ML17342A320
| ML17342A320 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 12/05/1985 |
| From: | Brewer D, Elrod S, Peebles T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17342A318 | List: |
| References | |
| 50-250-85-37, 50-251-85-37, IEIN-85-082, IEIN-85-82, NUDOCS 8512230426 | |
| Download: ML17342A320 (18) | |
See also: IR 05000250/1985037
Text
~
~pa Racy,
(4
Mp0
0O
c Wp*y4
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323
Report Nos.:
50-250/85-37
and 50-251/85-37
Licensee:
Florida Power
and Light Company
9250 West Flagler Street
Miami, Florida 33102
Docket Nos.:
50-250
and 50-251
License Nos.:
and
Facility Name:
Turkey Point
3 and
4
Inspection
Conducted:
October
15 - November
12,
1985
Inspectors:
/
T. A. Peebles,
Senior Resident
Inspector
D.
R. Brewer,
Res1
nt Inspector
Appr'oved by:
t
Steph
n
.
lrod, Section
ief
Division of Reactor
Proje ts
2 -~-Z3-
Date Signed
-J=a ~
Date Signed
Date Signed
SUMMARY
Scope:
This routine,
unannounced
inspection entailed
205 direct inspection
hours
at the site,
inclu'ding 43 hour4.976852e-4 days <br />0.0119 hours <br />7.109788e-5 weeks <br />1.63615e-5 months <br /> s on backshift, in the areas
of licensee
action
on
previous
inspection
finding's,
annual
and
monthly
surveillance,
maintenance
observations
and
reviews,
operational
safety,
engineered
safety
features
walkdown,
and plant events.
Results:
Violation 'ailure to meet the requirements
of Technical Specification (TS) 4.5.2.b.3.
C [
8512230426
851209
ADOCK 05000250:
i
8
REPORT DETAILS
1.
Licensee
Employees
Contacted
- H.
J.
- D
J.
J.
- K.
B.
H.
D.
E.
D.
+J
R.
- R.
- J
0.
- F
R.
E.
V.
R.
E.
R.
p.
R.
W.
p.
J.
J.
L.
M.
"R.
R.
"R.
W.
T.
J.
- D
T ~
G.
RJ
<J
rojects
Supervisor
EP) Manager
M. Wethy, Vice President
Turkey Point
T. Young, Acting Plant Manager - Nuclear
P. Mendieta,
Services
Manager
Nuclear
D. Grandage,
Operations
Superintendent
Nuclear
A. Finn, Operations
Supervisor
Crockford, Assistant Operations
Supervisor
Webb, Operations
Supervisor's
Staff
L. Jones,
Technical
Department
Supervisor
A. Abrishami, Inservice Test
( IST) Supervisor
E.
Hartman,
Inservice Inspection (ISI) Supervisor
Tomaszewski,
Pl ant Engineering
Super visor
'.
Suarez,
Technical
Department
Engineer
A. Chancy,
Corporate
Licensing
Arias, Regulation
and Compliance Supervisor
L. Teuteberg,
Regulation
and Compliance
Engineer
Hart, Regulation
and Compliance
Engineer
W.
Kappes,
Maintenance
Superintendent
Nuclear
E. Suero, Electrical
Maintenance
Supervisor
H. Southworth,
Engineering
Department - Special
P
A. Longtemps,
Mechanical
Maintenance
Supervisor
F.
Hayes,
Instrument
and Control
( IC) Maintenance
A. Kaminskas,
Reactor'ngineering
Supervisor
G.
Mende,
Reactor
Engineer
LaPierre,
Chemistry Department
Supervisor
E. Garrett,
Plant Security Supervisor
W. Hughes,
Health Physics
Supervisor
M. Brown, Assistant Health Physics Supervisor
C. Miller, Training Supervisor
J.
Baum, Assistant Training Supervisor
M. Donis, Site Engineering
Supervisor
M. Mobray, Site Mechanical
Engineer
C. Huenniger,
Start-up Superintendent
J.
