ML18038B610
| ML18038B610 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 01/29/1996 |
| From: | Lesser M, Wert L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18038B608 | List: |
| References | |
| 50-259-95-64, 50-260-95-64, 50-296-95-64, NUDOCS 9602120066 | |
| Download: ML18038B610 (60) | |
See also: IR 05000259/1995064
Text
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UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W., SUITE 2900
ATlANTA,GEORGIA 30X94199
Report Nos.:
50-259/95-64,
50-260/95-64,
and 50-296/95-64
Licensee:
Valley Authority
6A 38A Lookout Place
1101 Harket Street
Chattanooga,
TN
37402-2801
Docket Nos.:
50-259,
50-260,
and 50-296
License Nos.:
and
Facility Name:
Browns Ferry Units 1, 2,
and
3
Inspection. Conducted:
November
19 - December.
30,
1995
Inspector:
eo ar
.
e
,
r.,
endor
ess
ent
nspector
a e
sgne
Approved by.
J.
Hunday,
Resident
Inspector
R. Husser,
Resident
Inspector
H. Horgan,
Resident
Inspector
R. Aiello,
DRS Inspector
(paragraph
2.2)
P. Byron, Resident
Inspector,
Brunswick (paragraph
2.2)
L. Garner,
DRP Project Engineer
(paragraph
2.2)
H. Janus,
Resident
Inspector,
Brunswick (paragraph
2.2)
R. Kopriva,
DRP Project Engineer,
Region
IV (paragraph
2.2)
C. Patterson,
Senior Resident
Inspector,
Brunswick (paragraph
2.3)
T. Tongue,
DRP Project Engineer,
Region III, (paragraph
2.2)
//z~/FI,
'r
.
esser,
>e
Reactor Projects
Branch
6
Division of Reactor Projects
ate
tgne
SUHHARY
Scope:
Inspections
were conducted
by the resident
and other inspectors
in the areas
of operations
which included the Unit 3 restart,
review of biological shield
block removal practices,
and several fire protection issues;
maintenance
whi'ch
included routine observations,
post maintenance
testing issues,
deficiencies
Enclosure
2
9602120066
960l29
ADOCK 05000259
8
f
il
associated
with a freeze seal,
4160 volt breaker work activities,
and review
of open items; engineering
which included secondary
containment ventilation
damper failures,
narrow range torus water level issues,
and recirculation
pump
seal
purge effects
on the nuclear heat balance calculation; plant support,
and
review of NRC Operational
Assessment
Team findings.
The inspection of the
Unit 3 restart
included continuous
NRC control
room monitoring for a period of
about two weeks.
Results:
Plant
0 erations
Unit 3 was started
up during this report period after being shutdown for about
ten years.
Throughout the startup,
strong
management
involvement was noted.
Overall, equipment
problems
were minimal.
Although
a small .number of
personnel
performance
and procedural
problems occurred,
the issues
were
limited and addressed
promptly.
No multiple unit operation or "wrong
component"
issues
were noted during the entire startup.
(Paragraph
2.2)
Several
deficiencies
involving fire protection issues
were identified:
A violation was identified:addressing
two problems associated
with fire
protection program equipment.
Although the underlying causes
of the two
instances
were different, both resulted
in fire 'protection
equipment
being inoperable without compensatory
actions.
(Violation 296/95-64-01,
Fire Protection
Program
Equipment Inoperable Without Compensatory
Actions, paragraph
2.6).
A non-cited viol'ation was identified due to
a fire watch not performing
his duties
as required
by procedures.
(NCV 50-296/95-64-04,
paragraph
2.8).
ll
An unresolved
item was identified during followup review of'n ORAT
finding.
Procedural
requirements
for control of ventilation systems
in
the event of a fire appear to insufficiently incorporate
statements
in
the Fire Protection
Report.
(Unresolved
Item 260,296/95-64-08,
Fire
Damper Procedural
Controls,
paragraph
6. 1).
A non-cited violation was identified when control
room operators
did not
position the high pressure
coolant injection flow controller switch as
required
by a checkl'ist.
Operabil'ity of the system
was not affected.
(NCV
296/95-64-05,
HPCI Flow Controller Switch not In AUTO, paragraph
2.3).
During 'review of ORAT findings,
a non-cited violation was identified
associated
with control
room operators
not logging information required
by
procedures
to be logged.
(NCV 296/95-64-07,
Failure to Record Information in
Unit Logs,
paragraph
6.2).
II
0
Haintenance
A non-cited violation was identified involving deficiencies during thawing of
a freeze seal.
Coordination
and communications
between
Operations
and
Haintenance
personnel
were not satisfactory.
Furthermore,
Haintenance
workers
did not perform procedure
actions sequentially.
(NCV 296/95-64-02,
Deficiencies Involving Control of Freeze
Seal,
paragraph
3.2).
A non-cited violation was identified which addressed
several
examples of
failure to complete post maintenance
testing prior to returning equipment to
service.
Good Operations
and Haintenance
management
actions
were noted in
identification and investigation of the issues.
(NCV 296/95-64-03,
Equipment
Returned to Service Without Proper
PHT Completion,
paragraph 3.3).
During observation of snubber maintenance,
minor problems
were identified with
the applicable
procedures
and the use of the procedures.
(IFI 260,296/95-64-
11, Thread Lubricant Effects
On Torque Values,
paragraph
3. 1).
During review of ORAT findings,
a non-cited violation was identified involving
instances
in .which personnel
did not adequately
implement requirements
for
procedural
revisions during testing or maintenance activities.
(NCV 296/95-
64-06, Failure to Follow Requirements
for Procedure
Changes,
paragraphs
6.3
and 6.4).
En ineerin
Supervision of the Unit 3 power ascension
testing
was strong.
The overall
solid personnel
and equipm=iit performance
resulted
in the completion of the
testing
program well ahead of schedule.
Additionally, it was noted that the
licensee's
application of lessons
learned
from the Unit 2 Restart,
regarding
flexibility in scheduling of testing activities, resulted
in an efficient test
program.
(paragraph
2.2).
Several
failures of secondary
containment ventilation system
due to
solenoid failures
have occurred
over the last several
months.
The licensee
has
been adequately
pursuing the root cause
and long-term resolution of the
problems.
During review of a recent
damper failure, the inspectors
questioned
short-term operability of similar dampers.
The licensee
subsequently
initiated replacement
of critical damper solenoids
on an accelerated
schedule.
(Inspector
Followup Item 260,296/95-64-10,
Secondary
Containment Ventilation
Damper Failures,
paragraph
4. 1).
A non-cited violation was identified involving errors in a calculation for the
setpoints of narrow range torus water level indication.
This error had
occurred
several
years
ago
and the overall safety significance
was small.
(NCV 260/95-64-09,
Violation of Torus Water Level TS, paragraph 4.2).
Plant
Su
ort
Improvements
were noted involving a previously identified access
control
weakness.
(paragraph
5).
0
II
REPORT DETAILS
Acronyms used in this report are defined in paragraph
8.
1.0
PERSONS
CONTACTED
Licensee
Employees:
Brazell R., Site Security Manager
Coleman R., Radiological Controls Manager
Corey J.,
Chemistry .and Radiological Controls Manager
Cornelius
T
,
Emergency
Preparedness
Manager
- Crane C., Assistant Plait Manager
- Johnson J., Site equality Manager
Jones
R., Unit 3 Startup
Hanager
- Little. G., Operations
Superintendent
- Hachon R., Site Vice Presi'dent,
Browns Ferry
Haddox J.,
Maintenance
and Modification Manager
Moll R., Plant Operations
Manager
Pierce
G., Technical
Support
Manager.
Preston
E., Plant Manager
Sabados J.,
Chemistry Manager
Salas
P., Licensing Manager
Shriver T., Nuclear Assurance
and Licensing Hanager
Wetzel S., Acting Compliance Licensing Manager
- Williams H
, Engineering and'aterials
Manager
Other licensee
employees
contacted
included office, operations,
engineering,
maintenance,
and chemistry/radiation
personnel..
2.0
PLANT OPERATIONS (71707,
71715,
92901,
40500)
2.1
OPERATION STATUS AND OBSERVATIONS
Unit 2 operated
at power during this inspection period.
Unit 3 was restarted
after an extended
shutdown.
Paragraph
2.2 discusses
NRC review of the startup
which included continuous control
room monitoring.
Some inspections
were
condu'cted
on day and night shifts, during weekdays
and
on weekends.
