ML17345A821
| ML17345A821 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 04/19/1991 |
| From: | Butcher R, Crlenjak R, Ruff A, Schin R, Schnebli G, Trocine L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17345A819 | List: |
| References | |
| 50-250-91-11, 50-251-91-11, NUDOCS 9105080143 | |
| Download: ML17345A821 (34) | |
See also: IR 05000250/1991011
Text
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UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION I I
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323
Report Nos.:
50-250/91-11
and 50-251/91-11
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 Units
3 and
4
Inspection
Conducted:
ch
2 through 29,
Inspector
~
~
~
.
C.
ut
er,
e
or
esident
c
s, ei ent
ns
(. Y
g~L.
rocine,
Resident
Inspector
A.
.
Ru
r
t
ngineer
c
s
ro
ct
ngsneer
Approved by:
R.
V. Cr enjak,
C ie
Reactor Projects
Section
2B
Division of Reactor Projects
1991
pector
tor
f /> ~/
te
gne
a
e
gne
a
e Si
ne
a
e
>gne
e
1gne
Da
Signed
SUMMARY
Scope:
This routine resident
inspector
inspection
entailed direct inspection at the
site
in the
areas
of monthly .surveillance
observations,
monthly maintenance
observations,
operational
safety,
plant events,
and the emergency
power system
enhancement
program.
Results:
0
Within the
scope
of this
inspection,
the
inspectors
determined
that
the
licensee
continued to demonstrate
satisfactory
performance
to ensure
safe plant
operations.
In addition,
the licensee
took
prompt action to correct
the
following cited
and non-cited violations:
50-250,251/91-11-01,
Violation.
(Two examples)
Failure to document
removed
instrumentation
and
related
support
to reflect
the
requirement
for
Pl05080i43 9104i9
ADOCK 05000250
G
reinstallation
(paragraph
S.a)
and
the failure to provide the control'oom
marked
up drawings reflecting changes
in plant configuration (paragraph
S.b).
50-250,251/91-11-02,
Non-cited Violation.
Failure to adequately
preplan
and
perform maintenance
resulting in loss of power to the
4A 4160 volt bus
and
subsequent
loss
of spent
fuel
pool
cooling for approximately
two hours
(paragraph
9.a).
50-250,251/91-11-03,
Non-cited Violation.
Failure to verify
a
clearance
boundary
by utilizing controlled documents
(paragraph 9.b).
50-250',251/91-11-04,
Unresolved Item.** Modification made to fire water
supply
system without prior
10 CFR 50.59 safety evaluation
and without required work
process
controls.
A concern
was
noted to licensee
management
that the violation and the
second
non-cited violation reflected
a loss
in configuration control
which could
become precursors for more serious
events.
A strength
was
noted during this period concerning
the lockout of the startup
transformer.
Preplanning, for an event of this type was very good.
Procedures
and equipment
were in place to ensure
spent fuel pool cooling requirements
were
met.
Personnel
reacted
to this occurrence
in a professional
and expeditious
manner.
- Unresolved
Items
are Matters
about which more information is required to
determine whether they are acceptable
or may involve violations or deviations.
REPORT
DETAILS
Persons
Contacted
.
Licensee
Employees
¹T.
V. Abbatiello, (}uality Assurance
Supervisor
¹J. Arias, Jr., Technical Assistant to Vice President
¹L. M. Bladow, guality Nanager
¹W.
D. Brown, Site Construction Service
Manager
¹T. A. Finn, Assistant Operations
Superintendent
R. J. Gianfrencesco,
Assistant Naintenance
Superintendent
¹S. T. Hale, Engineering Project Supervisor
K. N. Harris, Senior
Vice President,
Nuclear Operations
E.
F. Hayes,
Instrumentation
and Controls Supervisor
R.
G. Heisterman,
Assistant Superintendent
of Electrical Naintenance
¹N.
P.
Huba,
Engineering
V. A. Kaminskas,
Operations
Superintendent
¹J.
E. Knorr, Regulatory Compliance Supervisor
¹R. Kundalkar, Project Engineer
J.
A. Labarraque,
Senior Technical
Advisor
¹N. L. Lacal, Configuration Group Supervisor
¹V.
G. Laudato, Fire Protection
G. L. Marsh, Reactor Supervisor
¹H. Johnson,
Operations
Supervisor
- ¹L. W. Pearce,
Plant Manager,
Nuclear
- ¹T. F. Plunkett, Site Vice President
- ¹0. R., Powell, Superintendent,
Plant Licensing
K. L. Remington,
System Performance
Supervisor
- R.
E.
Rose Design Control Supervisor
- C. V. Rossi,
equality Assurance
Supervisor
G.
N. Smith, Service
Manager,
Nuclear
R.
N. Steinke,
Chemistry Supervisor
J.
C. Strong,
Nechanical
Department
Supervisor
F.
R. Timmons, Site Security Superintendent
¹E. J. Traczyk,,Fire Protection Supervisor
¹G. A. Warriner, guality Control Supervisor
¹N. B. Wayland, Naintenance
Superintendent
J.
D. Webb, Assistant Superintendent
Planning
and Scheduling
- ¹A. T. Zielonka, Technical
Department Supervisor
Other
licensee
employees
contacted
included
construction
craftsman,
engineers,
technicians,
operators,
mechanics,
and electricians.
HRC Resident
Inspectors
- ¹R. C. Butcher, Senior Resident
Inspector
¹G. A. Schnebli,
Resident
Inspector
- L. Trocine,
Resident
Inspector
Other Personnel
- A. B. Ruff, Project Engineer,
Reactor Projects
Section
2A
fR. P. Schin, Project Engineer,
Reactor Projects
Section
2B
- Attended exit interview on March 15,
1991
O'ttended exit interview on March 29,
1991
Note:
An alphabetical
tabulation of acronyms
used in this report is
listed in paragraph
14.
