ML17346B204
| ML17346B204 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 06/17/1986 |
| From: | Brewer D, Elrod S, Peebles T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17346B203 | List: |
| References | |
| 50-250-86-25, 50-251-86-25, GL-83-28, NUDOCS 8607070358 | |
| Download: ML17346B204 (32) | |
See also: IR 05000250/1986025
Text
~p,S Rfgg,
Mp0
Cy
nO
ip
~0
<<k*<<>>
UNITED STATES
NUCLEAR REGULATORY
COMMISSION'EGION
II
101 MAR I ETTA ST R E ET, N.W.
ATLANTA,GEORGIA 30323
Report Nos.: 50-250/86-25
and 50-251/86-25
Licensee:
Florida Power
and Light Company
9250 West Flagler Street
Miami, Florida 33102
Docket Nos.:
50-250
and 50-251
Facility Name:
Turkey Point
3 and
4
Inspection
Conducted:
April 14
May 12,
1986
License Nos.:
and
Inspectors:
T.
.
eebles,
Senior
Resi
nt Inspector
Date Signed
D.
R.
Brew r,
esident
Inspector
Approved by: t phen A. Elrod, Section Chief
Division of Reactor Projects
Date Signed
Date
S gned
SUMMARY
Scope:
This routine,
unannounced
inspection
was
conducted
in the
areas
of
licensee
action
on previous inspection findings, annual
and monthly surveillance
observations,
maintenance
observations
and reviews,
operational
safety verifi-
cation,
engineered
safety features
walkdown,
independent
inspection,
and plant
events.
Results:
Violations
Failure to meet
the requirements
of Technical Specifica-
tion (TS) 6.8. 1., three
instances
with multiple examples,
(paragraphs
6,
7 and
8);
and failure to meet the requirements
of 10 CFR 50, Appendix B, Criterion VI,
(paragraph
8).
8607070358
860620
ADOCK 05000250
lf
g t
F
II II
li
Jl
REPORT DETAILS
Licensee
Employees
Contacted
"C.
M. Wethy, Vice President - Turkey Point
"C. J. Baker, Plant Manager-Nuclear
Turkey Point
- F. H. Southworth, Administration Department
E. Preast,
Site Engineering
Manager
D.
W. Hasse,
Safety Engineering
Group Chairman
D.
D. Grandage,
Operations
Superintendent-Nuclear
T. A. Finn, Operations
Supervisor
"V. A. Kaminskas,
Acting Operations
Supervisor
J. Crockford, Assistant Operations
Supervisor
J.
Webb, Operations/
Maintenance
Coordinator
D. A. Chancy,
Corporate
Licensing
J. Arias, Regulation
and Compliance Supervisor
"R. Hart, Regulation
and Compliance
Engineer
~J.
W. Kappes,
Maintenance
Superintendent-Nuclear
J.,C.
Strong, Electrical Maintenance Supervisor,
R. A. Longtemps,
Mechanical
Maintenance
Supervisor
E.
F. Hayes,
Instrument
and Control (IC) Maintenance
R.
G. Mende,
Reactor Engineering
Supervisor
R.
E. Garrett,
Plant Security Supervisor
P.
W. Hughes,
Health Physics Supervisor
W.
C. Miller, Training Supervisor
J.
M. Donis, Site Engineering Supervisor
J.
M. Mowbray, Site Mechanical
Engineer
R.
H. Reinhardt,
Quality Control
(QC) Inspector
"L. W. Bladow, Quality Assurance
(QA) Superintendent
"J. A. Labarraque,
Technical
Department
Supervisor
"M. J. Crisler,
QC Supervisor
R. J. Earl,
QC Inspector
Supervisor
Other
licensee
employees
contacted
included
construction
craftsmen,
engineers,
technicians,
operators,
mechanics,
electricians
and
security
force members.
"Attended exit interview.
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
May 14,
1986.
The
areas
requiring
management
attention
were reviewed.
Four violations were identified:
4,
,4
Failure of operations
personnel
to meet the requirements
of TS 6.8. 1.,
three
examples,
in that:
(1) Operating
Procedure
(OP)
1004.2
was not
properly implemented,
resulting in a Unit 3 reactor trip; (2)
OP 4304. 1
was
not
properly
implemented,
resulting
in
the
inadvertent
inoperability of the
"A" Emergency
Diesel Generator
(EDG); and (3)
OP
4304. 1 was not properly implemented,
resulting in the inadvertent start
of the "B" EDG (paragraph
7)(250, 251/86-25-01).
Failure to establish
an
adequate
procedure
for the operation
of the
as
required
by
TS 6.8. 1,
in that
procedure
0-OP-023
did not
correctly address
the. positioning of several
valves (paragraph
8)(250,
251/86-25-02).
Failure
to
implement
Appendix
B, Criterion VI, in that
drawing
5610-T-E-4536
did
not
accurately
reflect
the
as-built
configuration
of
the
auxiliary
systems
(paragraph
8)(250,
251/86-25-03).