Cri sler, Quality Control
(QC) Supervisor
H. Reinhardt,
Quality Control Inspector
J. Earl, Quality Control Inspector
J. Acosta, Quality Assurance
(QA) Superintendent
Bladow, Quality Assurance
Supervisor
P. Coste, Backfit Quality Assurance
Supervisor
A. Labarraque,
Performance
Enhancement
Program
(P
W. Hasse,
Safety Engineering
Group Chairman
M. Vaux, Safety Engineering
Group Engineer
C. Grozan,
Licensing Engineer
Traczyk, Fire Protection
Department,
Price,
General Office, Plant Support Staff
D. Palmer,
Procedures
Upgrade Supervisor
0
"E. Priest, Auxiliary Feedwater
System
(AFW) Supervisor
- P.
L. Pace,
Licensing Engineer
- G. J. Boissy, Director of guality Assurance
Other
licensee
employees
contacted
included
construction
craftsmen,
engineers,
technicians,
operators,
mechanics,
electricians
and
security
force members.
"Attended exit interview.
2.
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
November
8,
1985.
The areas
requiring
management
attention
were reviewed.
One violation was identified:
Failure to meet
the requirements
of TS 4.5.2.b.3
in that accumulator
check
valve operability
was
not
adequately
determined
in that leak
testing to support the functions described
in the Final Safety Analysis
Report
(FSAR) was not performed (paragraph
5) (250,251/85-37-01).
One Unresolved
Item (UNR) was identified:
Determine
whether
the
Nuclear
Watch
Engineer,
as fire brigade
team
leader,
can
assume
the responsibilities
of
a Senior
Reactor
Operator
(paragraph
7)
(UNR 250,251/85-37-02).
One Inspector
Followup Item (IFI) was identified:
Evaluate
the extent to which the control
room noise level
has
increased
subsequent
to
removing
the
ceiling
insulation
(paragraph
7)
(IFI
250,251/85-37-03).
The licensee
did not identify as proprietary
any of the materials
provided
to or
reviewed
by the
inspectors
during this inspection.
The
licensee
acknowledged
the findings without dissenting
comments.
3.
Licensee Action on Previous
Inspection
Findings
(92702)
a
0
Performance
Enhancement
Program
(PEP)
TS and
FSAR Operability Review
The licensee
has
been
performing reviews of the
TS and
FSAR to identify
systems
and
components
which
were
not
receiving
comprehensive
operability testings
The results
of these
reviews
are being included
in the
TS rewrite
and
in the surveillance
program.
The
comprehen-
siveness
of this
program
is
an
area
of concern
since
independent
evaluations
of the
reviews
performed
to date
have
shown that all
components
which would benefit
from enhanced
operability testing
have
not been identified.
Previously Identified Items
(OPEN)
UNR 250,251/85-24-04.
In
Inspection
Report
250,251/85-24,
issued
on
July 30,
1985,
a
concern
was
raised
as
to
when
the
should
be operable.
The Turkey Point
TS require only that
the
be
prior to reactor criticality.
Newer
plants,
operating
under standardized
TS, are required to have
when
primary coolant
pressure
is
above
1000
pounds
per
square
inch (psi).
However,
the
Turkey Point
and
standard
TS
both
require
a critical reactor
to
be
shutdown
and
cooled
down if the
are unavailable for an extended
period of time.
Operating
Procedure
(OP)
0202. 1,
Reactor
Startup - Cold Condition to
Hot Standby
Condition,
requires
that the accumulator isolation valves
be
locked
open
when
primary
coolant
pressure
reaches
1000
psi.
However,
section
8.34
of
the
procedure
states
only
that
the
"should" be filled and pressurized
prior to reaching
1000
psi.
Plant
procedures
specify that
"should" is used
to denote
the
non-mandatory
nature of a procedural
step.
Mandatory procedural
steps
generally
specify
that
a
certain
procedural
step
"shall"
be
accomplished.