2.
Plant Status
Control
room
and
main control
board modifications
continue,
with
cable pulling
and
terminations
in the control
r'oom,
wiring modifications,
and replacement
switches
and instruments
being
installed.
All four
new sequencers
are
in place with wiring modifications
and
terminations in progress.
The
4A
bus
outage
is complete.
The
38
and
48
DC buses
are
currently out of service with modificati'ons in progress.
Installation of the eight
new 480 volt- load center
transformers
is
complete
and the transformers
have
been turned over to operations.
The
38 and
48 4160 volt bus
outages
are currently in progress.
Phase
II of the outage
coranenced
on March 7,
1991, for Unit 4 and
on March
8,
1991, for Unit 3.
The Security
System
upgrade
continues,
with the vital area barri,er
steel
grating about
60% completed,
installation of CCTY cameras,
and
testing of individual intrusion detection
and access
control zones.
Installation of the
new
system
(removal
of bypass
loops)
continues
on schedule.
Installation of the
ATWS system is in progress.
Inspection
and repair of intake structure
bays is on schedule.
The
38 and
48
ICW header
inspections
are
complete
and the piping is
being reassembled.
3A and
38
EDG modifications
are in progress.
These
include idle
start modification,
new air compressors,
new air piping and supports,
upgraded
and
stub shaft,
and
the addition of two air
start motors.
The installati.on of the
new
ARMs system
is" in progress
with the
installation of the
new instrumentation
and
cable pulling in the
control
room.
The Unit 3 high pressure
turbine was disassembled
for inspection
and
repair.
Unanticipated
erosion of the turbine casing
and fixed blade
mounting
surfaces
was identified.
Repair will require
weld buildup
and machining.
This additional
work may impact the outage
schedule.
Four of the five blackstart
diesels
are operational.
The
No.
5
blackstart diesel
experienced
a mechanical failure on March 20,
1991.
See paragraph
9.c.
The
outage
was
on schedule
until March
13,
1991,
when
management
stopped
all
construction
activities
due to the
Unit
4 Startup
Transformer lockout event
(see
paragraph
9.a).
Additional work hours
were authorized
to recover
from the loss 'of time, approximately
10
shifts.
Full schedule
recovery is expected
by April 30,
1991.
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.
Ve'rification of corrective
action
was
achieved
through
record
reviews,
observation,
and
discussions
with
licensee
personnel.
Licensee
correspondence
was evaluated
to ensure
the
responses
were timely and corrective actions
were
implemented within the
time periods specified in the reply.
(Closed)
VIO 50-250,251/90-18-03.
Failure to adequately
control reactor
shutdown
evolutions
resulting
in
a reactor trip and failure to follow
procedure resulting in a reactor trip.
a.
The first
example
occurred
on, May
26,
1990,
when Unit
4
was
inadvertently manually tripped while at approximately
1% power during
the performance
of 4-OSP-089.
The licensee
was in the process
of
performing
step
7.2.59,
which states:
"Trip the
Breakers
or
continue
plant
startup
in
accordance
with
the
requirements
of the applicable
GOP (N/A if breakers
were not reset in
step 7.2.8)."
With the
PSN's
concurrence,
the
RCO tripped
the
reactor trip breakers
resulting
in
a reactor trip in lieu of
continuing with the startup
as intended.
The cause for the manual reactor trip was
a cognitive error
made
by
a
licensed utility
individual.
Step 7.2.59 of procedure
4-OSP-089
offered
two options
to the
RCO.
The first option was to trip the reactor;
The second
option was to continue
on with the plant startup
in accordance
with'he
GOP.
The
RCO erroneously
chose
the first option which was to
trip the reactor.
The
RCO should
have
selected
the
second
option
which would
have
returned
him to the
procedure
to continue
start-up of the unit.
The following corrective actions
were taken to
avoid further
violations
in this
area.
Operating
Surveillance
Procedures
3/4-OSP-089
have
been revised.
The
now decides
which
option to exercise for Step 7.2.59.
An
ERT was
formed to determine
the root
cause
for the reactor trip and
make
recommendations
to
prevent recurrence.
The
ERT recommended
formal operator training on
0
e
b.
This
self-checking.
Scheduled
training
classes
on self-checking
were
completed
by August 31,
1990.
The
second
example
occurred
on June
15,
1990,
when the
PSN did not
adequately direct the Unit 3
RCOs,
as specified in ADM-200, while the
unit
was
being
taken offline.
This
allowed
poor communication
between
the
RCOs controlling the reactor
and the turbine.
The poor
communication
led to the
RCO pulling control
rods to raise
RCS Tavg
as
the turbine
was
being tripped.
This resulted
in reactor
power
increasing
above
the
P-10
setpoint
(10% reactor
power)
which
automatically
tripped 'the reactor.
The
cause
for the
was
a
cognitive error
made
by licensed utility
personnel.
Preparations
were being
made to manually trip the turbine
as
part of
a controlled unit
shutdown
to repair
an identified
condenser
tube leak.
With reactor
power below the P-10 permissive,
one
RCO
was
attempting
to correct
a
low
average
temperature
condition
by 'pulling control
rods.
In doing so, reactor
power was
increased
to the P-10 permissive.
A second
RCO tripped the turbine
without verifying the reactor
and
steam
generators
were in a stable
condition below
10K reactor
power.
The following corrective actions
were
taken
to. avoid further violations in the
ar ea.
An entry was
made in the Operations
Night Order
Book to emphasize
the
need for
Control
Room
Supervisors
to
establish
themselves
as
the
command/control
focus
of significant operating
evolutions.
