cooling Water System.
This was accomplished
by
performing
a
complete
wal kdown
of al 1
accessible
equipment.
The
following criteria were used,
as appropriate,
during this inspection:
a.
b.
C.
Systems
lineup procedures
match plant drawings
and
as built configu-
ration.
Housekeeping
was
adequate
and
appropriate
levels
of cleanliness
are being maintained.
Valves
in the
system
are
correctly installed
and
do
not exhibit
signs
of gross
packing
leakage,
bent
stems,
missing
handwheels
or
improper labeling.
10
d.
Hangers
and supports
are
made
up properly and aligned correctly.
e.
Valves in the flow paths
are in correct position
as required
by the
applicable
procedures
with power available
and valves
were locked/
lock wired as required.
f.
Local
and remote position indication
w'as compared
and remote instru-
mentation
was functional.
g.
Major system
components
are properly labeled
The
inspectors
reviewed
procedures
3,4-0SP-030.3,
entitled
Component
Cooling Water System
Flowpath Verification, revisions dated. June
18,
1987
and
September
18,
1987, for Units
3
and
4, respectively.
The'nspectors
also
reviewed
the
applicable
operating
diagram
5610-T-E-4512,
sheet
1,
revision 53.
The inspectors
did not note
any adverse
conditions during . the
walkdown.
During this past
outage
the licensee
has
performed
numerous
maintenance
activities
on the Unit 3
and
4
CCW system
which includes
eddy current
testing
and plugging of defective
tubes
in the
CCW heat
exchangers,
and
replacement
of CCW surge lines that were experiencing
external
corrosion.
The licensee-also
made
two enhancements
to the
CCW system which includes;
the change of corrosion inhibitors in the
CCW from chromates
to molybdates
for environmental
considerations
and the
change
in operating
procedures
which allows the running of one
CCW pump instead of two with the plant in
Mode 5.
This change is designed
to decrease
flow induced vibrations which
could damage
the
CCW heat exchanger
tubes.
No violations or deviations
were identified within the areas
inspected.
Facility Modifications (37701)
The inspectors
reviewed
the facility modification to install the Reactor
Vessel
Level Monitoring System
(RVLMS), which satisfies
the requirements
of NUREG-0737,
Item II.F.2,
Inadequate
Core Cooling Instrumentation
System
(ICCI).
The
NRC
found
the
licensee's
submittals
for the'esign
and
installation of
RVLMS to
be acceptable
in
a letter
and attached
safety
evaluation
dated January
28,
1985.
The installation, functional testing,
and calibration of the
RVLMS portion
of the
ICCI system
were
completed
by December
16,
1983, for Turkey Point
Unit 3 and
May 25,
1984, for Unit 4.
The plant specific Technical
Speci-
fications for the
RVLMS was
incorporated
in
Change
155
(Amendment
125
for Unit 3 and Amendment
119 for Unit 4)
on July 28,
1987.
The inspectors
reviewed Plant
Changes
and Modifications packa'ges
(PC/M)81-162
and
81-167
which installed
the
ICCI
system
instrumentation
on
Units
3
and
4, respectively.
The
PC/Ms
were
implemented
in accordance
with the
licensee's
Administrative Procedure
0190. 15,
including changes
to the original
PC/M.
The documents
received the proper level of
review'nd
contained
the -required
safety
evaluations.
FSAR evaluations
were
conducted
and the
FSAR was
updated
with Revision 4,
dated July 1986, to
reflect the
new system.
The following procedures
were reviewed to ensure
the
new surveillance
requirements
were included:
a.
O-PMI-041.3
Incore
Thermocouples
(Excore
Thermocouples)
(}SPDS
Calibration Procedure.
b.
3/4-OSP-204
Accident Monitoring Instrumentation
Channel
Checks.
c.
AP-0190. 16
Scheduling
and
Surveillance
of Periodic
Tests
and
Checks
Required
By Technical Specifications.
Item II.F.2 is closed.
No violations or deviations
were identified within the areas
inspected.
ll.
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 radio-
logical 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
r elated
systems
to verify operability and proper valve/switch alignment:
A and
Intake Cooling Water Structure
Control
Room Vertical Panels
and Safeguard
Racks
Condensate
Storage
Tanks
Component Cooling Water
4160 Volt Buses
and
480 Volt Load and Motor Control Centers
Units 3 and
4 Main Steam Platform
12
Unit 3 Return to Service
Unit 3
was
returned
to service
on
December
22,
1987,
following an
outage
that
began
on
September
25,
1987,
in order to repair the
3B
Pump,
spray valve
PCV 455B,
and seal table leaks.
On.
December
25,
1987,
the
operators
were
experiencing
difficulties
controlling Reactor Coolant System
(RCS) pressure
due to pressurizer
spray valve PCV-455A not fully closing.
