ML17349A268
| ML17349A268 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 05/29/1992 |
| From: | Butcher R, Schnebli G, Trocine L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17349A266 | List: |
| References | |
| 50-250-92-10, 50-251-92-10, NUDOCS 9206150056 | |
| Download: ML17349A268 (22) | |
See also: IR 05000250/1992010
Text
1
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W., SUITE 2900
ATLANTA,GEORGIA 30323
Report Nos.:
'50-250/92-10
and 50-251/92-10
Licensee:
Florida Power
and Light Company
9250 West Flagler Street
Miami, 'FL 33102
Docket Nos.:
50-250
and 50-251
License Nos.:
DPR -31 and
DPR -41
Facility Name:
Turkey Point Units
3 and
4
Inspection
Conducted:
Apri 1
4
rough
May 1,
1992
Inspectors:
C. Butch r,
enior Resident
Inspector
Dat
Sig ed
A. Schneb
, Resi
t Inspector
Dat
S'gn
d
Trocine,
Res dent Inspector
t
Accompanying Personnel:
RE
P. Schin, Project Engineer
M. N.
er,
Region II Inspector
Dat
Sign
d
Approved by:
K.
D.
and
,'hief
Reactor Projects
Section
2B
Division of Reactor Projects
Dat
Sig ed
SUMMARY
Scope:
This routine resident
inspector
inspection
involved direct inspection
at the
site in the .areas
of monthly surveillance
observations,
monthly
maintenance
observations,
engineered
safety features
walkdowns,
operational
safety,
plant
modifications
and plant events.
Results:
Within the
scope
of this
inspection,
the
inspectors
determined
that
the
licensee
continued to demonstrate
satisfactory
performance
to ensure
safe plant
operations.
The inspectors identified two violations,
one non-cited viola'tion,
and
one weakness
as noted below.
e
50-250,251/92-10-01,
Violation - Failure to follow a procedure resulting in the
removal of a Unit 4,
Channel
A, refueling water
storage tank level transmitter
q20b
oCK 05ppp25
15005b 920529
pDR
IIII
pDR
9
from service
during the calibration of
a Onit 3,
Channel
B, refueling water
storage
tank level transmitter (paragraph
5).
'0-250,251/92-10-02,
Non-Cited Violation - Failure to test diesel
fuel oil for
sulfur or content
per
the test
method specified
in Technical
Specification'.6.1.1.2.e
(paragraph 9.a).
50-250,251/92-10-03,
Violation - Failure to follow procedures for changing out
the
backup bottle. for the
3A
and
3B main
steam
isolation valves
(paragraph
9.d).
Weakness
Incomplete description
in the Final Safety Analysis
Report of the
functions of the main
steam isolation valve nitrogen/accumulator
backup
system
(paragraph
9.d).
REPORT DETAILS
Persons
Contacted
Licensee
Employees
T. V.
R. J.
R. j.
K. N.
E.
F.
R.
G.
D.
E.
H.
H.
V. A
J.
E.
R.
S.
J.
D.
J.
T.
G.
L.
L.
W.
M. 0.
T.
F.
D.
R.
R.
N.
F.
R.
M. B.
J.
D.
E. J.
Abbatiello, Site Quality Manager
Earl, Quality Assurance
Supervisor
Gianfrencesco,
Support Services
Supervisor
Harris, Senior Vice President
Nuclear Operations
Hayes,. I 8
C Maintenance
Supervisor
Hei sterman,
Mechanical
Maintentance
Supervisor
Jernigan,
Technical
Manager
Johnson,
Operations
Supervisor
Kaminskas,
Operations
Manager
Knorr, Regulatory
Compliance Analyst
Kundalkar, Engineering
Manager
Lindsay, Health Physicist Supervisor
Luke, Engineering
Manager
Marsh,
Reactor
Engineering Supervisor
Pearce,
Plant General
Manager
Pearce,
Electrical Maintenance
Super visor
Plunkett, Site Vice President
Powell, Service
Manager
Steinke,
Chemistry Supervisor
Timmons, Security Supervisor
Wayland,
Maintenance
Manager
Webb,
Outage
Manager (Acting)
Weinkam, Licensing Manager
Other
licensee
employees
contacted
included
construction
craftsman,
engineers,
technicians,
operators,
mechanics,
and electricians.
NRC Resident
Inspectors
RE
C. Butcher,
Senior Resident Inspector
G. A. Schnebli,
Resident
Inspector
L. Trocine, Resident
Inspector
Additional
NRC Inspectors
R.
P. Schin, Project Engineer
M. N. Miller, Region II Inspector
" Attended exit interview on
May 1,
1992
Attended exit interview on April 24,
1992
Note:
An alphabetical
tabulation of acronyms
used in this report is listed
in the last paragraph
in this report.