Observations
included control
room manning,
access
control, operator
professionalism
and attentiveness,
and adherence
to procedures.
Instrument
readings,
recorder traces,
alarms, operability of nuclear
instrumentation
and reactor protection
system channels,
availability of power
sources,
and operability of the Safety Parameter
Display System were
monitored.
Daily di'scussions
were held with plant management
and'arious
members of the
plant operating staff.
One of the inspectors
attended
the daily Plan of the
Day meetings.
Routine plant tours were performed throughout the reporting
period.
Observations
included valve position
and system alignment,
and hanger conditions,
containment isolation alignments,
instrument readings,
~
2'.3
FLOW CONTROLLER SWITCH NOT IN CORRECT POSITION
On November 23,
1995,
an
NRC inspector noted that the
HPCI flow controller was
in, BALANCE instead of AUTO.
at this time having completed
hot quick start test earlier in the day.
The inspector inquired about the
system status with a unit operator.
The operator
researched
the last
procedures
performed to be sure of the system status
and alignment.
Within
minutes,
the oncoming
SOS toured the control board
and inquired about the
same
switch position.
This occurred
independent of any discussion with the
-inspector
and was noted
as
a good observation
by the
SOS.
It was determined
that during the run of the HPCI, the switch should
have
been returned to AUTO.
There is
a procedural
step which requires
a signature attesting to this switch
position.
The switch was subsequently
returned to AUTO and the licensee
initiated
a
PER to document the problem.
This issue
was discussed
in subsequent
shift operations shift turnover
meetings
as
a significant problem since it was
a mispositioned
switch that had
been repositioned
by
a procedure requiring
a signature.
This problem was not
identified during the next shift turnover following, operation of HPCI.
Also
mentioned in the turnover meeting
as
a factor in not catching the error,
was
that only partial control board walkdowns were conducted
due to every operator
having specific tasks to do.
It was emphasized, that complete
board walkdowns
and reviews would be conducted
and the time to do it correctly would be
allowed.
The mispositioned, switch did not affect the operability of HPCI.
Inspectors
noted that this is the
same type controller used for the feed
pumps
and the
controllers, are routinely operated
in BALANCE instead of AUTO.
The reason for
running the feed
pumps in BALANCE is that
a failure of a controller will allow
quick shifting to manual.
This will shift to the last,setting before the
failure and possibly avoid
a transient.
One operator indicated that he
regarded
the two switch positions
as equivalent since the functioning of HPCI
was essentially
the
same.
This operator
was retrained
on procedural
compliance
aspects
of the issues.
The inspectors
concluded that corrective
actions
taken in response
to the mispositioned
HPCI switch were prompt
and'ppropriate.
This licensee-identified
and corrected violation is being treated
as
a Non-
Cited Violation, consistent with Section VII.B.I of the
NRC Enforcement
Policy.
This issue is addressed
as
NCV 296/95-64-05,
HPCI Flow Controller
Switch not in AUTOS
a
2.4
NODE SWITCH KEY NOT IN SMITCH
On November '20,
1995, with Unit 3 in the startup
mode
and at approximately
3 percent
power, the inspector
noted that the mode switch key was not
installed in the
mode switch.
The inspector brought this to the attention of
the operations shift manager.
Within 10 minutes,
the key was located in the
Unit 3 key locker and placed in the
mode switch.
The inspectors
were
concerned that, if required,
the
mode switch could not be placed in the
shutdown position without the key installed.
(One of the initial operator
actions following a-reactor
scram is to place the
mode switch in the shutdown
position).
The primary manual scram switches
were. operable
at -the time.
After additional questioning
the licensee verified that the mode switch could
not be repositioned without the key installed.
This m>tter represents
an
example of poor procedural
controls of a safety related
component.
Corrective
action for this matter involved preparing
a night order directing operators
to
keep the key in the
mode switch at all times during plant operation.
The
inspectors
considered
the licensee's
corrective actions, related to this matter
as adequate.
2.5
FAILURE OF RESIDUAL HEAT REMOVAL VALVE TO FULLY SHUT CAUSES
UNEXPECTED
REACTOR WATER LEVEL DECREASE
On November
18,
1995, with Unit 3 in cold shutdown
and operators
making final
preparations
for the restart of the unit, unexpected
reactor water level
decreases
occurred during the operation of RHR;valves associated
with shutdown:
cooling.
Specifically, at approximately
1: 10 a.m., control
room operators
were attempting to place loop II of RHR into the shutdown cooling mode of
operation
when reactor water level
began decreasing
(Loop II of RHR is
comprised of the
3B and
3D
RHR pumps).
The shutdown cooling flowpath to the
suction of the
RHR pumps is from the "A" recirculation loop, through the two
containment isolation valves
(74-48 and 74-47)
and one of the four pump
suction valves
(74-2
[RHR pump 3A], 74-13
[RHR pump 3C], 74-25
[RHR pump 3B],
and 74-36
[RHR pump 3D]).
When the operators
opened
74-47 and'8,
vessel
level decreased
from 34 inches to 24 inches over several
minutes.
'Initially,
it was thought that the decrease
was caused
by filling of the
RHR piping.
After several
more cycles of 74-47
and
48 and
an investigation
by shift
operations
personnel,
the problem was traced to leakage
through the 74-13
valve (the shutdown cooli"", suction to the
3C
RHR pump).
Because
the
3C
pump is in loop I of RHR which was aligned in "standby"
(ready for the
mode of operation),
the valve between
the torus
and the
3C pump (74-12)
was
open.
The 74-13 leakage
permitted
a direct flowpath from the reactor vessel
(through the 74-12) to the torus.
The lowest reactor level reached
during
these evolutions
was
22 inches.
The setpoint for shutdown cool.ing
1'ow level
isolation is
11 inches with the top of active fuel located, at approximately
-165 inches.
Although 74-13 indicated fully closed
by remote indication,,an operator
was
able to operate
the valve's actuator
hand wheel
approximately
20 turns in the
closed direction.
This corresponded
to only a fraction of a turn on the valve
stem.
Valve 74-13 closes
on torque
and the close indication limit switch is
set for 2-5 percent
open.
Subsequent
to the event,
the licensee
determined
that the torque switch was set at
a low value within the vendor's
acceptable
range.
The torque switch setpoint
was increased
and valve was successfully
cycled
a number of times.
It should
be noted that 74-13 is not addressed
by
the licensee's
GL 89-10 or 10
CFR, 50 Appendix J programs.
Following the event,
the inspectors
performed
an extensive
review of control
room chart 'recorders,
logs,
and
SPDS data.. Although problem i'dentification
required several
cyclings of the 74-47
and
48 valves
and extensive
investigation,
the inspectors
concluded that operator
performance
was adequate
and procedures
were followed.
The matter
was documented
on
PER 95-1752 .with
corrective action assigned
to the maintenance
valve engineering
group.
hi
~$0
Immediate corrective actions
involved electrically stroking the other
3
pumps'hutdown
cooling suction valves
(74-2,
25,
and 36)
and then manually engaging
the valves to ensure
they had fully closed.
No problems with these
valves
were identified.
Other corrective actions to be performed in the near term,
are
as follows;
1) Revise procedure
ECI-0-000-HOV001, (Electrical Corrective
Instruction Maintenance for Limitorque Motor Operated
Valves), to include
steps
to electrically stroke the valve and manually verify that it has torque
seated.
Additionally, steps
are scheduled
to be added to ensure
settings will be returned to the as-found setting
on non
GL 89-10 valves
following maintenance
(In the past,
the torque switches
were returned to
a
minimal setting following maintenance).
2) This matter is scheduled
be
reviewed with plant maintenance
personnel.
3) Valve engineering
personnel
are
scheduled
to review as-left torque switch settings
on safety-related
non
GL 89-10 valves
and verify that they are the
same
as the as-found settings.
These matters
are scheduled
to be completed
by March 31,
1996.
The inspectors
have concluded that licensee corrective actions for this matter are
acceptable.
2'.6
FIRE
PROTECTION PROGRAM'QUIPMENT INOPERABLE WITHOUT COMPENSATORY
ACTIONS
During this report period,
two instances
were noted in which equipment
required to be operable
by the fire protection
program was inoperable
and
compensatory
actions
were not taken.
The first example involved an improper
clearance
which rendered
reactor building fire protection preaction sprinkler
valve 3-FSV-026-0077
The other issue
was
an inoperable battery
charger switch which had not been promptly recognized
as Appendix
R equipment.