Failure to meet the requirements
of TS 6.8. 1 in the area of maintenance
control, in that Administrative Procedure
(AP) 0190. 19 was not properly
implemented
when
a maintenance
technician
did not thoroughly document
maintenance
actions,
and
maintenance
work
was
performed
under
an
emergency
authorization
when the criteria for such work did not exist
(paragraph
6) (250/86-25-05).
Two unresolved
items were identified:
Determine
the
basis
for allowing maintenance
activities
which
can
affect
the
performance
of safety-related
equipment
to begin without
requiring that the maintenance
be preplanned
or performed in accordance
with written procedures,
documented
instructions or drawings appropriate
to the circumstances
(paragraph
6)(UNR 250, 251/86-25-06).
Determined the relationship of TS 6'.3.,
temporary
changes,
to changes
made
to
Preoperational
Procedure
(POP)
0800. 112
(paragraph
5)
(250/86"25-04).
The licensee
did not identify as proprietary
any of the materials
provided
to or reviewed
by the
inspectors
during this inspection.
The
lice'nsee
acknowledged
the
findings
without dissenting
comments.
The
licensee
indicated that
perhaps
violations
250,
251/86-25-01
and
250,
251/86-25-05
could
be
combined.
This was
subsequently
considered
by the
NRC Region II
management.
While example
2 of 86-25-05
could fit either place,
example
1
would not.
The violations remain separated.
3.
Licensee Action on Previous
Inspection
Findings (92702)
a.
Performance
Enhancement
Program
(PEP)
Summary
The construction of the Administration Building was completed
in April
1986
and
occupancy
began
in
May
1986.
The centralization
of
the
4T
administrative
offices
has
improved
the
coordination
of inter-
departmental
matters
and facilitated
communications.
Construction
of the Training Building is progressing well; work began
on the
second floor in early May.
A meeting is scheduled
for May 29 and
30 between
NRC management
and the
licensee
to discuss,
in detail,
the progress
of the
PEP
program
to
date.
The meeting will take place at the Turkey Point site to allow
NRC management
to tour the nuclear plants.
Consolidation
of the Engineering
Department
under the Site Engineering
Manager
has
facilitated
the
handling
of
engineering
issues.
Coordination
between
the
engineering
staff
and
the
Plant
Manager'
staff
has
improved.
An
improved
procedure
for the resolution
of
technical
issues
has
been
implemented.
The
procedure
is
highly
structured
and
provides
measures
for prioritization,
feedback
and
monitoring not found in previous
programs.
r
Previously Identified Items
(Cl osed)
Violation
250/84-39-01
and
251/84-40-02
-
Thi s violati on
occurred
when
the
licensee
staff
failed
to fully evaluate
the
consequences
of
a fai 1 ed
Auxi 1 iary
(AFW)
differenti al
pressure
(DP)
cell
during
surveillance
testing.
The
licensee
has
conducted
training
on
TS
4. 10.4
which
has
corrected
misconceptions
regarding
AFW pump operability.
The
DP cells
were
removed
from the
AFW system after being evaluated
as
not essential
for proper
system
operation.
Additionally,
the
surveillance
procedures
have
been
- revised to clarify testing
and operability requirements.
The previous
surveillance
procedure,
OP 7304. 1, which was
common to both trains for
both units,
has
been
superseded
by procedures
3/4 OSP-075. 1
and 3/4
which are unit and train specific.
(Closed)
Violation 251/84-40-01
This violation occurred
due
to
a
misinterpretation
of
During
an
AFW test
on Unit 3
a
DP
cell failure resulted
in Unit
3 entering
a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> limiting condition
for operation
(LCO).
Licensee
personnel
failed to evaluate
the
DP cell
failure with respect
to Unit 4, which was being started
up.
Due to
a
peculiarity in the wording of TS 3.8,
no
LCO existed for Unit 4,
and
a
shutdown of Unit 4 was not begun
as required.
Since
December
1984 the
licensee
has
continued
to
emphasize,
through training,
the correct
interpretation
of TS 3.8.
In addition,
on
May 7,
1986,
the licensee
submitted
to the
NRC Office of Nuclear
Reactor
Regulation
(NRR),
a
proposed
license
amendment
which clarifies the requirements
for AFW
system operability by adopting
modes of applicability consistent
with
the Standard
Technical Specifications.
Licensee letter
L-86-193, which
transmits
the
amendment
request,
was voluntarily submitted.
(Closed)
Unresolved
Item 250/84-35-04
and 251/84-36-04
This item was
determined
to
be
a violation of
NRC requirements,
in that the
Main
Steam
Isolation
Valves
were
not
tested
in
accordance
with
the
requirements
of
the
Inservice
Inspection
Program.
Violation
250, 251/85-05-01
was issued
on March 6,
1985.
Corrective
action for
the
discrepancy,
which
was
subsequently
the
subject
of
a
report (Licensee
Event Report
is in progress
and its
completion will be verified at
a later date.
(Closed)
Inspector
Followup Item (IFI) 250, 251/84-33-01
The licensee
submitted
supplemental
data describing plant capabilities with respect.
to Section
1.2 of Generic Letter (GL) 83-28.