The
use of
a
non-mandatory
"should" in section
8.34 of OP 0202
F 1 has
resulted
in the
isolation valves being
opened at
1000 psi
without the
being filled to
normal
water
levels
and
pressures.
Between
June
23
and
June
26,
1985,
the accumulators
were
uni solated
but empty and depressurized
while primary pressure
was
2235
psi .
The accumulators
are designed
to refill the reactor vessel
following a
loss of coolant accident
(LOCA).
The
FSAR for Turkey Point does
not
contain
an
evaluation
of
the
consequences
of
a
LOCA with the
unavailable.
Consequently.,
it is
not
apparent
that
excessive
fuel
temperatures
would
be
avoided
in the
event
such
an
accident
were to occur.
This is especially
true if the
were unavailable
(due to low pressure,
low water level or isolation
valve closure)
following a reactor trip and
a
LOCA.
This worst case
event would involve the
maximum possible
reactor fuel decay
heat load.
The
NRC is currently performing
an evaluation
of the safety
concerns
associated
with accumulator unavailability at
a time when the
TS allow
such
an unavailability.
The plant management
staff has
been
aware of this concern
since it was
raised
in July
1985.
However,
as of November
14,
1985,
the
licensee
has
not performed
an evaluation
of the consequences
of a
LOCA without
the accumulators
available
while the reactor
is subcritical.
Prior to
November
1985,
no staff
member
was
assigned
to
pursue
the matter.
Procedures
allowing the
accumulator s to
be placed
in ser vice without
normal
level
and pressure
have
not
been
modified.
This
item remains
open
pending
NRC evaluation
and analysis.
(Closed)
IFI 250,251/85-24-07,
Determine
Adequacy of Accumulator Check
Valve
Leak Testing.
This item
has
been
determined
to
be
a violation
and is discussed
in paragraph
5.
Corrective action will be tracked
as
Violation 250,251/85-37-01.
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.
One Unresolved
Item was identified during this inspection
and is discussed
in paragraph
7.
One previously identified Unresolved
Item is discussed
in
paragraph
3.
5.
Monthly and Annual Surveillance
Observation
(61726/61700)
The inspectors
observed
TS - required surveillance
testing
and verified the
following: 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:
Units
3 and
4
AFW Train
1 Operability Verification
Units
3 and
4
AFW Train
2 Operability Verification
Unit 3 Reactor Protection
System Periodic Test
Units
3 and
4 Safeguards
Periodic Test
Unit 3 Primary System
Flow Transmitter Calibration
Unit 4 Control
Rod Exercising Periodic
In Inspection
Report 250,251/85-24,
an IFI was established
to determine
the
adequacy
of OP 4504. 1, Accumulator
Check Valve Backleakage
Periodic Test,
with respect
to accumulator
testing
as described
in section
6.2 of the
( IFI 250,251/85-24-07)
.
TS 4.5.2.b. 3
requi res
that
accumul ator
check
va 1 ves
be
checked
for
operability during each refueling shutdown.
The
FSAR,
section
6.2.4,
states
that
test
circuits
are
provided
to
periodically examine
the
leakage
back through the accumulator
and to ascertain
that these
valves
seat
whenever
the reactor
system pressure
is raised.
Section 6.2.3 of the
FSAR states
that the accumulator discharge
valves are closed during the check valve leak testing.- Section 6.2.2 of the
FSAR states
that
each
is isolated
from the main coolant
system
by two check valves in series.
The
check valves closest to the main coolant loops (valves
875 A,
B and
C)
are leak tested at least
each refueling
shutdown in accordance
with
TS 4. 17
and are limited to
no
more
than
5 gallons
per minute
leakage
by
TS 3. 16.
The valves
have
a very low leakage
rate.
OP
4504. 1 determines
total
leakage
into
each
by monitoring
level changes.
Increasing
levels
are
assumed
to
be the result
of leakage
past the series
However,
since valves
875 A,
B and
C do not leak,
no water
reaches
valves
875
D,
E
and
F.