On November 23, at about ll:30 a.m.,
a fire alarm actuated
from the
565'levation
in Unit 3 reactor building.
The alarm was caused
by increased
temperatures
of recently applied paint on
some piping near
a smoke detector.
The reactor building fire protection preaction valve did not function to
charge
the sprinkler lines.
The cause
was traced to the valve "magnetic bypass"
valve not receiving
power
because
a knife switch had
been
opened
between
the valve and the power supply.
The knife switch had
been
opened
as part of a clearance
for other fire
protection work. It had not been recognized that this rendered
the preaction
valve inoperable
and thus compensatory
actions
were not initiated.
On November 24,
one of the inspectors
met with fire protection
manager
and
discussed
the incident.
The inspector verified that immediate corrective
actions,
including surveillance testing to verify operability of the preaction
valves
(HPCI and
RB) had
been performed.
The condition had
been quickly
recognized
by fire protection personnel
who responded
to the alarm.
Those
personnel
were knowledgeabl'e
and if required,
could have tripped the preaction
valve.
The work activity being performed
was demolition/removal of abandoned, fire
protection equipment.
The specific task was being performed
under stage
9 of
DCN 20511
(removal of cables).
The requestor of the clearance
(modifications
worker) for the work included
a circuit to be de-energized
which removed
power
4
0
10
from the preaction
bypass
valve.
(Requestor fills out list of circuits on
SSP-134
form).
The inspectors
met with the leader of the incident investigation
and also
reviewed the completed report.
The inspectors
noted that the investigation
was thorough in regard to review of specific process deficiencies.
Information indicates that the requestor
did not use
a schematic
drawing and
instead,
referred only to connection
diagrams.
Thus the requestor.
failed to
recognize that the switch provided power to the preaction valve.
The
inspector
noted that it was difficult to determine all the loads
on the
subject cable
from the referenced
drawings.
The complexity of'he work plans
contributed to the initial error.
The investigation
concluded that clearance
reviewer had not diligently fulfilled'their responsibilities.
From their reviews,
the inspectors
concurred that the deficiencies
involved;
1) personnel
errors during the development of the clearance
and 2) less
than
thorough reviews of the, clearance.
The inspectors
noted
some similarities
between this incident
and
one involving the Wide Range
Gaseous
Effluent
Radiation Monitor in 1994.
The licensee's
review of the current deficiency
also noted the effluent monitor example in review of previous events.
Although the licensee's
review of the incident was thorough,
the inoperable
fire .protection valve was identified only after it failed to respond to an
actuation.
Previous
examples of clearance
problems
have
been identified.
Information indicates that the valve was inoperable for over.
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
The
valve is one example of a violation of the license condition
regarding the-fire protection program.
In late October,
1995, during the performance of the diesel
generator
load
acceptance
testing being performed in preparation for the return of Uni.t 3 to
service,
a test deficiency was generated
when the battery charger
3 power
switch did not properly operate
and provide power to the charger
when placed
in the emergency position.
On December
7,
1995, during the repair of the
battery charger
power switch, personnel
noted that the switch had not been
properly wired and would not operate
in the emergency position.
At this time
it was also recognized that the switch had
an Appendix
R safe
shutd
wn
function to bypass
the load shed logic and provide power to the battery
"
charger in the event of an Appendix
R fire.
PER
BFPER951845
was initiated to
document this condition.
The switch,was properly wired the next day.
Al.though the cause of the wiring error is still being investigated,
the
licensee
has initially concluded that wiring .error may have
been in existence
since the recovery
from the
1975 fire event.
Upon receipt of the
PER, the inspector's
review of the issue indicated that
licensee's
corrective actions
focused
on the wiring error rather than the fact
that appropriate
Appendix
R compensatory
actions
were not taken in response
to
the switch not being functional at least since October
1995.
Section III of
the Appendix
R Shutdown
Program requires, if battery charger
3 is unable to
perform its function, that
a fire watch must
be established if the equipment
is not restored
in seven
days or equivalent
shutdown capability is provided.
The licensee failed to recognize
the Appendix
R function of the switch and did
not take appropriate
compensatory
actions.
The failure to perform these
I~
compensatory
actions is the second
example of a violation of the license
condition regarding the fire protection program.
These deficiencies
are identified as Violation 296/95-64-01,
Fire Protection
Program
Equipment Inoperable Without Compensatory
Actions.
2.7
BIOLOGICAL SHIELD'LOCK REMOVAL FOR REFUELING OUTAGES
The inspector
reviewed the licensee's
actions concerning
the removal of
biological shield. blocks with the reactor at power.
The shield blocks consist
of two sets of blocks stacked
one
on the other
and are located
above the
drywell.
They are accessible
from the refueling floor where they can
be moved
by the overhead
crane in preparation for reactor refueling.
The licensee's
procedure for reactor disassembly
allows removal of the top layer of blocks
while the unit is at
some low power condition progressing
toward the Refuel
mode.
However,
permission
from the refuel floor SRO and Radiological Controls
manager is required if the
mode switch is not in the Refuel or Shutdown
position.
Radiation surveys
are performed during the evolution.
An
engineering
review previously performed
by the licensee
concluded that one
layer of blocks was all that was necessary
for missile protection,
as stated
in the
FSAR, section 5.2.4.6.
2.8
On December
21, during
a routine inspection of the Unit 3 Reactor Building, an
inspector
noted that welding work per
WO 95-10970-00 - replacement
of 8 inch
FP piping was being performed.
Although an extinguisher
was in the
immediate vicinity of the job, the fire watch for the job could not be
immediately located
by the inspector.
The job welder
and foreman pointed out
an individual who they thought was the watch;
however,
the individual, when
questioned
by the inspector
proved not to be the assigned fire watch.
After
asking others,
the inspector
found the assigned fire watch talking to
personnel
in a group located
near the south
end of the east
side
HCU area,
approximately
60 ft from the job area.
The fire watch
had his back turned
toward the hot work area
and was inattentive to the welding being performed.
This issue
was
immediately reported to the
SOS.
BFPER 951902
was initiated
and
a licensee
follow-up was performed
by operations
and maintenance.
Step 5.2.A. I of BFNP Fire Protection
Report
(FPR),
Volume 2, Section I-L,
"Fire Watch Duties
and Responsibilities",
states
that "the fire watch shall
be
on continuous alert for fire, signs of fire and/or
any act that might result
in fire".
Failure of the assigned fire watch to maintain complete control of
his duties
as presented
in the
above
FPR, constituted
a violation of BFNP
procedural
requirements.
However,
the violation will not be subject to
further enforcement
action because
immediate
and effective licensee corrective
actions
were implemented
and the issue. was of minor significance.
This
failure constitutes
a violation of minor significance
and is being treated
as
a non-cited violation, consistent with Section
IV of the
NRC Enforcement
Policy.
This non-cited violation
(NCV) is identified as
NCV 50-296/95-64-04,
One violation and
two non-cited violations were identified.
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3.0
MAINTENANCE (62703,
92902,
61726,
92901,
37551,
92903)
3. 1
MAINTENANCE AND SURVEILLANCE OBSERVATIONS
Maintenance activities were observed
and/or reviewed during the reporting
period to verify that work was performed
by qualified personnel
and that
approved
procedures
in use adequately
described
work that was not within the
skill of the trade.
Activities, procedures,
and work requests
were examined
to verify proper authorization to begin work, provisions for fire hazards,
cleanliness,
exposure control, proper return of equipment to service,
and that
limiting conditions for operation
were met.
Surveillance tests
were reviewed
by the inspectors
to verify procedural
and
performance
adequacy.
Testing
was witnessed
to ensure that approved
procedures
were used,
test
equipment
was calibrated,
prerequisites
were met,
test results
were acceptable,
and system restoration
was completed.
The following maintenance
and surveillance activities were reviewed
and
witnessed
in whole or in part:
WO 95-22154-00
HPCI Turbine Exhaust Drain Pot Level Switches
On November 28,
1995,
the inspector witnessed
maintenance
personnel
perform
troubleshooting activities
on the Unit 3 HPCI turbine exhaust drain pot level
switches.
The annunciator for this condition was frequently alarming in the
control
room indicating
a high level in the drain pot.
The system design is
such that drain valves automatically
open to control level
when the
appropriate
level switch is actuated.
If the level continues to increase
an
annunciator in the main control
room alarms.
The switch controlling the
operation of the drain valves is BFN-3-LS-073-0008B while the switch actuating
the annunciator is BFN-3-LS-073-0008A.