~,
Plant Status
~Un4t
Unit At the beginning of this reporting period, Unit 3 was operating at 87
percent
power in order to extend the unit run time until the beginning of
the
August
24,
1992, refueling outage.
Unit 3
had
been
on line since
February
5,
1992.
The following evolutions
occurred
on this unit during thi s
assessment
period:
On April 9,
1992, at 5:30 a.m.,
a load reduction to 50 percent
power
was
commenced
to facilitate
the
cleaning
of the
3A
TPCW
heat
exchanger
and of all four waterboxes.
(Refer to paragraph
9.b for
additional information.)
On April 9, -1992, at approximately 6:30 a.m., Unit 3 reached
50 per-
cent power,
On April 10,
1992, at 12:55 a.m.,
power ascension
was
commenced.
On April 10,
1992,
at 4:05, a.m.,
Unit 3 reactor
power
reached
87
percent,
and
reduced
power
operations
at this
power
level
was
recommenced.
On
April 27,
1992, at 9:33 a.m.,
a power reduction
was initiated due
to an increase
in the
3C
number
1
seal
leak rate.
Unit 3 trip
breakers
were
opened
at
10:33
a.m.
(Refer to paragraph
9.g for
additional information.)
Unit 4
At the beginning of this reporting period,
Unit 4 was operating
at
100
percent
powe~
and
had
been
on line since
March 28,
1992.
The following
evolutions occurred
on this unit during this assessment
period:
On Apri'l 28,
1992, at 4:00 a.m., Unit 4 reactor
power was reduced to
approximately'7
percent
for reactor
engineering flux maps (axial
offsets).
On April 28,
1992, at 6:45 p.m.,
reactor
power
was returned to 100
percent.
3.
Onsite
Followup
and
In-Office Review of Written Reports
of Nonroutine
Events
and
10 CFR Part 21 Reviews (90712/90713/92700)
The
Licensee
Event Report discussed
below was
reviewed.
The inspectors
verified that reporting requirements
had been met, root cause
analysis
was
performed,
corrective
actions
appear ed
appropriate,
and
generic
applicability had
been
considered.
Additionally, the inspectors verified
the licensee
had reviewed the event, corrective actions were
implemented,
responsibility for corrective
actions
not fully completed
was clearly
I
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 50-250/90-12,
A Postulated
Failure of a Single Manual
Reset
Pushbutton
Could Render Both Trains of Containment
Spray Inoperable:
On June
13,
1990,
the licensee notified the
NRC of a significant event in
accordance
with 10 CFR 50.72
concerning
a potential
single failure of
OT-2 switches
used
in various safety-related
systems.
This
issue
was previously discussed
in
LER 50-250/89-18,
which was closed in IR
50-250,251/90-40.
LER 50-250/89-18 identified a problem with Westinghouse
OT-2 switch at Turkey Point similar to that discovered
at other utilities
but
failed
to
examine
the
problem
generically.
Subsequently,
LER
50-250/90-12
was
issued
identifying other safety-related
applications
of
the Westinghouse
OT-2 switch..
This issue
was also previously discussed
in
IRs
50-250,251/90-18
,and
50-250,251/90-19.
The
licensee'
corrective
actions
were reviewed
and found to be adequate.
This,LER is closed.
4.
Monthly Surveillance
Observations
(61726)
The inspectors
observed TS-required surveillance testing
and verified that
the test procedures
conformed to the requirements
of the TSs; 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
propel ly
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:
4-SMI-071.5,
Protection
Set III (QR-18)
Analog Channel
Test,
and
4-OSP-059. 10, Determination of Quadrant
Power Tilt Ratio.
The inspectors
determined that the
above testing activities were performed
in a satisfactory
manner
and met the requirements
of the TSs.
Violations
. or deviations were not identified.
5.
Monthly Maintenance
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 the TSs.
The following items
were considered
during this review,
as appropriate:
LCOs
were
met while
components
or
systems
were
removed
from service;
approvals
were
obtained
prior
to initiating
work; activities
were
accomplished
using
approved
procedures
and were
inspected
as applicable;
procedures
used
were
adequate
to control
the activity; troubleshooting
activities
were controlled
and repair records
accurately
reflected
the
maintenance
performed;
functional
testing
and/or
calibrations
were
performed prior to returning components
or systems
to service;
gC records
were
maintained;
activities
were
accomplished
by qualified
personnel;
parts
and materials
used
were properly certified; radiological
controls
were properly
implemented;
gC hold points
were established
and
observed
where
required;
fire
prevention
controls
were
implemented;
outside
contractor
force activities
were
controlled
in
accordance
with the
approved
gA program;
and housekeeping
was actively pursued.