This
requires
the
APSN and
PSN to ensure that specific evolution briefings
are
completed,
that
communications
are accurate
and
adequate,
and
that evolutions
are
smooth
and controlled.
Scheduled
training
classes
on self-checking
were
completed
by August 31,
1990.
This
event
was
reviewed with applicable
operations
personnel
to increase
awareness
of the potential for undesirable
results
due to
a failure
to mentally review the consequences
of actions
being
performed.
In
addition,
the
necessity
of
adequate
communications
between
the,
different operators
and the
PSN was stressed
during this review since
inadequate
communications
were determined
to have
been
a significant
contributing
cause
of this
event.
An Operations
Department
Instruction
was
issued
to clarify those
evolutions
which require
pre-job briefings.
Additionally, the instruction defines
those tasks
requiring
assignment
of
a
dedicated
individual
responsible
for
evolution oversight.
violation is closed.
4.
Followup on Inspector
Followup Items
(92701)
Actions taken
by the licensee
on the item listed below were verified by
the inspectors.
(Closed)
IFI 50-250,251/89-45-03.
ALARA concerns
over the practice
of
venting the containment
through the auxiliary building.
The
licensee
issued
PC/M 90-098 to correct this
problem.
The
PC/M
provides
the following:
,Replacing
the existing
carbon -steel
instrument
air bleed line with stainless
steel
pipe to prevent corrosion in the pipe;
Rerouting
and resupporting
the piping to allow for a continuous
downward
slope
throughout
the entire
length of piping towards
the
containment
which will allow proper
drainage
of condensed
wate'r;
and
Insulating the instrument air bleed line to reduce
water
condensation
in
the pipe.
These
changes
should prevent the bleed pipe from plugging and
thus eliminate
the
need for venting into the auxiliary building.
These
modifications
are currently scheduled
for completion during the current
outage.
This issue is closed.
Onsite
Followup
and In-Office Review of Written .Reports
of Nonroutine
Events
and
10 CFR Part 21 Reviews
(90712/90713/92700)
The Licensee
Event Reports
and/or
10 CFR Part 21 Reports
discussed
below
were
reviewed.
The inspectors
verified that reporting
requirements
had
been
met, root cause
analysis
was performed,
corrective actions
appeared
appropriate,
a'nd generic applicability had
been considered.
Additionally,
the inspectors
verified 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 10 CFR Part 2, Appendix C,
were applied.
(Closed)
LER 50-250/89-13
and
LER 50-251/89-09.
Boric Acid Transfer
Pumps
Out of Service
Due to Low Seal
Pot Levels.
An entry
was
added
to the, operations
night order
book
on September
13,
1989, to inform control
room personnel
that
BATPs are to be considered
out
of service during the time the nitrogen
pressure
indicator is removed.to
refill the seal
pots.
Caution
tags were placed at each of the Unit 3 and
Unit 4
BATP seal
pots.
These
tags
require operations
and/or maintenance
personnel
to notify the Control
Room personnel
prior to opening
the seal
pots
so appropriate
actions
can
be
taken
to maintain Boric Acid System
operability.
In addition,
the
licensee
is
pursuing
a
. concentration
reduction
program during this outage
which will allow plant
peration
at or below four weight percent boric acid.
This would allow
replacement
of the current
BATP seals
with cartridge
type single
sea
s
1
which are compatible with the lower boric acid concentration.
The use of
the
new seals
would also eliminate
the
need for the seal
water system.
This modification should
prevent
events
of this type after the current
outage.
This
LER is closed.
Monthly Surveillance
Observations
(61726)
The inspectors
observed
TS required surveillance testing
and verified that
the test
procedures
conformed
to- the requirements
of the TS; testing
was
performed in accordance
with adequate
procedures;
test instrumentation
was
calibrated; limiting conditions for operation
were met; test results
met
!
acceptance
criteria requirements
and were reviewed
by personnel
other than
the
individual directing
the test;
deficiencies
were identified,
as
appropriate,
and
were
properly
reviewed
and
resolved
by
management
personnel;
and
system restoration
was
adequate.
For completed tests,
the
inspectors verified testing frequencies
were
met and tests
were performed
by qualified individuals.
The
inspectors
witnessed/reviewed
portions
of
the
following test
activities:
O-OSP-301.2,
Technical
Support
Center
Emergency Yentilation System
Operational
Test;
O-OP-031,
Black Start
Diesel
Operation
(for black start
diesel
generator
No. 2);
and
Monitoring of
Spent
Fuel
Pump
Heat
Exchanger
Room for
Flooding Conditions.
The inspectors
determin'ed that the above testing activities were performed
in
a satisfactory
manner
and met the
requirements
of the
TS.
Yiolations
or deviations
were not identified.
Monthly Haintenance
Observations
(62703)
Station
maintenance
activities of safety-related
systems
and
components
were observed
and reviewed to ascertain
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;
a'ctivities
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:
Structura'1
Repair of the
3B1
ICM Intake Mell;
Phase
Rotation Verification of No.
2 Black Start Diesel
Generator
After Breaker Maintenance;
and
Troubleshoot
No.
2 Black Start Diesel Voltage Regulator
Low Voltage.
On March 20,
1991,
the licensee
performed
phase rotation
and differential
relay checks
of the
Nb.
2
BDG.
This testing
was required
because
the
output breaker. for this unit was
used for vendor testing of the
new 4A and
48
EDGs.
To facilitate
use of the breaker for the vendor tests,
the
normal
power cables
from the
BDG were disconnected
and temporary cables
were installed from the
4A or 48
EDG to the breaker.
In order to perform
the
phase rotation
and relay checks,
the output breakers
from the
BDG bus
to the Unit
1 and
2 startup transformer
were racked out.