Consequently,
OP
4504. 1
does
not test
for
leakage
past
check
valves
875
D,
E
and
F.
Additionally, the procedure
does
not measure
leakage
out of the accumulators
via
other
available
flowpaths.
Since
some
are
known
to
experience
out-leakage, it is possible that the accumulator
level
change is
not indicative of the leakage. in through the series
Contrary to the above,
subsequent
to 1976,
was not implemented,
in that
check
valves
875
D,
E
and
F were
not periodically
examined
to ascertain
that they were seating
nor were they tested for back
leakage.
Testing
which was
performed
was
inadequate
in that
only check
valves
875
A,
B
and
C
were
verified to
be
seated
and
not
leaking
excessively.
The failure to implement the requirements
of
is
a violation
(250,251/85-37-01).
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 what took place; 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:
Unit 3A Residual
Heat
Removal
pump repair
Unit 3 Motor Operated
Valve grease
change
Unit 3 Steam Generator
blowdown pipe hanger repair
Unit 3 Condenser
Boot seal repair
Standby
Pump discharge
pressure
gage repair
Unit 3 Accumulator fill valve repair
system nitrogen leak repair
Unit 3 Auxiliary Feedwater
steam emit valve repairs
Unit 3 Condensate
Storage
Tank level indicator repairs
Within this area,
no violations or deviations
were identified.
7.
Operational
Safety Verification (71707)
The inspectors
observed
control
room operations,
reviewed applicable
logs,
conducted
discussions
with control
room operators,
observed shift turnovers
and confirmed operability of instrumentation.
The inspectors
verified the
operability of selected
emergency
systems,
verified that maintenance
work
orders
had been
submitted
as required
and that follow-up and prioritization
of work was accomplished.
The inspectors
reviewed tagout records,
verified
compliance with
TS
LCOs
and verified the
return
to service
of affected
components.
By observation
and direct
interviews,
verification
was
made
that
the
physical
security plan was being implemented.
Plant housekeeping/cleanliness
conditions
and implementation of radiological
controls were observed.
Tours of the intake structure
and diesel,
auxiliary, control
and turbine
buildings were
conducted
to observe
plant
equipment
conditions
including
potential fire hazards,
fluid leaks
and excessive
vibrations.
The
inspectors
walked
down
accessible
portions
of the following safety-
related
systems
on Unit
3
and
Unit
4 to verify operability
and
proper
valve/switch alignment:
Emergency
Diesel Generators
(EDG)
4160 volt and
480 volt switchgear
Containment
Spray
Containment Penetrations
(Unit 3 only)
Nuclear Instrumentation
Drawers
Refueling Water Storage
High Head Safety Injection
Control
Room Vertical Panels
Emergency Boration and Chemical
and Volume Control
During daily tours
of the control
room,
the inspectors
noticed that the
Nuclear Match Engineer
(NWE) was usually assigned
as
the fire brigade
team
leader.
While the
NWEs are trained for this responsibility,
they are also
licensed
Senior Reactor Operators
(SROs).
In this capacity,
they assist
the
Plant Supervisor
Nuclear
(PSN)
and could serve
as the
SRO in charge of the
two units when the
PSN is out of the control
room.
The
may
be required
to leave
the control
room for many
reasons.
For
example,
each
makes
a
tour
of
the
site
once
during
shift.
Additionally, the
day shift
PSN conducts
a morning plant status
briefing
each
day in the administration building. It is not uncommon for the
PSN to
be absent
from the control
room for an
hour during
a typical
eight-houi
shift.
In the
PSN's
absence,
the
NWE is requi red to remain in the control
room in
accordance
with 10 CFR 50.54.
However, if the
NWE is also the fire brigade
team leader,
he is required to proceed to any fire scene
and direct the fire
brigade's
damage
control effort.
It was determined
that the licensee
has not established
any administrative
instructions
covering
this
eventuality.
