ML18038B639
| ML18038B639 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 02/29/1996 |
| From: | Lesser M, Wert L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18038B637 | List: |
| References | |
| 50-259-96-01, 50-259-96-1, 50-260-96-01, 50-260-96-1, 50-296-96-01, 50-296-96-1, NUDOCS 9603140308 | |
| Download: ML18038B639 (58) | |
See also: IR 05000259/1996001
Text
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UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W., SUITE 2900
ATLANTA,GEORGIA 303234199
Report
Nos ~:
50-259/96-01,
50-260/96-01,
and 50-296/96-01
Licensee:
Valley Authority
6A 38A Lookout Place
1101 Market 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:
December
31,
1995
February
3,
1996
Inspector:
nar
.
ert,
,
nidor Ress
ent
nspector
J.
Hunday,
Resident
Inspector
R. Husser,
Resident
Inspector
H. Morgan, Resident
Inspector
J. Coley, Special
Inspection
Branch,
DRS,
(paragraph
3.3)
R. Gibbs,
Maintenance
Branch,
DRS,
(paragraph
3.4)
G. HacDonald,
Maintenance
Branch,
DRS,
(paragraph
3.2)
Approved by:
ar
S.
Lesser.,
C ie
Reactor Projects
Branch
6
Division of Reactor Projects
m/z.~/9 0
ate
sgne
SUMMARY
Scope:
Inspections
were conducted
by the resident
and other inspectors
in the areas
of operations
which included routine observati'ons,
review of Unit 3 thermal
power above license condition maximum, freeze protection program,
and
verification of engineered
safeguards
system alignment;
maintenance
which
included, routine observations,
post maintenance
testing
program,
trending
and
corrective actions,
and scheduling
and planning;
engineering
which included
review of spent fuel pool cooling system
and refueling outage
core unloading
practices,
measures
to prevent'oi'sture
intrusion into safety equipment,
and
Enclosure
2
9603i40308
960229
ADQCK 05000259
8
'lN
~is
drywell air monitor setpoint determination;
plant support which included
routine security observations,
ALARA planning effectiveness,
post accident
sampling observations,
and required radiation exposure
postings.
In several
of the areas,
review of open items, including one Unit 3 post restart
Three
Mile Island item,
was also conducted.
Results:
Plant
0 erations
A violation was identified which addressed
Unit 3 operating with core thermal
power above the l.icensed condition maximum for several
hours.
Due to a
problem with a feedwater temperature
transmitter,
indicated core thermal
power
was lower than actual
power.
Operators
increased
core recirculation flow to
maintain indicated core thermal
power at the full rated value.
The condition
was identified after several
hours
when
an operator
noted irregularities
between control
room indications.
(Violation 296/96-01-01,
Core Thermal
Power
Above Licensed Condition Haximum, paragraph
2.2)
Overall implementation of the freeze protection
program was effective.
The
inspectors
noted that
some administrative
aspects
of the program were not
being rigidly implemented,
but there
was
no reduction in the cold weather
protection of safety-related
equipment.
Equipment problems
have
been
few
despite
recent
extended
periods of cold weather.
(paragraph
2.3)
Maintenance
The Post Haintenance
Test
(PHT) Program
and program implementation
were
considered
acceptable.
The
PHT process
was complex, requiring
4 procedures
for implementation.
PHT backlog
and
PHT failure rate were low.
The number of
PHT Problem Evaluation Reports
was low.
PHT activities were generally
adequate
and performed in accordance
with program procedures.
One example of
inadequate
PHT was noted in a scheduled
work order which was subsequently
returned to maintenance
planning for revision.
(paragraph
3.2)
The licensee
has
implemented effective controls for identifying, resolving,
and preventing
issues that degrade
the quality of plant operations
or safety.
The corrective action program at Browns Ferry has
been intentionally set at
a
very low threshold for reporting, evaluating,
and trending plant problem
evaluation reports in order to capture
low level events,
encourage self-
identification of conditions,
and provide effective management
oversight of
all conditi'ons in
a "window" format.
Effective senior plant management
oversight which requires
management
accountability in every area of the
corrective action program
was found to be
a strength.
One concern
was
identified associated
with the application of the Stop, Think, Act, and Review
program.
(paragraph
3.3)
Review of on-line maintenance activities concluded that the licensee
had
a
very strong
program to control the planning/scheduling
of work accomplished
on
its operating units,
which is directed at the completion of surveillance
and
maintenance
in a very aggressive
fashion, while maintaining the plants in as
safe
a condition
as possible.
Two minor discrepancies
were noted,
one
0
~ii
regarding inclusion of Individual Plant Evaluation matrix requirements
into
7,. 1,
and the other concerning the need to strengthen
the scheduling of
Preventive
Maintenance.