The
inspectors
witnessed/reviewed
portions of the following maintenance
activities in progress:
troubleshooting
and repair of the
3B
ICW pump discharge
failure,
troubleshooting
the Unit
3
RPI circuitry to determine
cause of,a
runback (see
paragraph 9.e),
and
troubleshooting
and
replacement
of the
No.
1
seal
due
to
increased
leakage.
At 1:35
p.m.
on April 2,
1992, the Unit 4
RCO received
an
RWST low level
alarm
and discovered that the
RWST level indicator (LI-4-6583A) had failed
low.
A 7-day
LCO was entered
per
TS
3 ',3.3,
Table 3.3-5 Item 20.
Upon
investigation, it was discovered
that the Unit 4,
Channel
A,
RWST level
transmitter
had
been valved out by I&C personnel
during the performance of
a
calibration
of
the
Unit
3,
Channel
B,
level
transmitter
(LT-3-6583B).
The Unit 4,
Channel
A,
RWST level transmitter
was valved
back in.
Aft'er a channel
check with the Unit 4,
Channel
B,
RWST level
transmitter,
the
Channel
A level indicator
was returned to service.
The
7-day
LCO was exited at 1:45 p.m.
on the
same day.
The licensee
attributed this event to
a lack of attention to detail
and
the failure of
an
IEC technician
to follow procedure.
The technician
involved was counselled
by the
18
C Maintenance
Supervisor,
and
a Nuclear
Problem
Report
(92-045)
was generated.
The
Human Performance
Enhancement
System
Coordinator
was
also
requested
to review this incident.
As
a
result of this review,
the licensee
plans to incorporate
the use of self
checking
'(stop,
locate,
touch,
verify,
anticipate,
manipulate,
and
observe)
into
the
IEC
Maintenance
Initial
and
Continuing
Training
programs.
The inspectors will follow up
on this action
during future
inspections.
TS 6.8. 1 requires that written procedures
be established,
implemented,
and
maintained covering the activities referenced
in Appendix A of Regulatory
Guide
1.33, Revision 2, February
1978.
Paragraph 8.b(l) of this Appendix
recommends
that
implementing
procedures
be written for each calibration
listed
in the
TSs.
Item ff of this paragraph specifies
procedures
for
water
storage
tank level
instrument calibrations.
Procedure
3PMI-062. 1,
Refueling Water Storage
Tank Level Instrumentation
Channels
LT-3-6583A/B
Calibration satisfies
the calibration
requiremeats
of TS 4.3.3.3,
Table
4.3-4,
Item 20,
RWST, and provides the instructions
and the necessary
data
to ensure
proper calibration and functional testing of the process
control
instrumentation
associated
with the
RWST level indicating
system.
This
procedure
was not followed in that during the calibration of the Unit 3,
Channel
B,
RWST level transmitter
on April 2,
1992; the Unit 4, Channel
A,
RWST level transmitter
was
removed
from service
instead
of the Unit 3,
, Channel
B,
RWST level transmitter.
This failure to follow a procedure
constitutes
a violation and will be
tracked
as
VIO 50-250,251/92-10-01,
fai 1ur e
. to
fol 1 ow
a
procedure
resulting
in the
removal
of a Unit 4,
Channel
A
RWST level transmi,tter
from service during the calibration of the Unit 3,
Channel
B,
RWST level
transmitter.
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.
One violation was identified.
Engineered
Safety Features
Walkdown (71710)
The inspectors
performed
an inspection
designed
to verify the status
of
the
4B EDG. This was accomplished
by performing
a complete
walkdown of all
accessible
equipment
and
by utilizing procedure
4-0SP-023.1,
Diesel
Generator Operability Test,
and drawings
5614-M-736,
Sheet
1,
EDG 4A 8
B
PEI Diesel
Oil
8 Service Air P81
Diagram;
5614-M-736,
Sheet
3,
4B
Diesel Oil, Lube Oil, Cooling 5 Air Systems
P81 Diagram;
5614-M-736,
Sheet
4,
45235A
& B;
and
5620-T-E-4530,
Sheet
2,
Water
Treatment
Plant Demineralizer Section.
The following criteria were used,
as appropriate,
during this inspection:
systems
lineup
procedures
matched
plant
drawings
and
as-built
configuration;
housekeeping
was adequate,
and appropriate
levels of cleanliness
were
being maintained,
valves
in the
system
were correctly installed
and did not exhibit
signs of gross
packing 'leakage,
bent
stems,
missing
handwheels,
or
improper, labeling;
hangers
and supports
were
made
up properly and aligned correctly;
valves in the flow paths
were in correct position
as required
by the
applicable
procedures
with
power
. available,
and
valves
were
locked/lock wired as required;
local
and
remote
position
indication
was
compared,
and
remote
instrumentaion
was functional;
and
major system
components
were properly labeled.