This removed the
BDG battery
charger
from service for the period of time these
breakers
were racked out.
Four of the five BDGs were available for use during this
period
as
the battery charger
was the only component
00S.
This testing
commenced
at 3:25
pm and the
BDG bus
was returned to normal at 4:45
pm.
For those
maintenance
activities observed,
the inspectors
determined that
the activities were conducted
in
a satisfactory
manner
and that the work
was
properly
performed
in accordance
with approved
maintenance
work
orders.
Violations or deviations
were not identified.
Operational
Safety Verification (71707)
The inspectors
observed
control
room operations,
reviewed applicable logs,
conducted
discussions
with control
room
operators,
observed
shift
turnovers,
and monitored instrumentation.
The inspectors
verified proper
valve/switch
alignment of selected
systems,
verified
maintenance
work
orders
had
been
submitted
as
required,
and verified 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.
The
implementation
of
radiological controls
and plant housekeeping/cleanliness
conditions
were
also 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.
In
addition,
the inspectors
walked
down accessible
portions of systems
which
are currently required to be operable/functional
in order to verify proper
valve/switch a'lignment.
The licensee
conducted
a safety evaluation
to .define control of the plant
configuration
during the
dual unit emergency
power
system
enhancement
project.
Procedure
Defueled Operations
Without Emergency
Diesel
Generators,
was issued to proceduralize
the requirements
determined
in the
safety
evaluation
to
be in effect from the time both units enter
the
0
defueled condition and both
EOGs are
removed
from service.
Also, portions
of the revised
TSs
became effective when both units entered. the defueled
condi tion.
As
a result of routine plant tours
and various operational
observat>ons,
the
inspectors
determined
that
the general
plant
and
system material
conditions
were satisfactorily maintained,
the plant security program was
effective,
and the overall
performance
of plant operations
was
good.
In
addition,
the inspectors
verified the critical electrical
system lineup
and verified the availability of the required
number of blackstart diesel
generators.
Availability of the minimum number of
ICW and
CCW pumps
was
also verified.
a.
On
March
5,
1991, auxiliary lube oil
pump control
instrumentation
(temperature
switch
TS
6537A) for the
A
AFW pump,
was
observ'ed
unattached
from its mounting
and
hanging
on
a pipe near the
A AFW
'pump.
This instrumentation
had
been
removed
from its previous
mounting
on approximately
February
28,
1991.
As
a verification check
f th
licensee's
configuration control
process,
the licensee
was
requested
to produce the-process
paper for relocating this particula r
instrument.
The licensee
had issued installation list 0466/88-418 to
rework the supports for,installation of vital areas
barriers
in the
AFW area
per
PC/N 88-418.
While vital area barrier rework was being
accomplished
in the
AFW pump area,
instrumentation
was encountered
that
had
not
been
recognized
by the
PC/N instructions.
This
-ins
rumen
'trumentation
was installed
as part of the
AFW pump assembly
and
therefore
was
not
shown
on
the
normal
operating
drawings.
The
Project Field Engineer
noted
the
removed
instrument
in his log book
and also noted the instrument did not have
an identification tag.
ASP-23,
General
Installation
Procedures
for Electrical
Raceways
and
Supports,
paragraph
5. 1.5 requires that the Project Field Engineer,
be
responsible
for ensuring that all supports
required
are listed
on
Attachment
A.
Paragraph
6.3. 1.4 of ASP-23 states
that Attachment
A
is
an active
document permitting field routed
raceway
being added
o
or deleted
from without formal revisions.
ASP-34,
Preparation
of
Process
Sheets
and Installation Lists, paragraph
5.4 states
that the
Project
Field
Engineer
is
responsible
for
insuring full
implementation
of
PC/N requirements
by the
preparation,
review,
approval,
and revision of all process
sheets
or installation lists.
TS 6.8. 1 requires written procedures
be established,
implemented
and
maintained
that meet or exceed
the recommendations
of Appendix
A of
RG 1.33, Revision 2, February
1978
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 -</br></br>1972" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process..
Section
5.1.2 of ANSI N18.7 -
1972Property "ANSI code" (as page type) with input value "ANSI N18.7 -</br></br>1972" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process. requires
that
procedures
be followed.
The failure to document
on Attachment
A of
ASP-23 the required support to reinstall
removed instrumentation,
and
the failure to revise installation list 0466/88-418
to reflect the
requirement
to reinstall
removed
instrumentation
is
a violation.
This is the first example of violation 50-250,251/91-11-01,
e
0
During
a tour of the control
room on March ll, 1991,
the inspectors
reviewed
the
marked
up electrical
figures provided to the control
room per
Dual, Unit Outage Configuration Control Notification.
paragraph
3. 1.3.2 requires
a configuration control notice
and
a
marked
up
figure notifying
the
of
changes
in plant
configuration which are
expected
in the next
24 to 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.
The
marked
up figures are to ensure
plant operations
is fully appraised
of configuration
changes,
both temporary
and
permanent,
that might
occur during the implementation of major modifications.
The posted
electrical
figures
(attachments
F thru
J of TP-644)
did 'not
accurately reflect the current plant configuration in that the
3B and
4B
4KV busses
were
shown
as in service.
The
3B 4KV bus
was removed
from service at
12:23
pm on March 8,
1991,
and the
4B
4KV bus
was
removed
fr'om service
12:40
pm
on
March
7,
1991.
The operations
personnel
on shift were fully aware of the revised electrical
lineup.
TS 6.8. 1 requires written procedures
be established,
implemented,
and
'aintained
that meet
or
exceed
the recommendations
of Appendix
A of
Revision 2,
February
1978
and Sections
5.1
and 5.3 of ANSI-
N18.7
-1972.