On November 27,
1985, the
NRC completed
a safety evaluation
(TAC Nos.
53643
and
53644)
on the
data
and
information capabilities
of
the
Turkey Point plants
and
determined that the licensee's
response
was acceptable.
Item
1.2 is complete for Turkey Point Units
3 and 4.
(Closed)
IFI
250,
251/83-26-06
-
The
licensee
has
developed
and
implemented
drawing
5610-T-E-4536,
sheets
1
and
2
which correctly
identify the status
of all valves in the
EDG air start
system.
Those
valves
whose closure could prevent
EDG starting
are
kept
locked
open.
OP
4303. 1,
Normal
Standby
Condition,
has
been
superseded
by
procedure
O-OP-023,
which correctly itemizes the required positions of
the
EDG air start
valves
and
reflects
the
locked
status
of the
appropriate air valves.
(Closed)
IFI 250,
251/83-38-05 - This item documented
a concern that
the
Spent
Fuel
Pool
(SFP)
temperature
was
excessively
high during
refueling.
Inspection
Report
250,
251/85-23
subsequently
documented
that
the
was
being
operated
in
a
manner
contrary
to
the
requirements
of the Final Safety Analysis Report
(FSAR), in that the
lower cooling
pump
suction
was
being
used
instead
of the
higher
suction.
It was determined
that the total cooling flow through
the
lower suction
was significantly lower than that which could be obtained
through
the
upper suction.
The
reduced
flow resulted
in higher
temperatures,
especially
when
the entire
core
was off-loaded during
refueling.
As a result of Violation 250, 251/85-23-01,
the licensee
no
longer
uses
the
lower
cooling
suction
line.
Consequently,
temperature
has
remained
less
than
120 degrees
Fahrenheit.
Corrective
actions for the violation have
been
implemented
and will be reviewed at
a later date.
(Closed)
This
LER documented
the licensee's
discovery
that Unit 4 containment
isolation valve
CV-4-956A, pressurizer
steam
space
vent line isolation,
was susceptible
to leakage
above the limits
established
in the inservice test program.
The potential
leakage
path
was identified during post-maintenance
testing after repairs
were
made
to the valve.
To preclude
the possibility of inadvertent
leakage via
CV-4-956A, the licensee
shut CV-4-951, which is located just inside the
containment
building
in
series
with
CV-4-956A.
CV-4-951
was
deenergized
to preclude
inadvertent
operation
90
minutes
after
the
'0
8g
E
identification of the problem.
No TS requirement or
LCO was exceeded.
Though not required,
the licensee
also shut manual
valve 997A adjacent
to
CV-4-951 'inside
containment.
This
provided
an additional
closed
valve in the flowpath through
the containment
CV-4-956A
was
repaired
within
2
1/2 hours.
No radiological
release
occurred.
CV-4-951
remained
closed until August
1984
because
a failed position
indicator precluded reliable remote monitoring of valve position.
The
delay
in the
maintenance
repair
was justified since
the
valve is
normally closed,
infrequently operated
and located in a relatively high
radiation area while the reactor is at
power.
The valve
was repaired
during the first shutdown of opportunity.
4.
Unresolved
Items
An unresolved
item is
a matter
about which more information is required to
determine whether it is acceptable
or may involve
a violation or deviation.
Two unresolved
items identified during this
inspection
are
discussed
in
paragraphs
5 and 6.
5.
Monthly and Annual Surveillance
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 .inspector verified that testing
frequencies
were
met
and tests
were performed
by qualified individuals.
The inspectors
witnessed/reviewed
portions of the following test activities:
Periodic Test
Load on 4
KV Bus
Unit 3 Auxiliary Feedwater
Flow Control Valve Stability Test
Power
Range Nuclear Instrumentation Shift and Daily Calibrations
Rod Position Indication System Monthly Test
Preoperational
Procedure
(POP)
0800. 112,
Unit 83
AFW Flow Control
Valve
Stability Test,
dated
March
21,
1986,
was
reviewed
in detail
following
implementation.
The testing
was performed to verify that flow oscillations
in the
AFW system during automatic
operation
had
been
corrected
subsequent
to
the
implementation
of Plant
Change/Modification
The
procedure
was
performed
by
the
Startup
Department
on
April 9,
1986,
following a reactor startup
from a month-long Unit 3 maintenance.
outage.
The
inspector
noted that
several
procedural
steps
had not
been
properly
implemented
during
the
performance
of the
test.
Step
9.4. 14 of
the
procedure
required that the time between
the start of the "A" AFW pump and
the delivery of 375 gallons per minute (gpm) flow to the
be
'iI
verified to
be
less
than
3 minutes
with the
system
operating
in the
automatic
mode.
However, flow oscillations through flow control valve (FCV)
3-CV-2816 precluded
obtaining
an accurate
flow reading.
Consequently,
the
verification was
not performed.
Similarly, step
9.4.25 of the procedure,
which directed that the time required to obtain
561
gpm flow to the
steam
generators
be recorded,
was not done.