(paragraph'.4)
En ineerin
Review of the Unit 2 spent fuel cooling system
and core unloading practices
identified no deficiencies.
The licensee's
refueling outage practices
regarding the offloading of reactor fuel were
as described
in the Final Safety
Analysis Report.
(paragraph
4. 1)
The. licensee's
current actions to prevent moisture intrusion into
safety-.related
equipment in the intake structure
from conduits passing
through
yard areas
were considered
satisfactory.
Previously,
water
had leaked in from
cable
pul-1 points or through wall penetrations
into the intake structure in
the vicinity of safety-related
cabling.
No degradation
of the cabling was
identified and the licensee
is presently pursuing corrective actions
adequately.
(paragraph
4.2)
An unresolved
item was identified during review of an increase
in Unit 2
drywell inleakage.
The inspectors
noted that the setpoint of the drywell
continuous air monitor appeared
to conflict with statements
in the Technical
Specifications.
Information and experience
indicates that the system is
capable of performing its safety function of identifying increased
leakage
rates,
but additional
review is necessary
to ensure that Technical
Specification requirements
are being met.
(Unresolved
Item 260,296/96-01-02,
Drywell
CAN Setpoint Determination
Method, paragraph
4.3)
During a review of ALARA planning effectiveness,
the inspectors
noted that the
licensee
did not document
management
review/resolution of recommendations
included in some post job review reports.
(paragraph
5.2)
Ij
'l5
REPORT DETAILS
'Acronyms used in. this report are defined in paragraph
8.
1.0
PERSONS
CONTACTED
2.0
2.1
'Licensee
Employees:
Abney, T., Manager,
Independent
Review and Assessment
Blakley, P., Surveillanc'e Instruction Scheduler
Brazell, J., Site Security Manager
Clardy, L., Audit Manager
Coleman,
R., Radiological Controls Manager
Corey, J.,
Chemistry
and Radiol'ogical Controls Manager
- Crane, C., Assistant
Plant Manager
Gilbert, P.,
PH Scheduler
Johnson, J., Site guality Manager
Jones,
R., Operations
Manager
Little, G., Operations
Superintendent
- Hachon, R., Site .Vice President,
Browns Ferry
- Haddox, J.,
Haintenance
and Hodification Manager
Parvin, J.,
CA( Supervisor
- Pierce,
G., Technical
Support
Manager
- Preston,
E., Plant Hanager
Rogers,
R., Maintenance/Modifications
Planning Technical
Manager
Sabados,
J.,
Chemistry Manager
Salas,
P.,
Licensing Manager
Schlessel,
J.,
Maintenance
Superintendent
Schumitsch, J., Daily Scheduling
Manager
Scott, T., Maintenance
Technical
Supervisor
Shadrick,
R.,
FME Coordinator,
Maintenance
Shriver, T., Nuclear Assurance
and Licensi'ng Manager
Thompson, J., Senior Instrument
and Control Engineer
Wages,
C., Maintenance
Program Coordinator
Wetzel, S., Acting Compliance
Licensing Manager
Wheeler, J.,
Work Week Manager
White,. D., Manager,
Reactor Safety Engineering
and Review
- Williams, H., Engineering
and Materials Manager
- Attended,February
2,
1996 Exit Interview
Other licensee
employees
contacted
included office, operations,
engineering,
maintenance,
and chemistry/radiation
personnel.
PLANT OPERATIONS (71707,
71715,
92901,
40500)
OPERATIONS
STATUS AND OBSERVATIONS
Unit 2 and Unit 3,operated't
power during this inspection period.
On
January
21,
1996, the licensee
began final feedwater temperature
'l!
0
reduction operations
on Unit 2 by isolating the extraction
steam to the
Al, Bl, and Cl feedwater
heaters
to allow an extended
period of full
power operation.
On January
31, reactor
coastd'own
commenced
and is
expected to continue unti,l Harch 22,
when the
U2C8 refueling outage
begins.
At the close of the report period, Unit 2 was at 99X.
Operations
were routinely inspected
throughout the report period in
accordance
with the guidance
in Inspection
Hodule 71707.
In addition to
weekday monitoring,
some inspections
were conducted
on night shifts and
weekends.
Overall, control
room operators
were attentive
and
professional
in their duties.
During, one backshift control
room visit,
the inspector
observed
control rod testing in progress.
The inspector
noted that the operators
were referencing the appropriate
procedures,
keeping the
ASOS informed,
and were cautious
when changing reactivity to
increase
power back to full. rated level.