Section
5.1.2 of ANSI
N18.7 -
1972Property "ANSI code" (as page type) with input value "ANSI</br></br>N18.7 -</br></br>1972" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process.
requires
that
procedures
be followed.
The failure to follow TP-644,
paragraph
3.1.3.2
and provide the
PSN with marked up'igures reflecting changes
in plant configuration
expected
in the
next
24 to
48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> is
a
violation.
This will
be
the
second
example
of violation
50-250,251/91-11-01.
On approximately
February
8,
1991,
nuclear plant fire protection
personnel
observed
that fossil plant .personnel
and their contractors
had
welded
new piping onto
the
nuclear
plant .fire water
supply
system.
Additionally, they were preparing to "hot tap" two four-inch
into the nuclear fire water supply system.
This work
was being done
as part of a modification to the fossil plant (Units
1
and
2) raw water
system,
to install
two new raw water booster
pumps.
The modification included installing
new four-inch recirculation
lines from the
new pumps.
These recirculation lines were welded to
the nuclear plant fire water supply system fire pump flow test line
near
the point where it returned
to the bottom of Raw Mater Storage
Tank II.
The flow test line penetrated
the
Raw Hater Storage
Tank
well below the
18 foot level
(335,638
gallons)
reserved
for the
nuclear plant fire water supply,
and there
was
no standpipe
inside
the tank to prevent
the tank from draining through the
new raw water
booster
pump recirculation connections.
The affected
nuclear fire
water supply piping
was
described
in the
and identified
as
equality-Related.
On
February
8,
1991,
a site nuclear
engineering
memo
was written
stating that
some of the work could continue,
but that the "hot taps"
were
not to
be
done until
a nuclear
plant
10 CFR 50.59 safety
evaluation
was
completed
and approved.
On March 14,
1991,
the "hot
taps"
were
done, prior to approval
of. the 50.59 safety evaluation.
On March
22,
1991,
the
PNSC
approved
the 50.59
saf'ety evaluation,
10
which endorsed
the fossil plant engineering
package.
Fossil. plant
personnel
continued with the modification installation.
On March 26,
1991,
an
NRC inspector
observed that the newly installed
raw water booster
pump
"A" recirculation line isolation valve
was
closed,
but not locked closed
as required
by the engineering
package
in use.
At the time, piping to the
"A" raw water booster
pump was
not completely installed
and inadvertant
opening of the recirculation
line isolation valve could
have
drained
water from the
raw water
storage
tank.
The inspector
noted
that other work controls for
nuclear
plant modifications,
as
required
by procedure
gI3-PTN-l,
Design Control,
dated
February
26,
1991,
were riot being followed..
Examples
included:
procedure
control
(pen
and ink changes
were
made to the working
copy of the
engineering
package
without required
review
and
approval),
and
quality control
(a hydrostatic test
on March 18,
1991
was later
found to be inadequately
performed).
Additional
review is
required
to determine
the full scope
and
s 1 gnl
1c
o
'ificance of this event.
This item is identified as Unresolved
item 50-250,251/91-11-04,
modification
made
to fire water
supp yl
system
without prior
safety evaluation
and without
required
work process
controls.
One violation was identified.
9.,
Plant Events
(93702)
The following plant events
were reviewed to determine facility status
an d
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.
a.
On March
13,
1991,
at 3:30
pm,
the output breaker
from the Unit 4
startup
transformer
to the
-4A 4160 volt bus
received
a lockout
signal.
This re'suited
in the isolation of the transformer
and the
4A
4160 volt bus.
Loss of power to the
4A bus resulted
in the loss of
ling since
the
4B 4160 vol: bus
and
both
were out of
coo ln
se of the
se rvice for modificati ons
during
the
outage.
The
cau
lockout relay actuation
could not
be, determined
at the time
of the
event.
The startup
transformer
was
inspected
and
no relay targets
11
were
found in the'- tripped position
nor were
any external
causes
identified.
The switchyard circuit breakers
were inspected
and
two
breakers
were
found
open;
however. lockout-relays
were
not found
tripped on these
breakers.
The switchyard breakers
opened
because
of
the lockout
on the startup
transformer.
The
4A 4160 volt bus
was
inspected
and
no problems
were identified.
Concurrent with the actions
being taken to determine
the cause of the
lockout, the licensee
commenced
monitoring the Unit 4 SFP temperature
every
30 minutes
and started
effoi ts to restore
power to the 4A bus
per existing procedures.
Two
BDGs were started to provide emergency
power to the
4A bus from the
4C bus if required.
The
PSN declared
an
Unusual
Event at 3:50
pm and all required notifications
were
made.
The startup
transformer
was
reenergized
at 4:30
pm from normal off
site
power
and
the
4A 4160 volt bus
was
reenergized
at 4:35
pm.
Breakers
to the
480 volt load centers
and motor control centers
that
were closed prior to the event were reclosed.
Normal
SFP cooling was
restored
at
5:27
pm
and
the
Unusual
Event
was
terminated.
temperature
increased
about
3 degrees
F during the approximate
two
hour period
the cooling system
was
not in operation.
This rise in
temperature
was less
than predicted
by the analysis
performed for the
safety evaluation for the outage.
An occurrence of this type was considered
during the planning for the
Emergency
Power
Systems
outage.
Procedures
were
prepared
for
response
to such
an occurrence.
The systems
required to 'operate
in
the event of a loss of the capability to provide
power from offsite
sources
worked
as
designed.
Also,
a capability existed
to tie the
Unit 3 startup
transformer
to the
4A 4160 volt bus if needed.
A
truck mounted
400
KW diesel
was available to provide temporary
power
to pro'vide'ooling to the
spent
fuel pool.
In addition,
a diesel
powered fire pump
and non-vital
screen
wash
pump were available
to
supply spent
fuel
pool cooling water.