Steps
9.5. 14
and 9.5.25
were also
not implemented
on train
2 because
system
flow indicator
FI-3-1401B exhibited
sticky
and erratic
operation
during part of the test.
Consequently,
accurate
flow readings
were
not
possible.
Members of the Startup
Department
documented
those
areas
where they deviated
from the
requirements
of
the
procedure.
The
Engineering
Department
evaluated
the test results
and concluded that the two steps relative to the
testing
of
each
train
were
unacceptable.
However,
the
Engineering
Department
recommended
that
the
AFW system
be
accepted
"as is" for the
following reasons:
Valve CV-3-2816
was the only one of six identical
valves
to exhibit
excessive
oscillation
subsequent
to the design
change.
Therefore,
the
problem did not appear to be inherent in the trim design,
but rather in
the control
loop.
Engineering
concluded
that the valve control
loop
could be repaired
and retested
in accordance 'with
POP
0800. 112 at the
next possible opportunity.
Even
though
FI-3-1401B exhibited erratic operation
during the test,
personnel
monitoring CY-3-2831 reported that it was operating without
oscillation
and
was
open to a position that agreed with the other two
train
2 FCVs.
Engineering
considered
the visual verification of valve
stability to
be
acceptable.
FI-3-1401B
was
replaced
but applicable
portions
of
POP
0800. 112
were
not
repeated
due
to the
Engineering
comments.
The Plant Nuclear Safety Committee
(PNSC) specifically approved
POP 0800. 112
on March 21,
1986.
Section
3.2 of the procedure
specifies
the
acceptance
criteria,
stating that (1) flow control
valves
must stroke
smoothly;
(2)
within three minutes after
pump start,
the
system
must achieve
setpoint flow
to each
and (3) the flow controller
must maintain flow per
the flow criteria outlined in the procedure.
TS 6.8.3 requires that temporary
changes
to procedures
only be
made provided
that:
a.
The intent of the original procedure is not altered;
b.
The change is approved
by two members of the plant management
staff, at
least
one
of
whom holds
a
Senior
Operator's
license
on
the
Unit
affected;
and
e
c.
The
change
is
documented,
reviewed
by the
PNSC
and
approved
by the
Plant Manager-Nuclear within 14 days of implementation.
On April 9,
1986,
temporary
changes
were
made to Preoperational
Procedure
(POP)
0800. 112,
Unit
3
Flow Control
Valve Stability
Test,
dated
March 21,
1986,
in that several
procedural
steps
were
not performed.
The
omi ssions
included not recording the time required to achieve
required flow
rates
and
not
observing
required i flows
on
installed
flowmeters.
The
omissions
appear
to constitute
changes
to the intent of the
procedure
in
that the acceptance
criteria for control valve stability were modified to be
less restrictive
than was,.acceptable
by the
PNSC
approved
procedure.
The,
intentional
omi ssions
were
not
approved
by
two
members
of
the
plant
management staff or approved
by the Plant Manager-Nuclear within 14 days.
The relationship of TS 6.8 '
to preoperational
test procedures
is unresolved
item 250/86-25-04
pending further
NRC evaluation.
Maintenance
Observations
(62703/62700)
Station maintenance activities
on safety-related
systems
and components
were
observed
and
reviewed to ascertain
that they were conducted
in accordance
with approved
procedures,
regulatory guides,
industry
codes
and
standards
and in conformance with TS.
The following items
were
considered
during this
review,
as appropriate:
that
LCOs were
met while components
or systems
were
removed
from service;
that approvals
were obtained prior to initiating work; that activities were
accomplished
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.
The following maintenance activities were observed
and/or
reviewed:
Replacement
of AFW Flow Indicator FI-3-1401B
(PWO 6230)
Rod Control
System Repair For Shutdown
Bank "A" (PWO 6379)
CV-3-2816
Loop Calibration
FI-3-1401B Meter Calibration
During review of these
maintenance
activities,
the inspector
noticed that
work on the rod control
system
and
AFW system
began prior to the development
of written work procedures
and without the required pre-review of the work
package
by the
gC Department.
I
Technical Specification (TS) 6.8.1
requires
that written procedures
and
administrative policies
be implemented that meet or exceed
the requirements
and recommendations
of sections
5. 1 and 5.3 of ANSI N18.7-1972
and Appendix
A of USNRC Regulatory
Guide 1.33.
Appendix
A of
Regulatory
Guide
1.33
states
that
administrative
procedures
specifying procedure
adherence
should
be established.
AP 0190. 19,
Control of Maintenance
on Safety
Related
and Quality Related
Systems,
dated
January
8,
1986,
states
that the Plant Supervisor-Nuclear
(PSN)
may authorize
work to start prior to obtaining Quality Control
(QC)
approval
of the
Plant
Work Order
(PWO)
when
the plant is in
a
load
threatening
condition or in an Action Statement of TS 3.0. 1.
To immediately
commence
work, the
PSN shall originate
a
PWO and assign
a class
"AA" work
priority
and
sign
the
permission
to
start
work
block.