Some minor drawing and labeling discrepancies
were noted
and were brought
to the atttention
of the
system
engineer
for correction,
Violations or
deviations
were not identified.
7.
Plant Modifications (37828)
The
inspectors
observed
the installation of cathodic protection
in
heat
exchanger
3B.
This
was
done
per
PC/M 92-014,
under
work request
number
WA920319142431.
The
PC/M,
work order,
and
actual
work were
reviewed in process
and as completed.
This PC/M directed the installation
of four
anode
bars in the
ICW side of each
end of the
CCW heat
exchanger.
Each bar
was to be bolted to two two-inch square
blocks of
90/10
cupro-nickel'hich
in turn
were
to
be
welded
to
the
90/10
cupro-nickel
shell of the heat
exchanger.
The
purpose
was to eliminate
galvanic =corrosion of the
aluminum bronze
tubes that
had been occurring.
The inspectors
noted
no deficiencies
in the work or in the records.
8.
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
emergency
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.
The
inspectors
walked
down
accessible
portions
of
the
following
safety-related
systems/structures
to verify proper valve/switch alignment:
A and
B emergency diesel
generators,
control
room vertical panels
and safeguards
racks,
intake cooling water structure,
4160-volt buses
and 480-volt load and motor control centers,
Unit 3 and
4 feedwater platforms,
Unit 3 and
4 condensate
storage
tank
area,'uxiliary
area,
auxiliary building.
Ouring tours
of the auxiliary building, the inspectors
identified
the
following minor
discrepancies,
which
were
promptly
corrected
by
the
licensee:
In the
4A
pump room, the inspectors
found the
B sump
pump motor
ground wire not connected to the motor.
There were
tw'o sump
pumps in
the room,
and the
A sump
pump
'looked to be fn good condition with its
motor ground wire attached.
These
pumps were not classified
as
safety-related
but were support
equipment for the
RHR pump.
When the
inspectors
informed
the
NPS of this
condition,
he
promptly
had
maintenance
personnel
check the
pump and initiated
a work request to
have the ground wire connected.
Within two days,
the ground wire was
connected to the
pump motor.
b.
In the Unit 4 pipe
and valve
room,
the inspectors
observed
a loose
piece of heavy metal
on the floor adjacent
to and touching
the
letdown radiation monitor.
The piece of metal
was located
so that it
could have
been
bumped or tripped over and
knocked into the radiation
monitor. It looked almost like a support for the radiation monitor,
except
that it was
not bolted to the floor or fastened
to the
radiation
monitor.
The
inspectors
informed 'he
about
this
condition,
and
he prompt'ly had the loose piece of metal
removed.
The
licensee
routinely
performs
QA/QC audits/surveillances
of activities
required
under its
QA program
and
as
requested
by management.
To assess
the
effectiveness
of these
licensee'udits,
the inspectors
examined
the
status,
scope,
and findings of the following audit reports:
Audit Number
Number of
Findincis
T
e of Audit
QAO"PTN-92-007
QAO-PTN-92-009
TS 3/4.6,
Containment
Systems.
Reactivity Control,
Power
Oistribution
Limits, and Specia'l
Test
Exceptions.
0
QAO-PTN"92-011
RCS, Safety Limits and
Limiting Safety
System
'ettings,
Safety
Limit
Violations.
QAO-PTN"92"013
QAO-PTN"92-014
TS 6.5. 1,
PNSC
March Performance
Monitoring Audit
QAO-PTN"92-017
QAO-PTN-92-018
TS 3/4.7.6,
Training and
Qualification
No additional
NRC followup actions will be taken
on the findings referenced
above
because
they were identified by the licensee's
QA program
audits
and
corrective actions
have either been
completed or are currently underway.
Plant
management
has also
been
made
aware of these
issues.
. As
a result of routine plant tours
and various operational
observations,
the
inspectors
determined
that
the general
plant
and
system material
conditions
were satisfactorily maintained,
the plant security
program
was effective,
and
t
the overall performance of plant operations
was good.
Violations or deviations
were not identified.
9.
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
'o the
need for additional
NRC response
to the event.
Additionally, the
following i ssues
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 January
23,
1992,
the licensee
received
a fuel oil shipment for
their
EDGS.
TS 4.8. 1.1.2.e requires that the licensee verify within
30 days of obtaining
a
sample of the
new fuel oil that the other
properties
(those
not required prior to addition to the storage
tank)
specified in Table I of ASTM-D975-81 are
met
when tested
in accord-
ance with ASTM-D975-81 except that the analysis for sulfur
may
be
performed
in
accordance
with
ASTM-D129,
ASTM-D1552-79,
or
ASTM-D2622-82.
This analysis
was completed
on January
30,
1992,
and
showed the fuel oil was acceptable.