Consequently,
some
NWEs
are
uncertain
as to which responsibility
to fulfill. Discussions
with some
NMEs
revealed
that they would
make
a decision
based
on the size
and location of
the fire and
the status
of the operating
units.
Most
NWEs indicated that
they would delay proceeding
to the fire scene until the
PSN returned to the
control
room.
They would then quickly appraise
him of the status
of the
units prior to leaving the control
room.
If a fire were to occur in conjunction with
event,
such
as
a
reactor trip, the advisability of
a quick exchange
of information
between
the departing
NWE and the returning
PSN is questionable.
Appendix
R,
section III, item
H specifies
that
the shift
supervisor
shall
not
be
a
member of the fire brigade.
Mhen
the
PSN is
absent
from the control
room the
NWE (as
the available
SRO is responsible
for supervising
the
operation
of the
nuclear
units
and is
tasked
with
directing
the shift's
response
to transients
and
accidents.
In this
capacity,
he is temporarily fulfilling the duties
and responsibilities
of
the shift supervisor.
Consequently,
in the absence
of the
he could be
considered
a
de facto shift supervisor.
While acting
in this capacity
he
would
not
be
able
to
the fire brigade
should
the
need
arise.
Additionally, in the event of a fire in conjunction with
event
he
might,
in his
haste,
fail to exchange
pertinent
information with the
returning
PSN concerning
the status of the units.
The assignment
of the
NWE as fire brigade
team leader while he is the sole
in the control
room
may
be contrary
to the
intent of
Appendix
R, section III, item H.
This issue constitutes
an Unresolved
Item
pending
interpretation
and resolution
by both
the
licensee
and
the
NRC
Region II fire protection specialists
(UNR 250,251/85-37-02).
During the last
several
months
the
licensee
has
removed
large
amounts
of
insulation
from the cei ling of the control
room.
The licensee
has
stated
that
replacement
is
not
required
from
a fire
protection
standpoint.
However, lack of insulation
may have contributed to an increase
in the noise
level
in the
control
room
due
to
decreased
sound
dampening
without the
insulation.
The
licensee
has
agreed
to
review
the
noise
suppression
characteristics
of
the
uninsulated
ceiling
to
determine if the
sound
dampening
characteristics
have
diminished.
The
adequacy
of the acoustic
characteristics
of the uninsulated
ceiling with respect
to noise
abatement
is an Inspector
Follow-up Item (IFI 250,251/85-37-03).
Within this area,
no violations or deviations
were identified.
8.
Engineered
Safety Features
Walkdown (71710)
The inspector verified operability of the
AFW system,
which is
common to
Units
3 and
4 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;
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.
that
valves
were
in proper position,
breaker
alignment
was correct,
power was available,
and valves were locked/lockwired
as required;
e.
local
and
remote
position
indication
was
compared
and
remote
instrumentation
was functional;
f.
breakers
and
instrumentation
cabinets
were
inspected
to verify that
they were free of damage
and interference.
Within this area,
no violations or deviations
were identified.
9.
IE Information Notice Followup (92717)
(Open)
Diesel
Generator Differential Protection
Relay
Not Seismically Qualified.
The licensee
has verified that
General
Electric relays,
model
12CFD, are
used in the differential relay circuits of
both
EDGS.
The licensee
has
developed
Plant
Change/
Modifications (PC/M)84-157
and
84-158
which will remove
the sensitive
relays
and substitute
1I '
rel ays
less
susceptible
to
sei smi c
shock.
The
PC/Ms
are
scheduled
for
implementation
during
scheduled
EDG preventive
maintenance
on
November
20
and 21,
1985.
Three relays will be changed
in each
EDG control cabinet.
10.
Independent
Inspection
During the report
period the inspectors
routinely attended
meetings
with
licensee
management
and monitored shift turnover s 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
efforts were conducted
in the following areas:
AFW system
enhancement
Maintenance
management
controls
Fire brigade staffing
Commitment tracking procedures
Main Steam Isolation Valve operability
Operations
and Engineering
Departmental
support
Accumulator operability requirements
Periodically,
the
inspectors
attended
the daily morning planning
meeting
which is conducted
by the
PSN.