Maintenance
technicians
are
required
to thoroughly document all actions
taken
on the
PWO,
and the
PWO shall
be
made available
for subsequent
review by the
Department within one day.
On April 9,
1986,
PWO 6230
was
issued
as
a priority class
"AA" work order
for maintenance
on
AFW FI-3-1401B but the maintenance
technician
did not
thoroughly
document
his
maintenance
actions.
He failed to originate
a
calibration record sheet for the flow meter
he installed.
Additionally, he
failed to indicate
on
the
PWO that
he
had
performed
the required
meter
calibration.
The licensee
re-performed
the calibration
in order to obtain
the required
QA record of the maintenance activity, and indication was found
to be within calibration tolerances.
On
May 3,
1986,
the
PSN authorized
work on the rod control
system to start
on priority class
"AA" PWO 6379 when the plant was not in a load threatening
condition or in an Action Statement
of TS 3.0. 1.
Additionally, the
PWO was
not made available for review by the
QC Department within one day.
Shutdown
bank
"A" could not
be withdrawn past
41 steps.
The bank
was
then fully
inserted
and the reactor trip breakers
were
opened.
A dirty contact
was
found in the
rod control circuitry.
The
rod control
system
performed
satisfactorily after cleaning.
These
failures
to adequately
implement
AP 0190. 19 are
a violation of
TS 6.8. 1.
This violation applies to Unit 3 only (250/86-25-05).
The licensee
has
used priority class
"AA" PWOs approximately
77 times since
January
1985.
The licensee is implementing
changes
to AP 0190. 19 to better
define
the
responsibilities
of
those
tasked
with its
implementation.
Additionally, the licensee
has
instructed
the
PSNs to rigorously adhere to
the
implementation
requirements
and avoid the
use of priority maintenance
for activities for which it was not intended.
Since
0190. 19
effectively
authorizes
maintenance
to
begin
on
safety-related
equipment
prior
to
the
development
of
a
maintenance
procedure,
a concern
is raised
regarding
the
adequacy
and quality of the
maintenance.
Additionally, AP 0190. 19
may conflict with applicable
ANSI
y
1,
J'q
Standards
which require that maintenance
activities which can affect the
performance
of safety-related
equipment
be
preplanned
or
performed
in
accordance
with written procedures,
documented
instructions
or
drawings
appropriate
to the circumstances.
This concern constitutes
an Unresolved
Item pending additional
review and analysis
by both the licensee
and the
NRC
staff (UNR 250, 251/86-25-06).
Opera tiona1
Sa fety Verificati on (71707)
The inspectors
observed
control
room operations,
reviewed applicable
logs,
conducted
discussions
with control
room operators,
observed shift turnovers
and confirmed operability of instrumentation.
The inspectors
verified the
operability of selected
emergency
systems,
verified that maintenance
work
orders
had been
submitted
as required
and that followup and prioritization
of work was accomplished.
The inspectors
reviewed tagout records, verified
compliance with TS
LCOs
and verified the
return
to service
of affected
components.
By observation
and direct
interviews,
verification
was
made
that
the
physical security plan was being implemented.
Plant housekeeping/cleanliness
conditions
and implementation of radiological
controls were observed.
Tours of the intake structure
and diesel,
auxiliary, control
and turbine
buildings and Unit 4 containment
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
on Unit 3 and,
as applicable,
on Unit 4 to verify
operability and proper valve/switch alignment:
Emergency
Diesel Generators
4160 Volt and
480 Volt Switchgear
Control
Room Vertical Panels
and Safeguards
Racks
Two
examples
of
operations
personnel
failures
to properly
implement
procedures
were identified when they adversely affected plant operations.
A
third example
resulted
in the
inadvertent
start
of the
"B"
EDG.
The
requirements
for procedural
compliance
are specified below.
Technical Specification (TS) 6.8. 1 requires
that written
procedures
and
administrative policies
be implemented that meet or exceed
the
requirements
and recommendations
of sections
5. 1 and 5.3 of ANSI N18.7-1972
and Appendix
A of USNRC Regulatory Guide 1.33.
Appendix
A of
Regulatory
Guide
1.33
states
that
administrative
procedures
specifying procedure
adherence
should
be established.
'1 i
4
r,
'lC
I
10
Administrative
Procedur e
O-ADM-201,
Upgrade
Operations
Procedur e
Usage,
dated
December
4,
1985,
requires,
in
section
5.5. 1,
that
operating
procedures
be followed exactly
and that all personnel
comply with approved
procedures
applicable to the activity or circumstance
being performed.
Operating
Procedure
(OP)
1004.2,
Reactor
Protection
System
Periodic Test
(Unit 3 Only), dated
February 7,
1986, requires,
in section 8.61, that the
operator
proceed
to protection
instrument
rack
41 to perform train
"B"
reactor trip breaker testing.
Section 8.63 directs the operator to trip the
"B" reactor trip breaker.
On May 2,
1986,
an operator failed to properly
implement
OP 1004.2,
in that
while performing step 8.61
he remained at protection instrument rack 36 and,
while performing
step
8.63,
tripped the
"A" reactor trip breaker,
thereby
inadvertently tripping the Unit 3 reactor.