On April 3,
1992,
during
a
audit, it was
found that the subcontractor
had
used
ASTM-D-4294 for
the fuel oil
sample
analysis for sulfur.
Investigation
showed that
ASTM-D975 had been revised to reflect that sulfur test
methods
D129,
D1552,
D2622
and
D4294
can
also
be
used
for al l
grades
and
the
subcontractor
had
used
the latest version.
On April 14,
1992,
the
licensee
retested
the
EDG fuel oil using ASTM-D129. The results
were
satisfactory (sulfur content less than 0.50K) and correlated with the
~
previous test results.
The vendor was instructed to use only the
TS
approved
methods
as listed
on the purchase
order for future fuel oil
tests.
The failure to test
the
EDG fuel oil for sulfur content
as required
by
TS 4.8. 1. 1.2.e is
a violation.
- However, this violation will not
be subject to enforcement
action
because
the licensee's
efforts in
identifying and correcting the violation meet the criteria specified
in Section
V.G. of the
Enforcement
Policy.
This violation will be
~
tracked
as
NCV 50-250,251/92-10-02,
failure to test diesel
fuel oil
for sulfur content per the test method specified in TS 4.8. 1. 1.2.e.
b.
At 5:30
a.m.
on April 9,
1992,
a
load
reduction
on Unit
3
was
commenced
in order to facilitate the cleaning of the
3A
TPCW heat
exchanger
and all four condenser
waterboxes.
Unit
3
reached
50
percent
power at approximately
6:30
a.m.
on the
same
day,
and power
ascension
was
commenced at 12:55 a.m.
on the following day.
The
87
percent
power level
was re-attained
at 4:05 a.m.
on April 10,
1992,
and reduced
power operations
at this power level
was
recommenced.
C.
At 1:55 p.m.,
on April 17,
1992, the licensee notified the
NRC of a
Significant
Event
in accordance
with
0103.12,
Notification of
Events to the
NRC, and
10 CFR 50.72(b)(1)(ii)(B), In a Condition that
is Outside the Design Basis of the Plant.
After review of IN 91-75,
Status
Head
Corrections
Not
Included
in
Pressure
Transmitter
Calibration Procedures,
and associated
pressurizer
pressure
setpoints
for Turkey Point Units 3 and 4, the license
determined
that the
low
pressurizer
pressure
reactor trip setpoint
was
not adjusted
for
static
head
as
part
of
a
channel
calibration
procedure.
After
adjusting for static
head correction
and accounting for the allowable
margin within 'the current
TSs
, the licensee
confirmed that the plant
is presently operating
in accordance
with the current
TSs which were
implemented
on August 26,
1991.
However,
under
the
TSs in effect
prior to August
26,
1991,
the
licensee
determined
that
the
low
pressurizer
pressure trip setpoint
(if adjusted for static
head
and
assuming
the worst case
instrument error) could have resulted in the
plant operating in a condition outside the design basis of the plant.
This condition
was
documented
in
LER 50-250/92-003,
Operation
With
Improper Pressurizer
Pressure
Transmitter
Calibration,
dated April
22,
1992.
According
to this
LER,
the effect of
a static
head
correction
on the low pressurizer
pressure trip setpoint is currently
under
evaluation,
The
licensee
is
also
conducting
an engineering
analysis
to determine if the safety analysis limit for pressurizer
pressure
of 1790 psig was exceeded
and plans to document the results
of this analysis
in
a
supplement
to the
LER by June
1,
1992.
The
10
inspectors will review the
issue
upon
issuance
of the
supplemental
LER.
d.
At approximately
6:00
a.m.
on April 20,
1992, with Unit 3 operating
at approximately
87% of rated power,
a turbine operator
replaced
the
backup nitrogen supply compressed
gas bottles
on the
A and
B MSIVs on
Unit
3 without the
use of
a procedure.
Each
MSIV has
two backup
supply bottles.
One is normally in service
and
one
in
standby,
isolated
from the
Prior to replacing
a nitrogen
bottle, the
standby bottle
should
be placed
in service
and the
low
pressure
bottle
should
be isolated
from the header.
During nitrogen
bottle replacement
on this day, both bottles for the
A MSIV were left
isolated
and both bottles for the
B MSIV were also left isolated.
The
A and
8 MSIVs were considered
At 8:30
a.m. that
same
day, the Unit 3 turbine operator,
as part of
the next normal log taking in accordance
with Operations
Surveillance
Procedure
3-0SP-201.3,
Daily
Logs,
discovered
the
valve
misaligments
and notified the
NPS.
At 8:43 a.m.,
the
backup nitrogen supply system lineup was restored
in accordance
with 3-0SP-072.2,
MSIV N2 Backup Periodic Test.
The licensee
took the following corrective actions:
The
A and
B MSIVs were returned
to service
in accordance
with
procedures
as
soon
as the valve misalignment
was identified.