The inspector also verified
that the
SOS
was
aware of, the status of the testing
on Unit 3.
On January
9,
1996,
the inspector
noted that
one of the Unit 2 RCIC
turbine exhaust line snubbers
was leaking oil.
The indicator on the
snubber indicated that there
was very little oil remaining.
The
inspector
informed Operations
and the system engineer.
The snubber
was
subsequently
declared
removed,
and rebuilt.
During
disassembly,
the licensee identified that the oil was leaking from the
oil fill fitting.
During rebuild this fitting was replaced.
Following
rebuild, the snubber
was tested satisfactorily
and reinstalled
in the
system.
On January
21,
1996, the Unit I/2
B diesel
generator
auto started
unexpectedly
when the local alarm panel test pushbutton
was depressed
during testing.
The
EDG .did not tie onto the shutdown
board since
normal supply voltage
was available.
Since the cause of the auto start
was not apparent,
the
EDG was declared
inoperable until troubleshooting.
efforts were completed.
'The licensee identified that
a shorted
diode in
the annunciator .circuit caused
the energization of the start failure
auxiliary relay which caused
the auto start.
Normally the diode would
block the relay from energizing to allow testing of the annunciator
circuit.
The l.icensee
replaced
the damaged
diode
and following
successful
PHT of the
The licensee
reported
the
EDG start to the
NRC Operations
Center
as required.
During a routine tour of a mechanical
equipment
room in the control bay,
one of the inspectors
noted that plastic tubing had
been routed into a
ventilation duct at
an opening, which is required to be blocked
by some
Appendix
R procedures.
A piece of plexiglass is staged
to be used to
block the opening.
The hoses
are connected
to purge
pumps located -on
the control
bay chillers.
Since the hoses
were thick-walled and
appeared
to extend
wel:1 into the ductwork, the inspector questioned if
hoses
would prevent the performance of the procedure.
The
SOS
was
informed of the observation
and investigated.
Subsequently, it was
determined that the hoses
could have
been pulled out of the duct to
allow the plexiglass to block the opening.
The hoses
were relocated
so
that there is sufficient clearance
to install the plexiglass if
0
i1
required.
The issue
was discussed
with Operations
management
as
an
example of conditions which should
be questioned
by operators
during
rounds.
2.2
UNIT 3
THERMAL POWER
EXCEEDED LICENSE CONDITION MAXIMUM
On 'December
27,
1995,
feedwater temperature
transmitter
(3-TT-3-48A),
which provides
an input into the plant computer for calculations of core
thermal
power (HWt), was returned to service after repair-activities.
The feedwater temperature
is also indicated
on SPDS.
On December
28,
at 12:45 a.m.,
an operator noticed
HWt decreasing
with a steady
electrical
output
(MWe).
Upon further review, the operators
noticed
that the feedwater transmitter output,
which normally reads
375'F at
IOOX power,
was reading approximately
402 F. At 1:02 a.m.,
power was
reduced
5
MWe and the transmitter's
input to the power calculation
was
removed.
At 1: 15 a.m.,
power was reduced
another
5
MWe resulting in an
output of 1115
HWe with actual
core power of 3284
MWt.
On December
28, the inspectors
obtained
SPDS printouts
and reviewed
chart recorder traces
as well as other information in order to verify
changes
in parameters,
magnitude of change,
and time intervals.
The
incident was discussed
with Operations
and Maintenance
personnel.
During their initial review of the event,
the inspectors
noted the
following:
On December
24, the transmitter's
input to the thermal
power
calculation
was
removed .from service
due to indication swings.
On December
27,
as the transmitter
was initially returned to
service, it presented
an indication of 3'F to 4
F higher than the
other inputs
(about
379 F).
On December
27, from 4:00 p.m. to 6:52 p.m., the temperature
indication
(and input to thermal
power calculation) steadily
increased
.to 391'F,
causing
the calculated
HWt to slowly decrease.
Since
HWt indicated
was decreasing,
operators
incrementally
increased
recirculation flow to maintain
an indicated
power level
,of 100% thermal
power.
The temperature
indication remained at about
391'F. until 12:45
a.m.,
December
28,
and then
more abruptly changed
to 402'F.
The
sudden
increase
subsequently
presented
a significant drop in
indicated
HWt with little change
in
MWe output.
Operators
reduced
power shortly thereafter.
From 6:52 p.m.,
on December
27 to 12:45 a.m.,
on December
28,
actual
core power was increased
as high as
35
MWt above rated full
power of 3293
HWt.
The eight-hour shift average
was
3306
HWt
(100.4N) with an instantaneous
peak of 3328
HWt (101. 1/).