Maintenance
personnel
found that
switch BFN-3-LS-073-0008A was out of calibration low and in fact was set to
actuate prior to the drain valves opening.
The switch was recalibrated
to the
proper setpoint.
BFPER951799
was initiated to determine
why the switch
setpoint
was incorrect.
The inspector
reviewed the work order
and witnessed
the activity.
The procedures
were adhered to, radiological controls were
adequate,
and the personnel
involved were knowledgeable
concerning this
activity.
The inspector
noted
no discrepancies
with this activity.
WO 95-.23065-00
Solenoid Valve Replacement
For Unit 2 Reactor
Zone Inboard
Exhaust
Damper 2-FCO-64-42
On December
1,
1995 the inspector
observed
the replacement
of this solenoid
following its failure to operate
on the previous day.
The inspector
reviewed
the work order
and noted that
a torque verification for the core plugnut had
not been
signed
by
a
gC representative
as required.
The
gC representative
was
at the job site
and
when questioned
stated that
he had
made the verification
but had simply failed to sign the procedure.
He signed the procedure
at that
time.
The inspector
noted
a high degree of attention
being afforded this
activity.
The activity was performed satisfactorily
and the solenoid
successfully
operated
at the conclusion of the work.
The inspector
noted
no
significant deficiencies with this activity.
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WO 95-09025-00
Unit 2 RCIC Turbine Exhaust
Line Snubber Rebuild
On Dec m"or 12 the inspector
observed
the disassembly
an" rebuild of RCIC
BFN-2-SNUB-071-5007.
The inspector noted that the maintenance
personnel
did not use the procedure while performing the work.
The procedure
for this activity was
HPI-O-OOO-SNB002, Hydraulic Shock And Sway Arrestor
Bergen-Patterson
Unit Disassembly
And Reassembly,
and's
a '"Reference
Use"
procedure.
This allows maintenance
to reference
the procedure
as
needed
rather than performing it in a step
by step
manner.
The inspector
noted that
those
personnel
performing the work were extremely knowledgeable
and
experienced
in performing this activity.
The material condition of the area
was well maintained during this activity to avoid contamination of the parts
and snubber internals.
The parts
used
were verified to be in good condition
and appropriate for the job.
The inspector noted that the torque values
used
were obtained
from a,procedure
page attached
to the wall in the room in which
the work was taking place rather than from the page in the procedure that was
included in the work package.
The revision of the page attached to the wall
was revision one while the revision of the procedure
in the .work package
was
revision two.
The inspector
compared
the two pages
and noted that they were
identical.
This was later discussed
with the maintenance
personnel
who stated
that the page attached
to the wall would be removed.
On December
13, while
reviewing the procedure
the inspector noted that precaution
3. 1.2 of this
procedure
stated that if thread lubricant was
used the torque values
were to
be determined
by multiplying the selected
value from the procedure
by 0.90
as
specified in HSI-0-000-PR0017.
Thread lubricant was used during this
activity; however,
the torque values
were not reduced
as described
by the
precaution.
Haintenance
personnel initially agreed that the wrong torque
values
had
been
used
and stated that the snubber
would be loosened
and
retightened
to the
new values.
However,
maintenance later determined that
HSI-0-000-PR0017
stated that if vendor supplied torque values
were available
they should
be used.
Maintenance
stated that the values located in HPI-0-000-
SNB002 were those
recommended
by the vendor
and therefore did not need to be
reduced
as described
in the precaution.
However, discussions
with design
engineering
personnel
indicated that this information may not be completely
accurate.
At the conclusion of the report .period questions still existed
concerning
torque values.
Pending, resolution of this issue, this item will be,
tracked
as Inspector Followup Item 260, 296/95-64-11,
Thread Lubricant Effects
On Torque Values.
TI-137 Core
Power Distribution
During the Unit 3 startup,
O-TI-137, Core
Power Distribution, section 7.5,
Gross
TIP Symmetry Check
and TIP Hookup Verification, the licensee
determined
that TIP channels
A5 and A6,
AB and A9,
and
D6 and
D7 were'swapped.
One of
the purposes for performing this TI was to verify proper hookup of the
individual TIP tubes
and is usually performed following an outage or work
requiring TIP tubing to be removed.
Appendix
4 of the
same procedure
provided
guidance to correct the problem by altering the computer software.
The
licensee initiated
a work order to disconnect
and realign the tubes
when the
drywell can
be accessed.
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14
The l.icensee
has not yet determined
how the tubes
were misaligned
but
preliminarily stated that it appears
there
may have- been
a problem with
'iabelling.
To conclusively determine
the cause will require
a drywell entry.
BFPER951816
was initiated to determine
the root cause
and develop corrective
action.
The .inspectors
reviewed the process of revising the computer software
,to correct the problem
and concluded this method to be satisfactory,.
3.2
IMPROPER ACTIONS ASSOCIATED WITH FREEZE
SEAL't
2:05 p.m.,
on November 27, during control rod scram time testing,
an
unexpected
decrease
in
CRD system pressure
was noted.
The pressure
decrease
occurred
when
a freeze
seal
plug was thawed before the associated
clearance
boundaries
had been properly restored.
A freeze seal,had
been installed to
perform maintenance
on
a
CRD hydraulic control unit charging line isolation
valve ("588" valve).
The clearance
established
for the work required the
accumulator drain valve (downstream of the freeze plug) to be open.
When the
plug was thawed,
CRD pressure
was ported through the open valve and
a small
spill occurred.
Haintenance
workers shut the valve and stopped
the leakage.
The incident was clearly noted in the operating logs.
The
NRC shift inspector
observed
the incident in the control
room.
On the morning of November 28,
one
of the inspectors
questioned
operators
and the acting operations
superintendent
about
a
PER on the issue.
At that time there
was not
a
PER.
BFPER 951793
was initiated on November
28 to address
the issue.
I
The inspectors
interviewed several
maintenance
personnel
involved in the work
and reviewed'he
work package.
Inspectors
concluded that the incident was
caused
by poor communications
between
operations/maintenance
and
maintenance
not,rigidly following the "freeze seal" procedure
step-by-step:
Maintenance
workers called the
CR and, stated that they were "getting off
the clearance"
and thawing the plug.
Maintenance did not ask for
permission to thaw the plug which was at the time acting
as
a boundary.
NRC inspectors
noted that Step 7. 15 of MSI-0-000-PLGOOI: Installation of
Freeze
Seals,
states:
"Close drain line (if available
and with
Operations
permission)
of secti'on of pipe frozen".
The next step is to
close the refrigerant supply valve.
The drain valve was .tagged
open
on
the clearance
so the maintenance
workers could not operate
the valve.
The drain valve was not shut before the plug was thawed.
The problem with the "588" valve was that it had failed most likely due to
inter-granular stress
corrosion cracking. of the valve wedge ears
as described
in
This causes
the wedges to separate
from the stem.
The
corrective actions
are to replace
the solid wedge with flexible wedges of
different material.
There are
seven
manual isolation valves
on each
(normally open,
shut only for .maintenance)
which are susceptible
to this.
The
SIL focuses
on three of the valves which if fail could impair a scram
inlet/outlet
and
SDV lines).
The,inspectors
had previously verified that the
licensee
had refurbished
the three valves
on each
HCU which are highlighted in
the SIL prior to,Unit 3 restart.
The remaining susceptible
valves
are being
replaced
as failures are identified.
The failure of the charging isolation
valves
does not prevent the ability to scram the rod.
lh
15
The inspectors
regarded
the work practice
issues
that led to the freeze
seal
failure as deficiencies.
Performance of the procedural
steps
in order or
better coordination witn operations
would have prevented
the problem.
The
potential safety significance of the freeze
seal failure was that if personnel
did not isolate the flowpath, the ability to move rods with the normal drive
system would be lost due to loss of CRD charging pressure.
The'bility to
scram rods
(even the
HCU being worked) would not be lost since reactor
pressure
would still drive the rod in on
a scram.
PER 951793
was reviewed
by the
HRC on November 29,
1995.
A human performance
evaluation of the incident was directed.
At the close of this inspection
report period, licensee
management
was evaluating
methods of stricter controls
involving freeze seals.
This l,icensee-identified
and corrected violation is being treated
as
a Non-
'Cited Violation, consistent with Section VII.B.l. of the
NRC Enforcement
Pol.icy.
This issue is addressed
as
NCV 296/95-64-02,
Deficiencies
Involvi'ng
Control of Freeze
Seal.