The following safety-related
systems
for both Units
3 and
4 were
walked down by the system engineers
or operations
personnel
for
alignment verification in accordance
with the appropriate
system
alignment verification procedures:
Intake Cooling Water
Component
Cooling Water
Boric Acid System
, Post Accident Containment
Vent System
Containment
Spray
High Head Safety Injection
Residual
Heat
Removal
System
.124 Volt Vital DC
Startup Transformer
On-site
AC Distribution
Post-accident
Hydrogen Monitoring System
No other incorrect valve or breaker alignments
were found.
.The turbine operator
and his supervisor
were disciplined.
11
Each operations
crew,
including both licensed
and non-licensed
operators,
met 'with plant
upper
management
to reinforce
the
necessity
and
requirement
to
use
procedures
with
verbatim
compliance
on safety-related
systems
when performing
even
the
most
routine
operation.
The details
of this
event
were
the
focus of these
meetings.
The activities of the non-licensed
operator during the mid-shift
of April 20,
1992,
were
reviewed.
No other
anomalies
were
noted.
An independent
Human
Performance
Evaluation
System
review is
being
performe'd
and will be
complete
by April 30,
1992,
to
ensure that all
human factors
causes
are evaluated.
Technical Specification (TS) 6.8. 1 requires
written
procedures
be
established,
implemenmted,
and
maintained
covering
the activities
recommended
in Appendix
A of Regulatory
Guide
1.33,
Revision
2,
February
1978,
and Sections
5. 1 and 5.3 of ANSI N18.7-1972.
Para-
graph
3
of
Regulatory
Guide
1.33,
Appendix
A
recommends
the
establishment
of written procedures
for operation
of safety-related
systems.
Section
5. 1.2 of ANSI N18.7-1972
requires
that procedures
be followed.
Procedure
0-AD
M -201,
Upgrade
Operations
Usage,
paragraph
5.1,
Procedural
Adherence Policy, states
in part that procedures
shall
be
present
during
performance
of tasks
for which verification is
documented
by initial or signature.
Procedure
3-OP
072,
System,
paragraphs'.
1
and 7.2, define
the
steps
required to place
the
MSIV backup nitrogen bottles in service and/or in standby.
These
steps require initials for the operator
and
second verification.
However,
on
April
20,
1992,
'
turbine
operator
replaced
the
in-service
Unit
3
A and
B MSIV backup nitrogen bottles with full
bottles
without following the
procedure
and without the
required
second verification.
This resulted
in the misalignment of valves
and
isolation of the safety-related
backup
systems
for the
3A
and
3B MSIVS.
The nitrogen
backup
systems
for the
3A,and
3B MSIVs
remained
isolated for about
2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />
and
43 minutes while Unit 3 was
operating
in Mode 1.
The failure to follow procedures
for changing out the nitrogen backup
bottles for the
3A 'and
3B MSIVs is
a violation and will be tracked
as
VIO 50-250,251/92-10-03,
failure" to follow procedures
for changing
out the nitrogren backup bottles for the
3A and
3B MSIVS.
While reviewing the Turkey Point
FSAR following this event, it was
noted that the
FSAR does
not adequately
describe
the purpose of the
backup nitrogen supply.
Paragraph
10.2.2(b) of the
FSAR states'hat
a supplemental
nitrogen supply (for Unit 3) and air accumulators (for
Unit 4) are provided to maintain the
MSIVs closed for one
hour should
12
instrument
air
be
unavailable.
However,
FPL's
Component
Design
Requirements
Document
(Document
No.
5610-072-DB-002,
Rev.
A)
references
a
change
to the
MSIVs (documented
in
LER 50-250/85-20-01
dated
May 7.,
1986) that added the nitrogen/accumulator
backup to the
instrument air system .to ensure
the MSIVs would close
under
low steam
flow conditions
and could maintain
the
MSIVs closed
for
one
hour
should
instrument air be unavailable.
The
update
to the
FSAR was
inadequate
in that it does
not accurately reflect the reason for the
instrument air backup
system.
The inspectors
consider the incomplete
updating of the
a weakness.
On April 23,
1992,
at
8:53
a.m.,
with Unit
3 at
87% power,
two
momentary
rod
bottom
signals
were
received
causing
momentary
turbine runbacks,
The
RCO for the unit noted annunciators
B 9/3 (Rod
Deviation)
and
B 7/1
(RPI
Rod Bottom Runback)
alarming indicating
a
dropped
rod turbine
runback.
The plant computer printout indicated
that the first signal
was
a 40 msec duration
and that the
second
was
a 470
msec duration
causing
turbine
and reactor
power to drop
from
87% to 86.5%.
The licensee
verified that no'ontrol
rods dropped,
and
no
rod
bottom lights
were
seen.