OP 4304. 1,
Emergency
Diesel Generator
Periodic Test
Load on
4KV Bus, dated
April 1,
1986, requires,
in section 8.3, that the starting air supply valve
be closed for the
emergency
diesel
generator
(EDG) being tested.
Section
8.7 requires
that the starting air supply valve for the
be
reopened
after completion of sections
8.3 through 8.6,.
On
May 2,
1986,
an operator failed to properly
implement
OP 4304. 1 on two
consecutive
occasions,
in that during
an initial start
of the
"B"
section
8.7
was not implemented,
causing
the
EDG to fail to start.
While
realigning
the
"B"
EDG for
a
subsequent
start
attempt,
the
operator
improperly
implemented
section
8.3,
in that
he
closed
the
starting air
supply valve for the "A" EDG rendering the "A" EDG temporarily inoperable.
Additionally, on May 9,
1986,
an operator
again failed to properly implement
OP 4304. 1, in that
he pressed
the local start button during step 8. 11 of the
procedure
instead of pressing
the fuel priming button.
This personnel
error
resulted
in the inadvertent start of the "B" EDG.
The
EDG was immediately
secured
and was subsequently
successfully tested.
These
three
examples
of procedural
noncompliance
together
constitute
a
failure to implement
TS 6.8. 1., which is
a Violation (250, 251/86-25-01).
Engineered
Safety
Features
Walkdown (71710)
The inspector
completed
a verification of the operability of the emergency
power
system
for Units
3
and
4
begun
in
Inspection
Report
Nos.
250,
251/86-17.
Additionally, the operability
of the
"A" and
"B"
was
verified by performing
a complete
walkdown of the accessible
portion of the
system.
The
following
specifics
were
reviewed
and/or
observed
as
appropriate:
a.
that the licensee's
system lineup procedures
matched plant drawings
and
the as-built configuration;
11
b.
that the
equipment
conditions
were satisfactory
and
items that might
degrade
performance
were identified and
evaluated
(e.g.
hangers
and
supports
were operable,
housekeeping
was adequate,
etc.);
c.
that instrumentation
was properly valved in and functioning
and that
calibration dates
were not exceeded;
d.
e.
that
valves
were
in proper position,
breaker
alignment
was correct,
power was available,
and valves were locked/lockwired as required;
local
and
remote
position
indication
was
compared
and
remote
instrumentation
was functional;
and
f.
breakers
and
instrumentation
cabinets
were
inspected
to verify that
they were free of damage
and interference.
Both
were
determined
to
be
However,
discrepancies
were
identified in the normal lineup procedure
and the
system
drawing
was
found
to contain inaccuracies.
Technical Specification (TS) 6.8. 1 requires
that written procedures
and
administrative policies
be established
and maintained that
meet or exceed
the
requirements
and
recommendations
of sections
5. 1
and
5.3 of ANSI
N18.7-1972Property "ANSI code" (as page type) with input value "ANSI</br></br>N18.7-1972" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process.
and Appendix A of USNRC Regulatory Guide 1.33.
Appendix
A of Regulatory
Guide
1.33
states
that
procedures
should
be
established
for the
startup,
operation
and
shutdown
of safety-related
equipment including instructions relative to emergency
power sources
such
as
diesel
generators.
Procedure
O-OP-023,
Emergency
Diesel
Generator,
dated
March 25,
1986,
provides
instructional
guidance
for the
startup,
normal
operation
and
shutdown of the
EDG system.
As of May 12,
1986,
0-OP-023 did not adequately
establish
procedures
for the
startup
and operation of the "A" and "B" EDGs, in that:
the procedure
did not address
the control of valves
292
and
293 for
either the "A" or "B" EDG radiator cooling water system drains
and did
not address
the drain valves for the "A" or "B" EDG fuel oil skid tank;
the
procedure
addressed
the
position
of skid tank
solenoid
valve
SV-3-3522
bypass
line isolation
valve
70-048A,
which
has
not
been
installed for the "A" EDG; and
the
procedure
did
not
address
the
control
of valve
269B for the
starting air flask drains for the "B" EDG.
The failure to establish
an adequate
procedure
as required
by TS 6.F 1 is a
Violation (250, 251/86-25-02).
3
12
Appendix
B, Criterion VI, as
implemented
by
FPL Topical Quality
assurance
Report
(FPL-NQA-100A) Revision
8,
TQR 6.0,
Document
Control,
requires,
in part; that the distribution of controlled
documents,
such
as
drawings,
which provide guidance,
specifications
or requirements
affecting
the quality of nuclear safety-related
structures,
systems
and
components,
shall
be controlled
and that Quality Procedures
shall delineate
the control
measures
for drawings,
including direction for the review for adequacy.
t
FPL Quality
Assurance
Manual,
Quality
Procedure
(QP) 6.6,
Revision
1,
delineates
requirements
for maintaining
the
drawing
update
program
and
assuring
that
drawings reflect
the
as-constructed
configuration
of the
sa fety-rel ated
system.