Also,
an alternate
cooling
system,
in place for this outage,
could have. supplied spent fuel pool
cooling using non-vital power.
Th
licensee
immediately formed
an
ERT to determine
the cause of the
event
and
a list of most probable
causes
was developed.
A review o
e
i
f
drawing 5614-E-28,
sheet
19A, indicated if a short circuit occurred
(in either
panel
4C04 in the
Control
Room or 4Cll in the Cable
Spreading
Room) at the appropriate
terminal
points to increase
the
voltage
to the
lockout relay, it would actuate.
Also, if the
terminals
on the lockout relay indicator light bulb in the circuit
touched or it,'s resistor failed, additional voltage would be supplied
to the relay causing't
to actuate.
Two people
were working in panel
4C04 'he
control
room when the event occurred.'ne
electrician
was connecting
wires in the
panel
and the other
was
vacuuming met al
filings and chips
from the inside of the panel.
Licensee
management
t
d ll work in and around all areas
that could have contributed
d
b
to this
event
or
a similar event.
Work was
.to
be release
y
'I
r
f
0
12
management
pending
the
outcome of the
ERT investigation
and after
appropriate corrective actions
were in place.
I
In
an effort to duplicate
the cause
of the lockout,
the licensee
energized
the
4A 4160 volt bus
by back-feeding
through
the
main
transformer,
which was disconnected
from the Unit 4 generator,
and
the Unit 4 auxiliary transformer.
Power to the startup transformer
was then deenergized
to facilitate troubleshooting
on March 16,
1991.
The
licensee
was
only able
to duplicate
the lockout event
when
terminals
1 and
3 of the lamp flasher circuit for the indicator light
were shorted
together
by
a metal chip.
These
two terminals are very
close
together
and
are
located
in the
area
where
the
person
was
vacuuming.
The licensee
concluded that this
was the most probable
cause
as
the troubleshooting
did not identify other .circumstances
that reproduced
the event.
In
order
to
prevent
recurrence,
- the licensee
added
additional
requirements
to existing procedures
identifying responsibilities
and
actions
required
for work
on sensitive
equipment.
Sensitive
t was defined
as
equipment that could
have
an impact
on the
vital power
supply or the
SFP cooling function.
A list of sensi'tive
equipment
was
generated
and
added
to TP-645,
Defueled
Operations
Without Emergency
Diesel Generators.
In addition, Training Brief No.
288 was issued
on March 18,
1991, requiring all responsible
personnel
be trained in the
new requirements prior to management
releasing
the
hold on work in 'the affected areas.
TS 6.8. 1
requires
that
written
procedures
be
established,
implemented,
and
maintained
covering
activities
recommended
in
Appendix
A of
Revision 2,
February
1978.
Section
9.a of
this
Appendix
recommends
that
maintenance
that
can
. affect
the
per
erformance of safety-related
equipment
should
be properly preplanned
ted
d
erformed
in accordance
with written procedures,
documen
instructions,
or drawings
appropriate
to the
circumstanc
recommendations
stated
above
were not followed in that
on March
13,
1991, maintenance
on panel
4C04 in the control
room was not properly
preplanned
and
performed
causing
the Unit 4 Startup
Transformer to
lock out.
This caused
a loss of power
to the
4A 4160 volt bus
and
subsequent
loss
of cooling to the
Unit
4
Spent
Fuel
Pool for
approximately
two hours.
This licensee
identified violation is not
b't d because
the criteria specified
in Section
Y.G. 1 of the
NRC enforcement
policy were satisfied.
This item will bee tracked
as
NCY 50-250,251/91-11-02,
failure to adequately
preplan
and
perform
maintenance
resulting in loss of power to the
4A 4160 volt bus
and
subsequent
loss of
SFP cooling for approximately
two hours.
This
item is considered
closed.
On March 12,
1991, fire panel
C-285
was inadvertently
disabled for
greater
'than
one
hour without
a
being
established.
This resulted
from the following sequence
of events.
I
13
A clearance
request
(22360)
was submitted for fire suppression
system
control
panel
C-285
(Auxiliary Building North-South
Breezeway
Deluge
System - Fire 2one 79A).
Mhen the clearance
(3-91-03-050-R)
for this
request
was
written,
PCON
incorrectly
printed
the
identification of breaker
which supplies
120-volt
AC power
to this control panel,
as
a spare.
The
NWE noted that the clearance
reflected
a
spare
breaker,
signed
the
approval,
and
sent
the
clearance
to
be
hung.
The'learance
was
hung
at
12:45
am
on
March 12,
1991.
At 1:00
am,
the half-hourly fire watch patrol
noticed
alarm point 37 trouble alarm at control
room panel
0-39A and
failed to notify any control 'oom personnel
of
a
new off-normal
condition.
At 1: 10
am, the fire watch supervisor noticed the trouble
alarm
and asked'he
about it.
An
NO
was
dispatched
to
investigate
the trouble
alarm
and
reported
that
power to control
panel
C-285
was 'being
supplied
from the battery
backup.
An
overheard
the radio conversations
and reported that
he had just hung
1
a ce
on the
panel
in question.
An out-of-service condition
for fire zone
79A was determined,
and the fire protection supervi
'sor
was notified.
and
backup
suppression
were
established
per
TS 3.7.8.2.c at 2:00
am.
The original clearance
was
released,
a
new clearance
(3-91-03-054-R)
was written,
the
PCON
data-base
was corrected,
and fire protection
impairment FPI-4060
was
hung.
It was later
determined
that
the fire zone
79A was
not
actually
out-of-service
because
control
panel
C-285 was'eing
supplied
by a battery backup.
Several
opportunities
existed to identify and/or prevent this event.