3.3
E(UIPHENT RETURNED TO SERVICE WITHOUT POST
MAINTENANCE TESTING COMPLETED
On December
4,
1995, during control rod exercise testing, control rod 42-39
moved in three notches
(position
48 to position 42) rather than
a single notch
as expected.
Operations
promptly notified reactor engineering
and Technical
Support.
One of the
NRC inspectors
observed
adjustment of the rod speed
which
was performed in accordance
with OI-85.
The inspector noted'hat
the locknut
on the adjustment
device
was found snug.
PER 951815
was initiated to address
the cause of the incorrect
speed.
Subsequently, it was determined that the
insert directional control valve had
been replaced
on
HCU 42-39
on November 8.
Functional testing (verification/adjustment of insert/withdraw times)
was not
performed.
WO 95-20876-00
was used to replace
the directional control valve and it
listed,
as required
PMT, functional testing
.in accordance
with HCI-0-085-
HCU001
and OI-85.
However, the testing
was not performed.
Maintenance
personnel
signed
a step
on November
9 in HCI-0-085-HCUOOI which indicated that
Operations
(a Shift Support Supervisor
instead of SOS/ASOS)
had'een
informed
that the applicable functional test should
be performed.
The
WO was signed
as
PHT complete .at 5:30
pm on November
18 by another Shi'ft Support Supervisor.
There
was not
a signature
from Operations
as the responsible
section
indicating that functional, testing
was completed.
The rod had
been inserted
on the planned
on November 9, which
demonstrated
that the rod could perform its safety function.
At the
same time that the rod 42-39 issue
was being investigated,
maintenance
management
al'so
was reviewing other potential
problems with Work Order
processing
and
PHT status.
On December
6,
1995,
PER 951842
was initiated to
address
four mechanical'maintenance
work orders which had
been incorrectly
classified prior to all required
PHT being completed.
This practice
was not
in accordance
with SSP.-6.2,
Maintenance
Management
System.
The work orders
involved maintenance
activities, on several
HPCI and
RCIC valves.
Review of
16
other work orders indicated that the deficient practices
were limited to these
Four examples.
Haintenance
and Operations
management
issued
a memorandum
on December
7, which
clearly stated
expectations
regarding
WO processing
and controls
on
PHT
status.
Operations
and Haintenance
personnel
were briefed
on the guidance.
Emphasis
was placed
on Operations
personnel
verifying that all
PHT was
completed prior to
a system being .declared
The
PER contained
evaluations
which concluded that although not all the required
PHT was
completed,
equivalent testing which had
been
performed provided assurance
that
the important valves could meet their safety functions
and the systems
were
The inspector
reviewed the evaluations
and concluded that
operability of the equipment
was adequately
supported.
The inspectors
concluded that appropriate
actions
were taken in response
to
the identified deficiencies
and that management
and operations
personnel
had
been proactive
on the matter.
The safety significance of the specific issues
was limited, however, deficiencies
in such
a fundamental
process
(ensuring
that
PHT is completed prior to return to service)
are of concern.
This
licensee-identified
and corrected violation is being treated
as
a Non-Cited
Violation, consistent with Section VII.B.1 of the
NRC Enforcement
Poli'cy.
This issue is .addressed
as
NCV 296/95-64-03,
Equipment Returned to Service
Without Proper
PHT Completion.
3.4
REVIEW OF 4160
VAC BREAKERS HAINTENANCE ACTIVITIES
On June
15,
1995,
a loss of the
161 Athens line occurred
(IR 95-38;
Paragraph
5.c.) resulting in the loss of the IA & 2A Start Busses.
During recovery
operations,
the
3A CRD pump failed to start
because
the
pump breaker's
"latch
monitoring switch" open circuited.
This in turn, would not allow the charging
motor to charge.
The problem was attributed to
a closing coil plunger being
lodged in place
due .to corrosion
on the plunger shaft.
As
a result of this
problem, periodically, during the last three inspection periods,
an inspector
reviewed past work orders
(WOs) of maintenance
performed
on various Unit 3
4160
VAC Safety-Related
breakers
and observed
the following:
Since
1992, periodic maintenance
(PM) has
been
performed
on all safety-
related
pump breakers
i'.e.,
CS pumps,
RHR p'umps,
SW pumps, etc...
Breakers
are placed
on
a 5-year
PH program and,the
program includes
slide point lubrication
and replacement
of coils if any sticking or
binding,is noted.
The inspector
found that since
1989, only four (4) similar sticking or
binding "latch monitoring switch" problems
have occurred in this type of
breaker
the
"GE AHH 4.16-250 Horizontal" breaker.
Host "sticking"
occurred
due to "dirty" rather than "corroded" plunger shafts.
Since
1990,
PHs
have also
been
performed
on associated
4160
VAC safety-
related
HOV actuator breakers.
On
a continuing 5-year cycle breaker
PHs
are currently being performed'.
3a
Ik
17
All associated
Emergency Diesel Generator/Essential
Buss tie-breakers
have
undergone
comparable
breaker
PHs
and none of the
EDG breakers
have
experienced'imilar
"latch monitoring switch" problems.
After the above review, the inspector concluded that the current licensee
4160
VAC breaker
PH program for safety-related
equipment
was satisfactory.
3.5
OPEN
ITEHS REVIEW
3.5. 1 (Closed)
IFI 50-260/95-56-02,
Use of Nickel-Based
Thread Lubricant on
in TVA Class
"B" Fluid Systems.
In IR 50-260/95-56,
Paragraph
3.2,
an inspector
noted that in August,
1995,
BFNP gA personnel
observed
being coated with a nickel-
based lubricant; i.e. Nuclear-Grade
"Never-Seez".
The inspector also noted
that
such action could potentially allow this thread lubricant to be in direct
contact with the unit's condensate
system since leeching of this lubricant
into the system
was probable.
During the reporting period,
the inspector
contacted
the thread lubricant vendor
and received confirmation,
both verbally
and in the .form of a vendor specification report, that the lubricant was safe
for such application
and any leeching of this lubricant into the condensate
system
was minimal.
Licensee
personnel
presented
event specifics
and adequate
proposed corrective actions in Plant Problem Evaluation Report
(PER)
BFPER951122.
Based
upon the above,
the inspector's
specific review of vendor
material
and the review of licensee corrective action adequacy,
IFI 50-260/95-
56-02,
Use of Nickel-Based
Thread Lubricant on Gaskets
in TVA Class
"B" Fluid
Systems,
is closed.
Two non-cited violations
and
one inspector followup item were identified.
4. 0
ENGINEERING
4. 1
Secondary
Containment Ventilation Damper Failures
During this report period, the licensee
experienced
several
secondary
containment isolation damper failures
due to sticking solenoid valves.
Prior
to this report period, the licensee
experienced
similar failures in November,
1992 when two Unit 3 dampers failed to close.
The problem was believed to
have
been
caused
by excessive
wear
on the upper disc stem/seat
area
due to
possible chattering
caused
by low power supply voltage or foreign particle
intrusion.
The licensee
examined
the air supply quality and the power
supplies to the solenoids
but determined that both were acceptable.
At that
time other plants in the industry experiencing
solenoid failures postulated
that sticking was at the core-plugnut interface
(CPI)
and was caused
by
lubricant used
by the vendor during assembly.
Based
on this information the
licensee
replaced all the secondary
containment
damper solenoids with
solenoids
containing no,lubricant.
On October 4,
1995,
two secondary
containment isolation dampers,
Unit 2
reactor
zone dampers
13
and
14, failed to isolate
as required.
On October
5
a
third damper,
Unit
1 reactor
zone
14, failed to isolate.
The cause
was
determined
to be due to
a sticking solenoid valve
as previously discussed
in
<5
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IR 95-56.
In these
cases
when the solenoids
were lightly tapped the damper
repositioned
appropriately.
It was concluded that the solenoid core
was
sticking in the coil.
Following these failures, the licensee
took one of the
solenoids to the vendor for disassembly
and examination.
A black substance
was discovered
on the
CPI which was thought to be the cause of the sticking.
The black substance
was sent to the
TVA central
lab for analysis;
however, it
was determined that the sample size
was too small to make
a positive
identification of the substance.
The remaining two valves were also sent to
the vendor for testing.
The vendor energized
one of the valves for twenty-
four hours at high voltage.
At the end of the period the valve was
deenergized
and the core stuck.
When the solenoid
was lightly tapped
the core
came free.