There
were
no
rod position
indi,cation
changes
from previous
readings,
and
no rod motion was in
progress
at the time of the event.
All plant conditions were stable
before
and after the runback.
The runback selector
switch was placed
in the
NIS position
versus
the
normal
RPI position after the event
until
the
cause
could
be
determined.
The
licensee
is currently
troubleshooting
the
RPI circuitry which will be
followed by the
inspectot s.
At 2: 10 p.m.,
on April 24,
1992,
lockout relay
186G for the
4B
was inadvertently
contacted
in panel
4Cl2B.
This resulted
in the
lockout relay tripping and locking out,
and this in turn rendered
the
4B
EDG out"of-service for reasons
other than preplanned
preventative
maintenance.
The lockout relay
was reset
in less
than
30
seconds.
The licensee
entered
action statement
b of TS 3.8. 1. 1 which required
the
demonstration
of operability of the
startup
transformers
and
their associated
circuits per
TS 4.8. l.l. l.a within
1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and every
8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter,
the demonstration
of operability of the remaining
required
EDGs per
TS 4.8. 1. 1.2.a.4 within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />,
and the restor-
ation of the
status
within
72
hours.
Attachments
1 and
2 (the Unit 3 and
4 Startup
Transformer
Breaker
Alignments) of procedure
0-OSP205. 1, Startup Transformer s and Onsite
A.C.
Power Distribution Verification, were
commenced at 2:27 p.m.
and
were
completed
at
3:00
p.m.
Procedure
4-0SP-023.3,
Equipment
Operability Verification with an
Emergency,
Diesel
Generator
inoper-
able,
was
commenced at 2:50 p.m.,
and Attachments
1 and
3
(EDG 4A and
3A and Supported
Equipment Operability Verifications) of procedure
4-0SP-0-23,3
were completed at 3:30 p.m.
The
4B
EDG was returned to
service
at
9:20
p.m.,
and
the
startup
transformers
and
their
associated
circuits
were
verified to
be -operable
per
procedure
0-OSP-205.
1 at 9:38 p.m.
Operability testing of the
4A and
3A
was
completed
at
12:45
a.m.
and
4:00
a.m.,
respectively,
on the
13
fol 1 owing
day.
At
4: 10
a.m.
on
April
25,
1992,
procedure
4-0SP-023.3,
Section
6.2,
Emergency
Diesel
Generator
4E Inoperable,
was reviewed,
and all required actions
were .completed.
g.
On April 27,
1992, with Unit 3 operating at
87% power, the unit was
taken "off. line due to increased
seal
leakage
from the
No.
1 seal
on
" the
3C
RCP.
Beginning
on April 25,
1992,
an upward trend in the
No.
1 seal leakoff rate
had been
observed
and
was being monitored
by the
licensee.
At 9:33 a.m.
on April 27,
1992,
the
leakage
exceeded
the
administrative
limit of
5
gpm,
and
the
licensee
initiated
a
controlled
shutdown
of the unit to replace
the
seal.
The
unit
entered
Mode
5 at
1:55
p.m.
on April 28,
1992,
and the licensee is
currently disassembling
the seal to determine
the failure mechanism.
The
resident
inspectors
were
present
in the control
room for the
shutdown which was well controlled and without event.
The residents
will monitor the licensee's
corrective
maintenance
of the
3C
RCP seal
assembly.
10.
Load Sequencer- Followup (92701)
Paragraph
6 of IR 50-250,251/92-02,
dated
February
11,
1992, discusses
the
following sequencer
problems'.
On December
10,
1991, the
4A sequencer
was
found not functioning in the auto-self-test
mode
as it should
have
been.
As
a result of this condition,
the licensee
shut
down Unit 4.
Safety
evaluation
JPN-PTN-SEN-91-099,
dated
December
10,
1991,
was
performed to
evaluate
the effects of taking the
sequencers
out of the auto-self-test
mode.
LER 91-007-00,
dated January
7,
1992,
was issued in accordance
with
Technical
Specification
Table
3.3.2.
The root
cause
.of the
sequencer
problem was identified as
a failure of a portion of the output relay card
used for the auto-self-testing.
A sticking (welded) relay contact which
should
have
been
closed
for only 0.2
seconds
during auto-self-testing
remained
closed.
This relay contact
simulated
a valid input signal during
auto-test,
but by remaining
closed
( sticking), it appeared
to be valid
input signal thus causing
the sequencer
failure problem.,
The inspector
reviewed the root cause
evaluation
and the corrective action
program
proposed
by the
licensee.
The root
cause
evaluation
included
examining
data
from inrush
current tests
run
on the output relay card
contacts.
These tests
indicated
the
inrush current
through the contacts
to the cables'apacitance
exceeded
the contacts
rating.