Administrative Procedure
(AP) 0103.10,
Using
and Updating Plant
Drawings,
dated
March 3,
1983,
implements
the
above
requirements
and specifies
that
drawings shall
be field verified to ensure
proper accuracy.
As of
May
13,
1986,
drawing
5610-T-E-4536,
Revision
0,
sheets
1
and 2,
entitled "Diesel Generator
A" and "Diesel
Generator
B", respectively,
were
not accurate,
in that:
the drawing sheets failed to show the existence
of a fuel oil skid tank
drain valve for each
EDG;
the drawing sheets
showed that valves
292A and 292B, drains for the
radiator cooling system,
were normally closed valves
when actually they
were normally open valves;
numerous
valve numbers specified
on the drawing sheets
conflicted with
the valve
numbers utilized by approved
operating
procedure
0-OP-023;
and
drawing
sheet
1
showed
the
presence
of starting air flask drain valve
269A, which does
not exist,
and drawing sheet
2 showed
a starting air
flask drain piping configuration which was not accurate.
The failure to meet the requirements
of 10 CFR 50, Appendix B, Criterion VI
is
a Violation (250, 251/86-25-03).
9.
Independent
Inspection
During the report period,
the inspectors'outinely
attended
meetings with
licensee
management
and monitored shift turnovers
between shift supervisors,
shift
foremen
and
licensed
operators.
These
meetings
included
daily
discussions
of plant operating
and testing activities
as well as discussions
of significant problems or incidents.
As a result,
the inspectors
reviewed
potential
problem areas
to independently
assess
their importance to safety,
the
adequacy
of proposed
solutions,
improvement
and progress,
and adequacy
of corrective actions.
The inspector's
reviews of these
matters
were not
limited to the defined inspection
program.
Independent
inspection effort
was conducted
in the area of EDG loading.
"4
%
~
13
10.
Plant Events
(93702)
An independent
review was conducted of the following events.
a.
April 23,
1986
Intake Cooling Mater (ICW) Temperatures
Above Limits
The
maximum allowable
ICW temperature
to the
Turbine
Plant Cooling
Water
(TPCW)
heat
exchangers
was limited by engineering
evaluation
JPE-PTP0-86-172,
dated
February
13,
1986,
as
a result of the potential
failure of
ICM valve
Engineering
evaluation
JPE-L-85-38,
Revision
1,
dated
February
16,
1986,
provided instructions
for the
operation of the
ICW system until permanent corrective actions could be
implemented.
The allowable
ICW temperature
varied with the fouling
level of the
ICM heat exchangers
and the
number of heat
exchangers
in
service,
as depicted in graphs
developed
by the Engineering
Department.
On April 23,
1986,
the
average
tube resistance
of the heat exchangers
was
0.00288
which allowed
a
maximum
ICW temperature
of 77.8 degrees
Fahrenheit
(F) for
two
heat
exchanger
operation.
The
"B"
heat
exchanger
was
removed
from operation for cleaning.
ICW temperature
was
verified to be 77.0 degrees
F.
Within three
hours the
ICW temperature
increased
to 77.5 degrees
F and the cleaning of the "B" heat exchanger
was halted
and preparations
were
made to restore its operability.
At
approximately
9:00 a.m.
the temperature limit was exceeded
and the "B"
heat
exchanger
was
not yet operable.
Restoration
of the
"B" heat
exchanger
was unexpectedly
hindered
by the discovery of
a tom cover
which
required
replacement.
This
caused
the
Maintenance
Department to exceed
the
one hour time frame in which they had
hoped to
return the heat
exchanger
to service.
The increase
in
ICW temperature
above that evaluated
in JPE-L-85-38,
Rev'ision
1,
placed
the
ICM system in an unanalyzed condition, in that
the Component
Cooling Water
(CCW) system,
which is cooled
by the
ICW
system,
was
suspected
to
be incapable of fulfillingits post accident
heat
removal
function.
requires
that
the
CCM system
be
and at 9:00 a.m.
on April 23,
1986,
the licensee
determined
that the
CCM system
was not capable of fulfillingits intended function
should
a large break loss of coolant accident coincident with a fai lure
of an
EDG and
a loss of offsite power occur.
At 10:00 a.m.
the licensee
began
a Unit 3 load reduction in preparation
for a reactor
shutdown
as required
by TS 3.0. 1.
At 10:30 a.m.
the "B"
heat
exchanger
was returned
to service
and the
ICM system
was again
operating
within
the
bounds
of
the
JPE-L-85-38,
Revision
1.
Consequently
the licensee
returned Unit 3 to full power operation.
0
( ~
kl
t
e
II
V
4
f
I
P'
t,
April 22,
1896 - Inoperability of the
Emergency Notification System
(ENS)
On April 22,
1986,
the
ENS telephone
was disconnected. in ~the.control
room to allow an additional
telephone
to
be connected
i'.n> the 'general
office building.
The
control
room
telephone
was 'returned
to
service
on April 23,
1986.
While the
ENS circuit was ',unavailable,
commercial
telephone
service
was available
and could have
been
used for
emergency notification purposes.