As follow up, the internal'alve
components
were disconnected
from
the core
and again it was energized.
This allowed the core to be free to move
only by magnetic force from the energized coil or by gravity.
After being
.
energized for one week the valve was deenergized
and again the core stuck at
the CPI.
The inspection also identified that lubricant
had
been
used during
assembly
although the valves were ordered without it.
On November
20 Unit 2
reactor
zone damper
43 failed to close,
however,
the failure was attributed to
faulty limit switches.
On December
11 Unit
1 refuel
zone damper
5 took
approximately
one minute to close instead of the normal five to ten seconds.
No problems
were found with the damper nor was the solenoid confirmed to be
sticking.
The licensee
did not initially consider this
a damper failure.
On
December
13, Unit 2 reactor
zone
42 failed to close.
The cause
was
determined to be due to
a sticking solenoid.
Following this failure, the
resident
inspectors
held discussions
with the licensee. to determine the course
of action being taken
due to the increased failure rate,
the possibility of
common cause failure,
and the operability of the remaining isolation dampers.
Although the licensee
was actively pursuing
a long term solution to this
problem at that time, the short term concern of ensuring operability was not
aggressively
being pursued.
The licensee's
operability evaluation relied
on
weekly cycling of the dampers
which information indicated
was not adequate
to
ensure operability.
The licensee
stated that the failures which had occurred
were from solenoids
whose service life was between thirteen
and seventeen
months.
They indicated that all the solenoids with service lives greater
than
twelve months would be replaced.
By December
17 all the Unit 2 and Unit 3
reactor
zone solenoids
had been replaced.
The licensee
intends to replace
one
solenoid in each pair of the remaining ventilation paths
as replacements
become available
from the vendor.
On December
19, the inspectors
again
met with the licensee to discuss
the
solenoid failures.
The licensee
presented
their. conclusions
concerning
the
failures
and actions
taken or being taken
as
a result.
Results of their
investigation indicate that the solenoid is sticking at the CPI due to the
residue
found at that location.
The vendor
and the licensee
have yet to
conclusively determine the source of the residue.
The licensee
stated that
the
AC coil construction
and high temperatures
associated
with this .model
solenoid contributed to this adhesion
and subsequent
core sticking.
Data also
indicated that the sticking problem does not develop until after approximately
twelve months of operations
The licensee's
short term resolutions
include
replacement
of the existing solenoids
as previously discussed.
Longer term
resolution includes replacing the solenoids with solenoids of a different
design.
The licensee
stated that the
new design
operates
at
a much lower
.
4
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19:
wattage
and
CPI temperature
making it less susceptible
to developing core
sticking conditions.
At the conclusion of this report period, the inspector reviewed
NRC
Information Notice 95-53 which discusses
failures of solenoids
due to sticking
at the CPI.
This notice discusses
the possibil,ity of the sticking being due
to the combination of 1'ubricant
used
by the vendor
and thread sealant
used
by
the licensee.
The inspector will continue to monitor the progress, of this
issue
and follow up with the licensee
concerning. this Information Notice.
This issue is identified as Inspector Followup Item 260,296/95-64-10,
Secondary
Containment Ventilation Damper Failures.
4.2
NARROW RANGE TORUS
WATER LEVEL NOT MAINTAINED WITHIN TS LIMITS
On November
15,
1995, while performing
a review of the torus water level
limits for the
BFN Improved Standard
Technical Specifications,
TVA personnel
determined that
a +2 inch offset had
been introduced into the setpoint
calculation for the torus narrow range level instrumentation.
The offset had
been placed into the calculation in 1989 due to the close proximity of the
lower level analytical limit to the technical
specification value.
The
introduction of this offset caused
the level instrumentation
to display
a
value
2 inches less
than actual water level
and ultimately resulted
in Unit 2
violating the upper technical specification limit of -1 inch.
Browns Ferry
technical
specifications
require torus water level to be maintained within a
band o'f -1 inches to -6.25 inches
(instrument "0" corresponds
to elevation
536
feet
8 inches or 15 feet
5 inches of water in the torus).
The licensee
performed
a limited review of past water levels of the Unit 2 torus
and
determined that during the period between
October 8-14,
1995, the water level
within the torus exceeded
the technical specification limit by approximately
one inch.
No further review of past Unit 2 records
was conducted
as
engineering
analysis
indicated that
no detrimental effects
on long term torus
integrity would occur if indicated torus level did not exceed
Technical
Specification value.
This matter
was reported to the
NRC in accordance
with
10 CFR 50.73(a)(2)(i)(B) in an
LER dated
December
14,
1995.
The licensee's
immediate corrective actions for this matter were to place
a
more restrictive administrative
band
on the torus water of -3 inches to -5.5
inches to negate
the
2 inch offset for both Units
2 and
3 (at the time of
discovery, Unit 2 was operating at
100 percent
power and Unit 3 was in cold
shutdown preparing for restart following the
10 year outage).
Prior to the
startup of Unit 3, the torus narrow range instrumentation
was recalibrated
to
remove the
2 inch offset.
The offset was subsequently
removed
from the Unit 2
instrumentation
and the licensee
returned to their normal administrative
band
of -2 inches to -5.5 inches.
During 'the inspector's
review,
a number of questions
arose related to this
matter.
The first question deals with the instrument
accuracy of the torus
water level narrow range instrumentation.
The licensee's
setpoint
documentation for this instrumentation
states
that the accuracy
range is +/-
1.75 inches.
The inspector.
questioned,
when applying this accuracy
range to
the licensee's
administrative level limits of -2 inches to -5.5 inches,
how it
can
be assured
that the
TS limits are not exceeded.
Discussions
held with NRR
0
20
personnel
indicated that the licensee's
practice of utilizing the analytical
limit to bound instrument error is acceptable
for TS indication
instrumentation.
A second
question related to thi's matter
.'".mls with the
potential, that the licensee
exceeded their design analytical limit of +1 inch
when the
2 inch offset was present
in the setpoint.
The inspectors
brought
this matter to the attention of the licensee's
engineering
department
who in
turn contacted
the .NSSS vendor
(General 'Electric).
GE informed the licensee
that additional
margin existed
above. the
+1 inch upper analytical limit and
the appropriate
supporting documentation
would be provided.
As mentioned previously, the
2 inch offset resulted
in the licensee
exceeding
the Unit.2 torus
TS limit of -1 inch.
A'fter a detailed review of this matter,
the inspectors
concluded that this issue constitutes
a violation of minor
significance
and is being treated
as
a 'Non-Cited Violation, consistent with
Section
IV of the
This issue is identified as
260/95-64-09,
Violation of Torus Water Level TS.
4.3
REACTOR RECIRCULATION PUMP SEAL PURGE
EFFECTS
ON THE NUCLEAR HEAT
BALANCE CALCULATION
While investigating industry events
the licensee
determined that
a small
amount of control rod drive flow used for reactor recirculation
pump seal
purge
was not accounted for in the calculations of the nuclear heat balance.
Although not considered
to significantly affect the results of the core
thermal
power calculation,
BFPER951879
was initiated to document the concern
and ensure
the calculation
was reperformed.
The Operations
superintendent
issued'n
Operations
Daily Instruction directing that power be limited to 3292
Mwt rather than rated
power of 3293
Mwt until this was completed.
The amount
of flow into the reactor which was unaccounted
for was approximately 2-3 gpm.
The licensee
determined that the error in the reactor thermal
power caused
by
this flow was approximately 0. 1 to 0.5 Mwt.
Engineering
concluded that
conservatism
and component
inaccuracies
already factored into the calculation
would compensate
for this error and therefore this additional flow did not
result in reactor
power exceeding
the licensed limit of 3293 Mwt.
After
engineering
determined that the error was negligible the daily instruction
limiting power was rescinded.
The licensee will continue to follow this issue
both with the industry groups
and the vendor.
One Inspector
Followup Item and
one Non-cited Violation were identified.
5.0
PLANT SUPPORT
The inspectors
toured the protected
area
and noted that the perimeter
fence
was intact
and not compromised
by erosion
or, disrepair.
The fence fabric was
verified to be intact and secured.
The inspectors
observed
personnel
and
packages
entering the protected
area
and verifi'ed they were searched
either by
special
purpose detectors
or physical
patdown.
Improvement
was specifically
noted regarding
the access
control problems discussed
in IR 95-60.
No violations or deviations
were identified.
0
hi
0
~
~
21
6.0
REVIEW OF
NRC ORAT INSPECTION FINDINGS
The ir~; ctors reviewed the findings described
th
Unit 3
ORAT Inspection
Report (95-201).