In addition,
these
output
relays
were
being
operated
in
the auto-self-test
mode
approximately
every three minutes.
This was over 20,000 relay operations
per
month in the test
mode.
To correct
these
conditions,
the licensee
plans
to install
current
limiting resistors
in series
with the relay
contacts.
These resistors
would limit the current well below the rating
of the contacts.
In addition, another
set of relay contacts
from a manual
test or an auto-self-test
relay would also
be in series
with the output
relay contacts.
These additional contacts
(much higher rating) would open
when
the
sequencer
was
not in the test
mode.
Therefore,
under
this
arrangement,
the current limiting resistor
should prevent
and the
second
set of higher rated contacts
would mitigate
a failure of an output relay
~
E ~
~
if it should occur,
The licensee
also stated
the auto'-self testing would
be decreased
to once
an hour for each step.
The inspector
considered
these
actions
appropriate.
However, the inspector stated that the programmable
controllers
used
in the
sequencers
have
a
20-year
history of being
extremely reliable.
Since
the
programmable
controllers
already
have
a
built in factory auto test, additional continuous
auto testing
appears
to
be
redundant.
Overall,
the
inspector
considered
the
sequencers
quite
satisfactory.
The failure was with the relay associated
with continuous
auto-self-test
mode.
Meetings
(71707)
A meeting
was held at the
NRC Region II Office in Atlanta,
GA,
on April 3,
1992,
in order to discuss
the status
of issues
involving the
new
load
sequencers
and
instrument
setpoints.
Representatives
from the licensee
management
and
from the
NRC Region II staff
were
in attendance.
This
meeting
'was
considered
to
be beneficial
and
provided
a better
under-
standing of these
issues.
e
A second
meeting
was held at the
FPL Corporate Office in Juno
Beach,
FL,
on April
14,
1992,
in
order to discuss
current
engineering
issues.
Representatives
from the licensee's
management
and engineering
staff as
well
as
representatives
from both
the St.
Lucie
and
Turkey Point
NRC
Resident
Inspector
Offices
were
in
attendance.
This
meeting
was
considered
to be beneficial
and provided
a better understanding
of the
applications
at Turkey Point,
the
status
of the
PRA at
St.
Lucie,
engineering
standards
and specifications,
the status
of the Turkey Point
reactor
vessel,
and the Passport
computer
system.
12.
Exit Interview (30703)
The
inspection
scope
and
findings
were
summarized
during
management
interviews
held
throughout
the reporting period with the Plant
General
Manager
and selected
members of his staff.
An exit meeting
was
conducted
on
May l,
1992.
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
from the
licensee.
The
inspectors
had
the
following findings
Item Number
Descri tion and Reference
50"250,251/92-10-01
VIO - Failure to follow a procedure
resulting in the
removal
of
a Unit 4,
Channel
A,
RWST level transmitter
from
service
during
the
calibration
of
a
Unit 3,'hannel
B,
RWST level trans-
mitter (paragraph
5).
50"250,251/92"10-02
NCV - Failure to test diesel
fuel oil
15
50-250,251/92-10-03
for sulfur content per the test method
specified
in
TS 4.8. 1.1.2.e
(paragraph
'.a).
VIO - Failure to follow procedures
for
changing
out
the
backup
bottles
for
the
3A
and
3B
.
(paragraph
9.d).
Weakness
- Incomplete description
in the
FSAR of the functions of the MSIV
nitrogen/accumulator
backup
system
(paragraph
9.d).
13.
Acronyms and Abbreviations
ANSI
EOG
GPM
IKC
ICW
.
IN
IR
LCO
LER
LT
MSEC
N2
NIS
,
'PS
NRC
OP
PC/M
PMI
PNSC
PTN
gA
RCO
Administrative
American National Standards
Insti
American Society for Testing
and
Component
Cooling Water
Emergency
Diesel Generator
Florida Power 5 Light
Final Safety Analysis Report
Gallons
Per Minute
Instrumentation
and Control
Intake Cooling Water
Information Notice
Inspection
Report
Limiting Condition for Operation
Licensee
Event Report
Level Transmitter
Millisecond
Nuclear Instrumentation
System
Non-Cited Violation
Nuclear Plant Operator
Nuclear Plant Supervisor
Nuclear Regulatory
Commission
Operating
Procedure
Operations
Surveillance
Procedure
Plant Change/Modification
Preventative
Maintenance - 18C
Plant Nuclear Safety Committee
Probabi listic Risk Assessment
Plant Turkey Nuclear
equality Assurance
equality Control
Reactor Control Operator
Pump
Residual
Heat
Removal
tute
Materials
16
TPCW
TS
Rod Position Indication
'efueling Water Storage
Tank
Turbine Plant Cooling Water
Technical Specification
Violati on