These
included the following:
PCON incorrectly printed the identification of breaker
as
a spare
breaker
in lieu of the actual
power supply breaker,
and the need for a fire protection impairment
was not evident.
The
NWE signed
the approval
and sent the clearance
to be
hung
without cross-referencing
PCON with the breaker list.
The
who
was
assigned
to
hang
clearance
3-91-03-050-R
on
b
k
knew that this
would
remove
power from fire
rea er
suppression
control
panel
C-285.
The
NPO also note d that the
breaker
was labelled differently than the clearance,
but assumed
that
an alternate
power supply was being
used
because
there
was
no requirement
for
a fire protection
impairment
and the reason
for the request
was conduit modifications.
At 1:00
am,
the half-hourly fire watch patrol
noticed
alarm
point 37 trouble alarm at control
room panel
C39A and failed to
notify any'ontrol
room personnel
of a new off-normal condition.
TS 6.8. 1
requires
that
written
procedures
be
established,
~implemented,
and
maintained
covering activities
recommended
in
Appendix
A of
Revision 2,
February
1978.
Section
1.c of
14
C ~
One
this
Appendix
recommends
administrative
procedures
for equipment
control (e.g.,
locking and tagging).
Procedure
O-ADM-212, 1n-Plant
Equipment
Clearance
Orders,
paragraph
5.8. 1.2,
requires
that t e
c earanc
learance
boundary
be verified using controlled
documents (i.e.,
prints,
procedures).
However,
paragraph
5.8. 1.2
o,f.
procedure
0-ADM-212 was not followed in that
on March 12,
1991,
the
identification of clearance
boundary
breaker
as
a
spare
breaker
by
PCON was not verified by use of a controlled document
such
as the breaker list.
This licensee-identified
violation is not being
't d
b cause
the criteria specified
in Section
V.G. 1 of the
NRC
Enforcement
Policy were satisfied.
This item will be tracke d
as
NCV 50-250,251/91-11-03,.
failure to verify a clearance
boundary
by
utilizing controlled documents.
This item is considered
closed.
At 7:05
pm on March 20,
1991, the
No.
5 blackstart diesel
experienced
a mechanical
engine failure during
a routine scheduled
surveillance
test
per 0-OP-031.
The 3rd cylinder from the
NE end of the engine
had
a connecting
rod failure involving the
cap for the crankshaft
end.
The licensee
is performing'n investigation to determine
the
cause
of the failure.
This event investigation will be followed by
the resident inspectors.
violation and
one non-cited violation were identified.
10.
Emergency
Power System
Enhancement
Program
a
~
Cable Installation Review (51063)
Two partial
cable pulls in conduit were observed for cable
numbers
400147B
and
3B5007A.
The former involved two 1/C 750
MCM cables for
a
DC circuit between
the Unit 4
EDG building and the
DC room off the
Unit 4 cab'le spreading
room.
The- latter
involved three
1/C 750
cables
for an
AC circuit between
the
new electrical
equipment
room
(formerly the the hot machine
shop area)
and the Unit 3 load control
center.
Both runs started
approximately at the mid point of their
runs
and involved cable'engths
only for that portion of the run.
The
first pull involved approximately
460 feet of cable,
but since
the
cable
has
to be
snaked
in and out of conduit, pull boxes,
and other
pu
poin
s
ll
'
to prevent
exceeding
the
bend radius,
sidewall pressure,
pull tension,
and other criteria, approximately
680 feet
o
c
f
able
ll
observed.
-Of the 480 feet of cable,
approximately
80 feet
was
placed in its final position during the observatio
p
'
eriod.
The
second pull involved approximately
500 feet of cable
and s'imilar to
h
b
proximately
1000 feet of cable pull was
observed.
For
the
second pull, approximately
200 feet of cable
was
placed iin its
final position during the observation
period.
During the cable pulls the following observations
were made:,1)
The
licensee
adhered
to
the
cable
pull
card
routing, including
specifications
and
cable
pull calculations,
2)
cables
were well
protected
from both
physical
damage
and welding activities
when
,e
15
required,
3) proper pulling compound
was
used
and applied liberally,
4) pulling attachments
and
tensions
were
adhered
to
and
were
"
acceptable,
5) scaffolding
and climbing aids
were
used,
6) cable
routing was correct,
7) instrumentation
was in cal-ibration, 8) proper
bend radius
was maintained,
9)
gC inspectors
were qualified and were
present
and
performing
their
tasks
during
the
handling
and
installation activity, 10) cable identification was preserved, ll) an
adequate
number of electricians
and
gC inspectors
were available to
perform the pulls,
12) their cooperation
and
good attitudes
toward
performing quality work were evident,
13) installation
and inspection
activities
were
being
documented
during the process,
and
14)
when
necessary,
nonconforming
reports
were
issued
for engineering
evaluation.
The
licensee's
field engineering
personnel
-demonstrated
their
computer cable pull calculation
program via
a sample calculation for
a typical cable
run.
Various configurations
(different, sizes
of
pulleys
and/or
sheaves,
cable
runs, radii, etc.)
were
used
to show
.
their effects
on the cable pull tension.
b.
Nonconformance
Report Review
Nonconforming reports
N91-0222,
0228,
0232,
0171,
0136,
and
90-0759
associated
with
cable
pulls for
the
emergency
power
system
enhancement
program
were
reviewed.
These
reports
were readily
retrievable
and legible,
and they were evaluated
and reviewed in a
timely fashion.
The corrective
actions
and justifications
were
controlled through the licensee's
established
channels.
Violations or deviations
were not identified.
ll.
Allegation RII-91-A-0043.
Administration of General
Employee Training
Test.
The inspector
reviewed the administration of GET testing at the facility.