Several
deficiencies
and open items were identified.
6. 1
DEFICIENCY 50-296/95-201-05,
PROCEDURES
AND TRAINING WERE
NOT ADEQUATE
TO
ENSURE FIRE DANPERS
WOULD CLOSE
IN A FIRE AREA
The
ORAT identified that the procedural link which guided operators
to the
procedures
to secure/isolate
ventilation systems
in case of a fire was weak.
Paragraph
6. 14 of Inspection
Report 95-60 describes
a detailed resident
inspector review of the licensee's
immediate actions in response
to the
finding.
The inspector verified that the licensee
has modified procedures,
enhanced
labeling,
and trained operators.
Additionally, the
summary section
of the
ORAT report stated that the licensee
took prompt and adequate
corrective actions.
The
ORAT report specifically described
21
as the deficient procedure.
21 is only one, of the procedures
which should
be referenced
in event of a
fire.
Volume
2 of the Fire Protection
Report contains
the detailed Fire "Pre-
Plans" which will be carried to the scene
and
used
by the fire brigade leader.
These pre-plans
contain guidance
in the "special precautions"
section stating
"If zone isolation is required to stop the propagation of smoke, notify the
SOS".
Both the
new procedure
(AOI-26-1) and the old procedure
(AOI-30-1)
state that actions to secure ventilation are to be taken
based
on
recommendation
of the fire brigade leader.
In discussions
with the inspector,
the brigade leaders
indicated that this is practiced
in drills by
recommendations
to the incident
commander
(ASOS).
The inspectors
concluded
that the operators
would refer to the AOI. as necessary if specifical.ly
directed to secure ventilation.
Securing ventilation is
a relatively simple
activity that control
room operators
would most likely be able to perform
without specific procedural
guidance
once directed to do so.
The apparent
discrepancy
is that the Fire Hazards Analysis states
that
procedures
are in place to require the control
room to initiate
HVAC zone
isolation when
a fire is verified in an area.
Additional review of this issue
was conducted.
.In addition to the Fire Protection
Report statements,
the
inspector noted other documents
which indicate that procedures explicitly
direct shutting off ventilation in the event of a fire.
The licensee's
internal
response
to IN 89-52 indicated that AOI-30-1 had
been
issued to
address
the concern
in the IN.
A 1985
INPO document
involved similar fire
damper issues
and was also
addressed
by AOI-30-1.
The inspector also noted
that
CATO 23001-BFN-01
(employee
concern)
addressed
this
same issue.
The
original
CATD corrective action plan required verification that dampers
would
shut against air flow but was later revised
such that it also relied upon AOI-
30-1
as procedural
guidance to isolate ventilation.
The inspector
noted
documentation
indicated that many of the dampers
have
been upgraded/replaced
with dampers that are designed
to shut against air flow (meet
UL 555), but
that the dampers
are not tested
against air flow.
55.
0
22
The inspector
noted that the revised procedure,
like the original AOI, relies
on fire brigade'ecommendations
for ventilation operations.
The inspector
concluded that the pro=edures
do not require implementation of the actions
as
specifically stated
in the Fire Protection
Report statement.
Additional
discussions
were held with the licensee
and the
ORAT inspector
who identified
the issue.
The licensee
indicated that it is not desirable
to always
secure/isolate
ventilation in the event of a fire.
The licensee
stated that
a
50.59 evaluation
would be performed
and the statements
in the Fire Protection
Report will be revised.
The resident
inspectors
requested
that the evaluation
specifically address
the issue of fire dampers
shutting with fans operating.
This issue will'e addressed's
Unresolved
Item 260,296/95-64-08,
Fire Damper
Procedural
Controls,
pending additional
NRC review of the licensee's
actions.
6.2
DEFICIENCY 50-296/95-201-03,
FAILURE TO RECORD
REQUIRED INFORMATION IN
THE CONTROL
ROOM
LOG AS REQUIRED
BY PROCEDURE
The
ORAT identified examples
in which the operators failed to log information
specifically required
by procedures
to be logged.
The resident
inspectors
have noted other isolated
instances
in which log entries should
have
been
more
complete.
Technical Specification 6.8. l.l.a requires that written procedures
recommended
in Appendix A of Regulatory
Guide 1.33,
Revision 2, February
1978,
be
established,
implemented,
and maintained.
Section
1.h of Appendix A in
recommends
procedures
for log entries.
SSP-12. 1,
"Conduct of
Operations,"
Section 3. 11.3.B states
in part:
"The following information
shall
be recorded
in at least
one station log..."
The specified information
includes
abnormal
plant configurations,
status
changes
to safety-related
and
major plant equipment including the instruction
and section
used,
occurrence
of any reportable
events, initiation and completion of surveillance
instructions (SIs), entering
and exiting Technical Specification
(TS) action
statements,
testing activities including the procedure
number
and problems,
and events.
The listed examples
were clearly examples of issues that the
licensee's
procedures
require to be logged.
It should
be noted that the
operators
sometimes
do not record in the control
room logs all aspects
of
incidents which are recorded
in other documents
such
as
Problem Evaluation
Reports, test deficiencies,
or personnel
statements.
After detailed
review of the examples,
the inspectors
concluded that this
failure to follow procedures
constitutes
a violation of minor significance
and
is being treated
as
a Non-Cited Violation, consistent with Section
IV of the
This issue is identified as
NCV 296/95-64-07,
Failure
to Record Information in Unit Logs.
6.3
DEFICIENCY 50-296/95-201-01,
SOME OPERATIONS
PROCEDURES
MERE NOT
ADEQUATE.
The
ORAT identified three
examples
in which it appeared
that procedures
were
not appropriate
to the circumstances
in which they were used.
<i
23
Example A:
On October
13,
1995,
Work Order 95-18774-00,
"RPS Troubleshooting
Proposed
Plan of Action" failed to. include provisions to prevent the closure of 3-FCV-
74-67,
RHR LPCI inboard isolation valve,
as
was intended.
Consequently,
residual
heat removal'hutdown cooling was interrupted during the performance
of the work order.
An NCV was issued
in Inspection
Report 95-60
on this incident.
'The licensee
failed to treat the troubleshooting
as
a "high risk activity" as required
by
their procedures.
This failure to fol.low procedure
resulted
in a significant
reduction in the layers of defense
intended to prevent
such
an occurrence.
Personnel
errors during development and'eview of the troubleshooting
work
order caused
the event.
After detailed review of the issue,
the resident
inspectors
concluded that the deficiency was related to the,licensee's
failure
to fol-low established
procedures
in the formulation of:the plan., As stated
in
the
ORAT report,
the safety significance
was limited due to plant conditions
and the issue
was conservatively reported to the
NRC operations
center.
Example
B:
Operating Instruction, 3-0I-73,
"High 'Pressure
Coolant Injection System,"
Revision 0, Illustration 1, failed to provide adequate
instructions to perform
wire lifts on .Panel
3-9-39.
On October
11,
1995, operations
personnel lifted
the wrong wire.
This action resulted
in disabling of the manual trip function
for the high pressure
coolant, injection (HPCI) system
steam, driven turbine.
This deficiency occurred during testing of the
HPCI system
on auxiliary steam
prior to HPCI being declared
The evolution was being performed
primarily to flush the
HPCI discharge .lines.
One of the resident
inspectors
was observing this testing at the HPCI,turbine .when the deficiency was
identified.
The procedure
included
a confirmation that the turbine could be
tripped.
Immediately after the problem was identified, the testing
was
halted,
and the issue
was addressed.
The inspectors
reviewed
PER 951473.
The problem was that the panel
side wire
was lifted .instead
of. the field side wire.
'OI 73 for both 'Units
2 and
3 have
been revised to more clearl'y reflect the correct "field side" wires to be
lifted.
The inspector
reviewed the procedure
and concluded that it does
provide more clear directions
on which wire to lift.
Operators
have
been
informed on the problems described
in the
PER.
The
PER remains
open pending
additional. review of procedures
for similar.,problems.
The wire lift being performed
was to permit testing of HPCI on low pressure
steam.
'HPCI would be inoperable during such testing.
The OI and the TI both
included specific requirements
to confirm that the
HPCI trip function was
operable prior to running HPCI.
The OI has
been utilized successfully
(Unit
2) in the past to lift the leads for HPCI operations.
The enhancements
to the
procedure
provide better guidance to the operators.