Within this area,
no Violations or Deviations were identified.
11.
Plant Events
(93702)
An independent
review was conducted of the following events.
On October
16,
1985,
at 8:30 a.m.,
a Unit 4 4160 volt breaker tripped and
de-energized
the
4A 480 volt load center.
The breaker
was
inspected
and
returned to service with no abnormalities
found.
A review of the
equipment
affected
by the
bus
de-energization
indicated
that
no
TS
equipment
was
On October
16,
1985,
notified the licensee that
a discrepancy
was identified between
the
FSAR and
an assumption
used in the Westinghouse
LOCA analysis.
During loss of offsite power,
the loss of one of four high
head
safety
injection
pumps
was
assumed,
whereas
a single failure could
actually disable
two
pumps.
estimates
that
the
increase
in
peak fuel clad temperature will be less
than
20
Fahrenheit
(F) which will
still be within acceptable
limits.
On October
18,
1985,
at
12:17 p.m.,
a
small fire occurred
in the Unit 4
start-up
transformer
relay cabinet.
The licensee
evaluated
the
damage
and
determined that off-site power availability was not affected
~
10
On October
19,
1985,
both units
were
reduced
to
50 percent
power
and the
Unit
4
start-up
transformers
was
removed
from
service
to facilitate
modifications for the auxiliary power
system
upgrade.
This
was
a planned
evolution.
On October 23,
1985, Unit 3 was in cold shutdown
and the
B
EOG was taken out
of service for maintenance.
Normal testing
was performed
on the
3A residual
heat
removal
(RHR)
pump which
showed
greater
than allowable
seal
leakoff.
The
3A RHR pump was left in standby until the
B
EOG was returned to service.
TS 3.4. l.e. 1 requires
that
two coolant
loops
be operable
when
the unit! s
reactor
coolant
(RC) temperature
is less
than
350'F
and with the
B
EOG
the
B
RHR pump was technically inoperable.
On October 24,
1985,
narrow range
sump level indicator LI 6308B was found to
have
been installed in
an
area
susceptible
to neutron
streaming
and
was
therefore
not within its equipment qualifications.
LI 6308A had
been out of
service
since July 1985.
With both channels
out of service,
the thirty day
allowable period of inoperability expired in August 1985.
The
B channel
was
relocated prior to unit restart.
On October
26,
1985,
Unit
3 was in cold shutdown operating
the
B
RHR pump
with the
A
pump out of service for maintenance.
A low flow alarm was
received
due
to
one of the
suction
valves
auto-closing.
Investigation
revealed
a
defective
relay
which= was
replaced.
A
20
F rise
in
RC
temperature
occurred before the loop was returned to service.
On
November
5,
1985,
a Unit
3 start-up
was in progress
when
a train
1
flow transmitter
was
found
reading
erroneously
high
by
25 gallons
per
minute.
A unit cooldown
was,
commenced
while I
8
C technicians
vented
the
transmitter.
Cooldown
was
stopped
when this venting appeared
to clear the
offset problem.
About eight hours
later,
the
flow indication
was
again
found reading
25
GPM high.
Another plant cooldown was
commenced while I&C
was investigating
the problem.
A recalibration
of the
loop indicated that
an electrical offset was the problem. It was corrected
and the cooldown was
stopped.
On
November
10,
1985,
a Unit
3 pressurizer
power
operated relief valve
(PORV), PCV-3-456,
was found to be leaking in excess
of the
TS limit during
a pressurizer
spray
valve test.
PCV-3-456
was
declared
its
block valve closed
and its breaker
racked out.
The leak rate through the
other
PORV was found to be within the
TS limit but greater
than desired
and
therefore its block valve was closed.
On
November
11,
1985,
the
emergency
notification system
(ENS)
was
found
and reported.
Within this area
no violations or deviations
were identified.
c
0
0