The operations staff decided
to commence unit shutdown in order to repair
PCV 455A.,
The turbine
was
tripped
and
the
reactor
was
taken
subcritical
with all
the
control
rods manually taken to the
bottom position.
Upon entering
the
source
range
operation,
Source
Range
Nuclear
Instrument
(SRNI)
N-31 actuated
a high flux level trip and
a subcritical
occurred.
Initial investigation
by the licensee
indicates that N-31
reenergized
spontaneously
above permissive
P-6 during unit startup
on
December
22,
1987.
This spontaneous
reenergization
of the
SRNI is an
ongoing industry wide problem.
The licensee is awaiting modification
from Westinghouse
to replace
the solid state circuitry with the relay
type circuitry in order to preclude this problem from recurring.
The
Off Normal Operating
Procedure
(ONOP)-059,3, entitled Nuclear Instru-
mentation Halfunction, does
not address
removing
a SRNI from service
above
the
P-6
setpoint.
Therefore,
N-31 was
removed
on clearance
C311083
by removing the fuses.
Removing the fuses
causes
the
SRNI to
fail safe (i.e., tripped high).
When the power level decreased
below
the
P-6
setpoint
(10-10
amps
on
both
Intermediate
Range
Nuclear
Instruments)
the Source
Range
High Flux Trip automatically reset,
and
caused
the reactor trip.
The licensee
is planning to include
steps
to
ONOP 059.3 to ensure
that the
SRNI is placed in bypass position
when
taken
out of service.
The licensee
subsequently
repaired
455A by adjusting
the
bench
spring
pressure
from approximately
3-5
psi to 13.5 psi.
This
new setting is identical to the setting
found
for
PCV 455B which is seating
properly.
Unit 3 was started
up
and
returned to service
on December
27,
1987.
Unit 4 Returned to
Service
Unit
4
was
returned
to
service
on
December
4,
1987,
following an
outage
that
began
on October
12,
1987,
due to Hurricane Floyd.
The
'licensee
decided to remain
shutdown in order to complete
repairs
on
equipment
including the
4B
RCP,
PORV-456,
and
retorquing
of the
conoseals,
along with modification to the Residual
Heat
Removal
Pumps
recirculation
lines.
On
December
13,
1987, with the unit at
100%
power, the
RCO noticed
an unexplained
increase
in the
as
he
was
performing
4-OSP-046. 1, entitled
Leakrate
Determination.
The
RCO referred
to
ONOP-2608.2,
entitled
CVCS Malfunction of
Concentration
Control
System,
and
secured
the primary water.
The
inventory increase
discontinued.
The licensee
suspected
valve
114A,
which supplies
primary water to the blender,
was
not fully
seated.'he
valve
was cycled
and primary water
was realigned.
'No further
increase
in
RCS inventory was observed.
The primary water inleakage
0
13
was calculated
to be approximately 2.3
gpm (135 gallons total) which
added
an
estimated
+20
pcm of reactivity to the
system.
The
RCO
stepped
in rods
8 steps
(D-223 to D-215) to compensate
for positive
reactivity addition.
The
operators
were
unable
to duplicate
the
dilution incident.
The plant was set back to normal
parameters
and
a
second
leak rate calculation
was performed.
The leak rate
was at
~ 02
gpm which indicates
that
the inleakage
had
di,scontinued.
On that
same
day, Unit 4's
load
was reduced to 100
MWE due to the Northeast
(NE) intercept valve going closed.
Crud had built up in the control
oil orifice which
caused
the intercept
valve to close partially.
Maintenance
personnel
made
adjustments
to the
NE intercept
valve
orifice which 'opened
the valve.
The unit was returned to full power
later that
same
day.
On
December
16,
1987,
at
0920
hours
the
NE
intercept valve went to mid-position due to control oil orifice being
clogged
with crud.
While attempting
to fully open
the
valve
by
adjusting
control oil orifice differential pressure
(dp) the valve
went full open
and the ¹4 control valve went from 80% to
20% open.
This caused
a swing in load of 80
MWE and the plant was stabilized at
660
MWE.
The licensee
developed
a Temporary
Procedure
(TP)-417 in
order to
make adjustments
to the control oil for the
NE intercept
valve without ca'using
severe
load
swings.
The adjustment
was
made
such that the
NE intercept valve was fully open with the ¹4 control
valve controlling in the correct position.
Later that
same
day the
RCO noticed
a loss of approximately
20
MWE due to the ¹4 control
valve
going
partially
closed.
The
operations
superintendent
recommended
stabilizing the unit at
680
MWE and
93% reactor
power
until a fix could be implemented.