The inspectors
concluded
that this issue
involved
a personnel
error and that the licensee correctly
implemented
procedures
for testing deficiencies
and identification/resolution
$5
l
4
of the problem.
The inspectors
did not identify a violation of regulatory
requirements.
Example
C:
Technical
Instruction, 3-TI-343,
"HPCI Injection Flush," Revision 0, Step
7. 13, states,
"CLOSE HPCI
PUMP CST TEST VALVE, 3-FCV-73-35".
During a test,
the control
room operator throttled the valve to maintain the desired
flow rate to the reactor pressure
vessel
to prevent reactor cavity overflow.
This example also involved HPCI testing prior to the system being declared
As stated
in the
ORAT report, the procedural error had
no safety
significance,
the actual
actions
performed were correct,
and the procedural
problems
were documented
immediately after the test
was run.
After additional
review, the resident
inspectors
concluded that the regulatory concern
was that
administrative
requirements
for revision of procedures
were not followed.
This example will be grouped with the deficiency involving maintenance
procedures
not being followed since that issue involved similar failure to
adhere to procedure
requirements
on procedure
adherence/revisions
(paragraph
6.4).
Available information indicates that in both of these
examples,
the licensee identified the problem and pursued corrective action
independent
of NRC involvement.
This licensee-identified
and corrected
violation is being treated
as
a. Non-Cited Violation, consistent with Section
VII.B.I of the
The two examples will 'be addressed
as
NCV 296/95-64-06,
Failure to Follow Requirements
for Procedure
Changes.
6.4
DEFICIENCY 50-296/95-201-04,
MAINTENANCE PROCEDURES
WERE NOT FOLLOWED.
The
ORAT report clearly indicates that the issue
involved failure to follow
administrative
procedures
for revision of procedures.
As stated
in the
report,
the work was performed satisfactorily
and the procedure
was
subsequently
revised to reflect the
new acceptance
criteria prior to the
inspector's
observation that the procedure
was not followed.
The regulatory
concern is that the procedural
requirements
(follow procedure
or revise it)
were not met.
This example involves
a regulatory concern similar to,that
discussed
above
and will be addressed
as
an example of NCV 296/95-64-06.
6.5
OBSERVATION 50-296/95-201-02,
OPERATIONS
PERSONNEL
FAILED TO
FOLLOW GOOD
OPERATIONS
AND 'RADIOLOGICAL CONTROL PRACTICES
The examples listed in the
ORAT report address
two areas of Operations
performance;
good operations
practices,
and good radiological control
practices.
The inspectors
conducted
additional
inspections
to determine if
the examples
represented
declining or marginal
performance.
For over
10 days
in late November,
NRC inspectors
performed continuous
observations
of Unit 3
control
room activities.
While a few examples of inattention to detail
were
noted
by the inspectors,
there were
no observations
of inappropriate
performance
regarding annunciators.
No additional observations
of weak
radiological
controls practices
by Operations
personnel
have
been
noted
despite
the extensive
inspection activities conducted for the Unit 3 restart.
The resident
inspectors will continue to monitor performance
in these
areas.
<P
~
~
25
6.6
OBSERVATION 50-296/95-201-06,
ENGINEERING TO COMPLETE THE REACTOR VESSEL
HEAD VENT LINE PIPE
WHIP ANALYSIS
One of the resi'dent
inspectors
met with engineering
management
and reviewed
documentation
associated
with this issue.
In response
to the questions
raised
by the
ORAT inspector,
the licensee
provided information which indicated that
the l.ine does not represent
a potential
pipe whip situation in which the
piping could impact the containment spherical
shell
head.
Information was
provided which indicated that the original
GE pipe rupture analysis for BFN
concluded that the
damage potential
from pipe breaks of the size piping
involved does not have
a significant effect.
Additionally, documentation
was
provided which demonstrated
that the jet load effects
on the shell
head
closure
had
been considered
in the shell analysis.
The, resolution
and
evaluation of the
ORAT inspector's
questions
was documented
as attachment VII
of Calculation
CD-93999-950476
Pipe Rupture Evaluation for the
BFNP Unit 3
Restart.
The resident
inspector concluded that the issue
had
been
sufficiently resolved.
One unresolved
item and two non-cited violations were identified.
7.0
EXIT (30703)
The inspection
scope
and findings were summarized
on December
30,
1995,
by L.
Wert with those
persons
indicated
by an asterisk in,paragraph
1.
The
inspectors
described
the areas
inspected
and discussed
in detail the
o
inspection results.
A listing of inspection findings is provided.
Proprietary information is not contained
in this report.
Dissenting
comments
were not received
from the licensee.
Item Number
Status
Descri tion and Reference
VIO 50-296/95-64-01
NCV '50-296/95-64-02
NCV 50-296/95-64-03
NCV 50-296/95-64-04
NCV 50-296/95-64-05
Open
Open
8 Closed
Open
& Closed
Open
& Closed
Open
&
Closed'ire
Protection
Program
Equipment Inoperable Without
Compensatory
Actions
(paragraph
2.6)
Deficiencies Involving Control
of Freeze
Seal
(paragraph
3.2)
Equipment Returned to Service
Without Proper
PHT Completion
(paragraph
3.3)
(paragraph
2.8)
HPCI Flow Controller Switch
Not in AUTO (paragraph '2.3)
Nl
0
NCV 50-296/95-64-06
NCV 50-296/95-64-07
URI 50-260,
296/95-64-08
NCV 50-260/95-64-09
IFI 50-260,
296/95-64-10
IFI 50-260,
296/95-64-11
IFI. 50-260/95-56-02
8.0
ACRONYHS
26
Open
8 Closed
Open
5 Closed
Open
Open
5 Closed
Open
Open
Closed
Failure to Follow Requirements
for Procedure
Changes
(paragraphs
6.3 and 6.4)
Failure to Record Information
in 'Unit Logs (paragraph
6.2)
Fire Damper Procedural
Controls
(paragraph
6. 1)
Violation of Torus Water Level
TS (paragraph
4.2)
Secondary
Containment
Ventilation Damper Failures
(paragraph
4. 1)
Thread Lubricant Effects
On
Torque Values,
(paragraph
3. 1)
Use of Nickel-Based
Thread
Lubricant on Gaskets
in TVA
Class
"B" Fluid,Systems,
(paragraph 3.5.1)
AOI
ASOS
BFPER
'CATO
CFR
CR
DCN
EGR
EMS
gpm
Abnormal Operating Instruction
Assistant Shift Operations
Supervisor
Browns Ferry Nuclear Plant
Browns Ferry Problem Evaluation 'Report
Balance of
Plant'orrectiveAction Tracking Document
Code of Federal
Regulations
Core-Plugnut Interface
Control
Room
Control
Rod Drive
Condensate
Storage
Tank
Design
Change Notice
Emergency Diesel
Generator
Electro-Governor
R
Electric Hydraulic Control
Equipment
Hanagement
System
Emergency
Plan Implementing Procedures
Fire Protection
Fire Protection
Report
Final Safety Analysis Report
General
Electric
gallons per minute
Hydraulic Control Unit
High Pressure
Coolant Injection
I
ik
0
27
IFI
IN
IR
LPRH
HRC
Hwt
NRC
PER
PH
PHT
gA
gC
RC IC.
.RPS
SOS
TI
TS
UL
UNID
VAC
'WO
rations
Team
Inspector Followup Item
Information Notice
Institute for Nuclear
Power
Ope
Inspection
Report
Low Pressure
Coolant Injection
Local
Power
Range Monitor
Motor Operated
Valve
Management
Review Committee
Megawatts-Thermal
Non-cited Violation
Nuclear Regulatory
Commission
Nuclear
Reactor Regulation
Operating Instruction
Operational
Readiness
Assessment
Problem Evaluation Report
Preventive
Maintenance
Post Modification Testing
guality Assurance
guality Control
Reactor
Core Isolation Cooling
Reactor 'Building
Regulatory
Guide
Residual, Heat
Removal
Reactor Protection
System
Scram Discharge
Volume
Safety Evaluation
Surveillance Instruction
Service Information Letter
Safety Parameter
Display, System
Shift Operation Supervisor
Senior Reactor Operator
Site Standard
Practices
Safety Rel:ief Valve
Service
Water
Technical
Instruct'ion
Traversing
Incore Probe
Technical Specifications
Valley Authority
Underwriters Laboratory
Unique Equipment Identification
Unresolved
Item
Volts Alternating Current
Violation
Work Order
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