This included:
a review of the
examination
questions;
the method of
answering
the
questions;
the
method
grading
the
examination;
and
discussions
with responsible
licensee
personnel.
The
examination
consists
of
20 multiple choice
and true/false
type
questions.
Each multiple choice
question
has
four 'possible
answers
labeled
A through
D and
the true/false
questions
are
labeled
A and
B,
.respectively.
The questions
are general
in nature
and the student
must
obtain
a grade of 80% to pass.
The questions
are
answered
on
a separate
answer
sheet
that lists
each
question
number
1
through
20 with its corresponding
answer letter,
A
through
D.
The student is instructed to mark their answers clearly on the
answer
sheet
using
a No.
2 pencil.
'
Th
sheet
is then
graded
using
a clear plastic sheet overlay with
holes
punched
out to identify the correct
answer.
Incorrect
answer
e
answer
s ee
s are
then circled in red
and totaled.
The test is graded
by two separate
individuals,
one Training Grader
and one-gC Grader.
As previously stated;
the student is required to obtain
a grade of 80% to
hich corresponds
to
a
maximum of four incorrect
answers.
The
inspector
reviewed
the specific
answer
sheet
and test in question
and
verified that it contained five incorrect
answers,
which corresponds
to
75:.
and
a failure.
The answer
sheet did not appear to have
been
tampered
with.
The inspector
considers
taking this type of test'ith
a pencil to
be typical
and adequate.
This allegation could not be substantiated.
12.
Outage Status
Review by
NRC l'lanagement
On
Yarch
5,
1991,
the
NRC
Region II Regional
Administrator
and
the
D'
D'sion of Reactor Projects
toured
TPNP to assess
the current
status of the dual unit outage.
On March 27,
1991,
the Director,
iv
iree or,
ivi i
D
ision
of Reactor
Projects
I and II, NRR, the Assistant Director for Region II
Reactors,
NRR,
and other headquarters
management
personnel
toured
TPNP to
th
rent status of the dual unit outage.
The licensee
provided
NRC management
with the current status
of the outage
progress,
'
g
licensin
actions,
and the general
plant startup testing schedule.
13.
Exit Interview (30703)
The
inspection
scope
and findings
were
summarized
during
management
interviews held throughout the reporting period with the Plant Nanager-
Nuclear
and selected
members of his staff.
Exit meetings
were conducted
on Yarch
15
and 29,
1991.
The areas
requiring
management
attention
were
reviewed.
The
licensee
did not identify as
proprietary
any of the
materials
provided
to
or
reviewed
by
the
inspectors
during
this
inspection.
Dissenting
comments
were not received
by the licensee.
The
inspector's
had the following findings:
Descri tion and Reference
50-250,251/91-11-01
VIO - (Two examples)
Failure to document
removed instrumentation
and related
support to reflect the requirement for
reinstallation
(paragraph
S.a)
and the
failure to provide the control
room
marked
up figures reflecting changes
in
plant configuration (paragraph
S.b).
50-250,251/91-11-02
NCV - Failure to adequately
preplan
and
perform maintenance
resulting in
loss
of power to
4A 4160 volt bus
and
17
subsequent
loss of SFP cooling for
approximately
two hours.
{paragraph
9.a).
50-250,251/91-11-03
50-250,251/91-11-04
14.
and 'Abbreviations
NCV - Failure to verify a clearance
boundary
by utilizing controlled documents
{paragraph 9.b).
URI -'Modification made to fire water supply
system without prior 10 CFR 50.59 safety
evaluation
and without required
work
process
controls.
A concern
was
noted, to licensee
management
that the violation and
the
second
non-cited violation reflected
a loss in configuration control which
could become
precursors for more serious
events.
A t
th
as
noted during this period
concerning
the lockout of the
startup
transfOrmer.
Preplanning for an event of this type
was
y g
s reng
w
ver
ood.
Procedures
and
equipment
were in place to ensure
Spent
Fuel
Pool Cooling
requirements
were
met.
Personnel
reacted
to this
occurrence
in
a
professional
and expeditious
manner.
1/C
ADN
am
ANSI
APSN
BATP
BDG
CFR
ERT
F
FPI
ICW
One Conductor
Alternating Current
Administrative
As Low As Reasonably
Achievable
ante meridiem
American National Standards
Institute
Assistant Plant Supervisor Nuclear
Area Radiation Monitor
Administrative Site Procedure
'nticipated Transient
Without Scram
Closed Circuit Television
Component Cooling Water
Boric Acid Transfer
Pump
Black Start Diesel Generators
Code of Federal
Regulations
Direct Current
Emergency
Diesel
Generator
Event Response
Team
Fahrenheit
Fire Protection
Impairment
Florida Power
5 Light
General
Employee Training
General
Operations
Procedure
Intake Cooling Mater
0
18
IFI
IR
'KV
LCO
LER
NCY
NO
NRC
NME
OP
PC/M
PCON
pm
RCO
TPNP
TS
Inspector
Followup Item
Inspection
Report
Kilovolt
Kilowatt
Limiting Condition for Operation
Licensee
Event Report
Thousand Circular Mils
Non-cited Yiolation
Nuclear Operator
Nuclear Plant Operator
Nuclear Regulatory
Commission
Office of Nuclear Reactor Regulation
Nuclear Match Engineer
Out of Service
Operating
Procedure
Operations
Surveillance
Procedure
Plant Change/Modification
Plant Clearance
Order Network
post meridiem
Plant Supervisor
Nuclear
Quality Assurance
Quality Control
Reactor Control Operator
Reactor
Coolant System
Regulatory
Guide
Resistance'emperature
Oetector
Spent
Fuel Pit
Temporary Procedure
Turkey Point Nuclear Plant
Technical Specification
Unresolved
Item
Yiol a tion
~
'