The turbine vendor
established
new
adjustments
for the
smothering
and
control
oi 1
orifices in order to prevent
the intercept
and control valves
from
drifting closed.
The unit experienced
a loss of two
ICW pumps
on
December
18,
1987,
which caused
the operators
to decrease
power to
49%.
This event is discussed
further in paragraphs
8 and
13.
The
unit
was
returned
to
100%
power
on
December
20,
1987,
after
the
vendor
recommended
adjustments
to the
smothering 'and
control oil
orifices were performed.
No violations or deviations
were. identified
12.
Summary of International
Atomic Energy Agency (IAEA) Activities.
In fulfillment of the
Safeguards
Agreement
between
the United States
and
the
IAEA, the
IAEA selected,
on July 19,
1985,
Turkey Point Unit 4 for
participation in its international
safeguards
inspection program..A major
portion of this
program requires
the continuous surveillance of the fuel
inventory through
camera monitoring and seal wire placement.
The surveil-
lance
program
ensures
that
the fuel inventory does
not change
between
physical audits.
14
The
US/IAEA Safeguards
Agreement
has
been
in 'force
since July 31,
1980.
The
commitments
by the
U.S.
in this treaty,
which carries
the force of
law, are defined in the
Code of Federal
Regulations,
the treaty itself,
and
the
site-specific
Facility Attachments.
On April 10,
1987,
the
Commission
issued
Amendment
117
to
the
Facility
Operating
Licence
No.
DPR-41 for the Turkey Point Plant, Unit 4.
The amendment
adds
License
Condition 3.J regarding
implementation of the
IAEA Safeguards
program for
Unit 4.
Seal
wires
are
placed
by
IAEA inspectors
on
the
containment
equipment
access
hatch
and the reactor
vessel
head seismic restraints,
if
accessible.
Only .the
seal
wires
on the
equipment
hatch
can
be observed
from outside
the containment
building.
The containment
building is not
normally entered
during
power operation.
Two surveillance
cameras
are
installed
in the Unit 4
SFP.
The
area
is always accessible
through
locked and alarmed doors.
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.
The licensee
plans to issue
LERs on each
event within 30 days following the date of occurrence.
On
December
9,
1987, with Unit 3 in Mode 5,
an automatic containment
and
control
room ventilation isolation occurred.
PRMS Channel
R-19 was out of
service
and Plant Work Order
(PWO)
number
7397
was generated.
While
IKC
department
personnel
were disassembling
PRMS-19 drawer,
breaker
tripped.
This deenergized
PRMS rack
number
66 which contains
PRMS-12.
This causes
control
room and containment ventilation isolation.
A strand
of wire was found in PRMS-19 drawer
on the power'able,
which is believed
to
be
the
cause
of
a
ground fault that tripped breaker
The
remaining
PRMS drawers
and
panel
number
66 were cleaned
and the entire
rack was placed
back in service.
On
December
9,
1987,
with Unit 3 in
Mode
5
and Unit 4 in
Mode 1,
100%
power,
a site visitor alarmed the explosive detector while attempting
to
enter
the plant.
The visitor backed
out of the explosive
detector
and
produced
a
.38 caliber bullet from
a pocket
and
gave
the bullet to the
security
guard.
The visitor entered
the site
and the bullet was returned
as the visitor exited the site.
On
December
15,
1987, with Unit 3 in
Mode 5,
an automatic
control
room
ventilation isolation occurred.
IEC personnel
were removing jumpers that
were installed during repairs to
PRMS ll and
12,
when all the
were
15
momentarily.removed"from
the terminals.
This deenergized
the relay coil
. which caused
the control
room ventilation isolation.
PRMS 11.and
12 were
subsequently
returned,to
service
and
the
control
room
and containment
- isolation was reset.
On December
17,
1987, with Unit 3
in= Mode 4,
an automatic
control
room
ventilation
isolation
occurred
and
valves
RCV-609,
CV-2819,
CV-2826
closed.
The
Reactor
Control Operator
(RCO) . was
performing
the
monthly
surveillance
test
on
PRMS-19
and
when
the
high
alarm
setpoint
was
initiated, breaker
3P08-19 tripped which deenergized
the entire
PRMS rack.
Deenergization
of
PRMS ll and
12 . results
in the
ESF actuation
of the
control
room and containment ventilation.
The cause
was determined to
be
an apparent
short
in the relay circuit.
The
PRMS rack was
subsequently
reenergized
and
the control
room/containment
ventilation
isolation
was
reset.
On
December
17,
1987,
with Unit 3 in
Mode 4
and Unit 4 in Mode 1, at
93% power,
a visitor attempted
to enter the plant at the security gate.