April 25,
1986
Failure of the "A" EDG to Close Onto the
4
KV Bus
At 9:27 a.m.,
during
a periodic test of the
"A" EDG, breaker
4AA20,
which connects
the
"A" EDG to the "4A" 4160 volt bus,
would not close
from the control
room.
The
"4B" 4160 volt bus
had
previously
been
deenergized
for routine
maintenance.
Unit
4
was
operating
in .cold
shutdown with the
"4A" Residual
Heat
Removal
(RHR)
pump operating.
Since the "A" EDG could not be connected
to the "4A" bus,
the "4A" RHR
pump did not have
a backup
power supply in the event offsite power was
lost.
Thus,
due to
a mechanical
failure, the action statement for TS 3.4. l.e. 1 was entered.
Breaker
4AA20 was returned to service following
adjustment of a type
"HH" interlock switch at 11:33 a.m.
Type
"HH" switches,
which are
common to several
4160 volt breakers,
have
caused similar problems
on previous occasions.
Modified switches
are
on order
and will be installed
when received.
Discussions
with the
licensee
regarding the adequacy of the corrective
action
and root cause
identification are still in progress
and will be addressed
and tracked
when the
LER for this event is issued.
May 2,
1986
Unit 3 Reactor Trip
Thi s
was
the
resul t of
per sonnel
error
during
the
performance of OP 100'4.2,
Reactor Protection
System Periodic Test.
The
plant responded
as
designed
during the post-trip transient.
However,
source
range
instrument
N-32 failed to energize
as
reactor
power
decreased
into the source
range.
Poor performance
of the source
range
instruments
has
been
a
frequent
problem.
On
November 30,
1985
and
March 5,
1986,
two previous
reactor trips occurred
during
which
one
source
range
instrument
failed to perform properly.
The failure to
follow procedures
during the implementation of OP 1004.2
was determined
to
be
one
part
of Violation
250,
251/86-25-01
as
discussed
in
paragraph
7.
The Unit 3 reactor
was returned to power
on
May 3,
1986.
May 2,
1986
"A" and "B" EDG Inadvertently
Placed out of Service
The "B" EDG was out of service during the Unit 3 reactor trip on May 2,
1986.
As
required
by
TS 3.0. 1.,
a
plant
cool
down
was
begun.
Preparations
were
made to test the
"B"
EDG to verify its return to
service.
As
a result of a personnel
error, the air start valve was not
opened
as required during the
EDG lineup for operation.
Consequently,
1
15
the
"B"
EDG failed to start
when the start
signal
was initiated,from
the control
room.
Subsequent
to correcting the lineup for the "B"
air start
system,
the
same operator
inadvertently closed
the air start
isolation valve
on the "A" EDG.
This rendered
the
"A" EDG inoperable
at
a time
when
the
"B"
had not yet
been verified to
be operable
following its maintenance.
The "A"
EDG air start valve
was quickly
opened after the air isolation resulted
in the loss of the ready start
light.
The
"A"
was
out of service
for just
a
few minutes.
Subsequent
to
these
personnel
errors,
both
were
tested
satisfactorily.
The personnel
errors
were determined
to constitute
a
violation of
TS 6.8. 1,
which requires
that
procedures
be
properly
implemented.
The violation (250, 251/86-25-01) is further discussed
in
paragraph
7.
May 4,
1986
"D" Motor Control Center
(MCC) Automatic Transfer Design
Error
The
licensee
previously identified tha't
the
"D"
MCC could fail to
transfer
to an energized
bus during cer tain failures of equipment,
such
as
loss of the
"3B" battery.
PCM 86-041
was installed
on Unit 3 to
correct
the
problem.
During
a design
review,
the licensee
determined
that
PCM 86-041 created
the possibility that the "D" MCC could transfer
from an operable
bus to
an inoperable
bus.
An engineering
evaluation
was performed which determined that the continued
operation of Unit 3
was justified (JPE-PTP0-86-1000,
dated
May 4,
1986)
as long as the "D"
was
manually transferred
to
an
bus within
20 minutes
following its
loss
of power.
Changes
were
made
to the
emergency
operating
procedures
to
incorporate
the
requirements
of
JPE-PTPO-86-1000.
The validity of the evaluation
was discussed
with
the
NRC Region II staff.
The
PNSC has since
approved
a modification to
PCM 86-041,
which provides
a timing relay to alleviate
the
problem.
The modification is to be installed in the near future.
May 9,
1986
Inadvertent
Manual Start of the "B" EDG
During preparation
for the
performance
of a periodic test
run of the
"B"
EDG,
a Turbine
Operator
failed to follow OP
4304.1
in that
he
pressed
the
diesel
start
button
instead
of
the
fuel oil
prime
pushbutton
as required
by step
8.11 of the procedure.
This personnel
error resulted
in the local start
of the
"B"
EDG.
The diesel
was
secured
and properly tested.
The failure to follow procedure
OP 4304. 1
was determined
to
be
a violation (250,
251/86-25-01)
and is further
discussed
in paragraph
7.
J
4
Ci
i'l
10(r