Upon emptying his pockets prior to entering the explosive/metal
detector,
security personnel
noticed
a .357
magnum bullet in his personal
belongings.
The Security
Supervisor
denied
access
into the plant
and
the visitor
departed.
On
December
18,
198?,
with Unit 4 in
Mode 1, at
94% power,
the licensee
declared
an
Unusual
Event
due to the
loss of 4B and
4C
ICW pumps.
The
4C
ICW pump coupling
sheared
during continuous
operation
and the
4B ICW
pump could not be started
by the operators.
The licensee
formed an Event
Response
Team
(ERT)
and
commenced
unit shutdown in accordance
with Tech-
nical
Specification
3.0. 1.
Upon
receiving
discretionary
enforcement
from the
NRC, the licensee
was able to maintain reactor
power around
50%
for the
24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> extensiop to repair the
4B and
4C
ICW pumps.
The licensee
terminated
the
Unusual
Event at 8:24 p.m.,
and proceeded with repairs
on
the
pumps.
Both pumps were placed
back in service
on
December
19,
1987,
prior to exceeding
the
24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> time frame.
The unit was returned
to full
,power.
This event is discussed
further in paragraph
8.b.
On
December
18,
1987,
with Unit 3 in
Mode
3
and Unit 4 in
Mode 1, at
53%
power,
the
Emergency
Notification
System
(ENS)
telephone
became
during
followup notification to the
NRC
operations
center
regarding
termination of the Unit 4 Unusual
Event.
The notification was
completed
via commercial
telephone.
The
ENS telephone
was repaired
and
placed
back in service
on December
19,
1987.
On December
21,
1987, with Unit 3 in Mode
3 and Unit 4 in Mode 1, at
100%
power,
a contractor
vehicle
was
found to contain
a
box of
.12
shotgun
shells while being searched prior to entering the site.
Security
denied
access
to the vehicle and the driver.
On
December
25,
1987, with Unit 3 in Mode 3,
a subcritical
occurred.
The
root
cause
was
evaluated
and the unit was restarted
on
December
27,
1987.
This event is discussed
further in paragraph
11.
16
ll.
Temporary Instruction (TI) 2500/26
(25026)
This TI is provided to ensure that fasteners
selected
by the licensee
in
.
response
to
NRC Bulletin 87-02, entitled
Fastener
Testing
To Determine
Conformance
With Applicable Material Specifications,
are representative
of
installed
fasteners
and that
suspect
fasteners
are selected for testing.
On December
7,
1987,
the inspectors
witnessed
the sampling process
of the
fasteners
which were
selected
for the testing.
The licensee
obtained
a
printout of Stores
Usage in order to facilitate the sampling process.
.The
safety related bolting (purchased
gL-1) was split almost
evenly
between
A total of eleven
safety related
fasteners
with their
associated
nuts
were
selected.
The sizes
were determined
by
the actual
usage
over the past
12 months.
This sample consisted for four
SA 193,
Grade
B-7
and
seven
SA 307,
Grade
B fasteners.
The
associated
nuts
sample
consisted
of the following:
Eight
SA 194,
Grade
2H;
two
ASME Section III, Class
2
and
one
SA 307,
Grade
B.
The
non safety-related
sample
(commercial
grade)
was
based
solely
on the
actual
usage
in the plant.
A total of ten fasteners
were selected
along
with the
associated
nuts.
All of the
fasteners
selected
were
Grade
5
steel.
The
nuts
selected
did
not
have
any
material
specification
documented
except for one which was
ASME A 194,
Grade
2H.
The licensee's
sample
technique
included taking four of each fastener
and nut selected.
One fastener
and its associated
nut were
tagged
and
sealed
in
a plastic
bag for shipment to the testing
laboratory.
The remaining three
samples
of fasteners
and nuts were placed in a plastic
bag
and were to be locked
in a safe.
These extra
samples
were to be kept if the original
sample
was
damaged or lost enroute or at the testing laboratory.
During the licensee's
sampling
process
a
number of non-safety
related
(commercial
grade)
cap
screws
were identified to have manufacturers
marks which were
suspect.
The marks in question include:
KS, J,
M,
FM and A.
The licensee's
sample
which was selected for testing included
screws with KS and
M manufacturers
markings.
Review of the
licensee's
sampling
process
indicates
that
licensee
selected
a representative
sample of fasteners
and nuts
used at
the plant and that the fasteners
were properly tagged for shipment to the
testing laboratory.
The results of the testing are expected
to be received
by the
week of January
4,
1988.
This TI will remain
open
pending
the
completion
of the
fastener
testing
and
the
review of the
licensee's
receipt
inspection
program.
The
inspectors will also
review the main-
tenance/warehouse
procedures
for issue
and control of safety .and non-safety
related fasteners.