Initially, the investigation into the cause of the feedwater
temperature failure focused
on loose circuitry connections
because
lS
!I
a terminal
board lug screw was found loose.
Repair activities
included
use of an adhesive
and tightening of the screws
on this
and all similar terminals.
However, after the repair,
the
transmitter
again failed and
by the end inspection period, the
licensee
had placed the transmitter out of service.
After reviewing applicable portions of the
FSAR, the inspectors
also
reviewed the results of the
GE review of the incident to verify that no
assumptions
in the analysis of the design basis
accident
had
been
exceeded:
0
The review concluded that there
was
no adverse effect upon core
safety
and integrity.
GE stated that, in the design analysis,
there is greater
than
a
5%%d
margin to any core thermal limit. They also noted that the event
margin reduction to
4%%d was still well below design limits.
Furthermore,
analysis
performed to set core thermal limits took
into account
a
2%%d core power uncertainty.
Therefore,
concluded that the overpower of about
35
HWt did not adversely
impact plant safety.
Further inspector review indicated that there
had
been
some
opportunities to identify the problem earlier
and several
factors
had
contributed to the performance of the operators
in this incident.
The
inspectors
made the following conclusions
regarding the incident:
The initial slow transmitter failure mechanism
was difficult for
the operators
to detect.
The operators
did not carefully review all available indications
of plant parameters
after reactivity changes
were initiated.
Specifically, they did not investigate
an apparent
power reduction
wi'thout corresponding
changes
in HWe output.
The computer alarms for important plant parameters
such
as
feedwater temperature
were not set at appropriate levels to alert
the operators
of this type of an equipment
problem before limits
were approached.
Information indicated that
some of the, board operators
were not
fully aware that maintenance
had recently
been
performed on, the
transmitter circuitry and there
was
no heightened sensitivity
given 'to the indication.
PER (0951914)
and
an event
human performance
analysis
also noted that
the operators
did not have
a solid model of indications expected
at
rated thermal
power.
4l
IP
As an initial response
to the event,
the licensee
has proposed
the
following corrective actions:
Reactor
Engineering will develop
a detailed
model of plant
conditions at rated thermal
power for both Unit 3 and Unit 2.
The
model will reflect current plant conditions
and is to be provided
to
BFN Operations
by the end of February,
1996.
Operations will provide the .above
model to all licensed operators
and this model will be available
as
a control
room reference
by
April, 1996.
Licensed operator requalification training program will include
training
on the detailed
model
by April, 1996
and
BFN Operations
wi.ll establish
a process for periodic updating of the model
by
Hay,
1996.
Technical
Support will evaluate
the heat balance
alarm setpoints
to verify adequate
warning of non-conservative
failures.
Setpoints
are to be changed/completed
by the
end of February,
1996.
Unit 3 Operating
License Condition 2.C(l),
Maximum Power Level states
that the licensee
is authorized to operate
the facility at steady state
reactor
power levels not in excess
of 3293
MWt.
Reactor, power,
averaged
over
an 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> period
ex'ceeded this value.
This event is
a violation
and will be addressed
as Violation 296/96-01-01,
Core Thermal
Power
Above License Condition Maximum.
2.3
IMPLEMENTATION OF
FREEZE
PROTECTION
PROGRAM
On December
22,
1995,
the inspectors
toured the service water building,
intake structure,
diesel
generator buildings,
and Standby
Gas Treatment
building inspecting freeze protection
systems
as the temperature
had
been
below freezing for the previous several
days.
In the Unit I/2
diesel
generator building the inspector discovered
the portable heater
in the carbon dioxide tank room was turned
OFF.
In addition, the room
heaters
in
EDG rooms A, D,
and
3C were
OFF.
The thermostats
in the
remaining
rooms were all set differently ranging from 45 to 90 degrees
fahrenheit.
The inspector discussed
these
observations
with the
ASOS.
He noted that while the heater in the carbon dioxide tank room shoul'd-
have
been energized,
the room was'ot
so cold as to affect the operation
of the system.
The inspector
reviewed the licensee's
procedure
concerning freeze protection,
O-GOI-200-1,
Freeze
Protection
Inspection,
and noted that while the Unit 3
EDG carbon dioxide tank room heater
was
listed in this procedure
the Unit 2 tank room heater
was not.
The: ASOS
stated that the heater
would be energized
and
added to the list of items
to be verified in the procedure.
In addition,
he stated that since the
EDG rooms. were maintained
warm by convection
from the
EDG crankcase
and
jacket water heaters, it was not necessary
to use the room heaters.
Those heaters
are operated
as
needed
by building operators
.as they make
their routine rounds,
therefore the heaters
and thermostats
were not
4
i&
2.4
maintained
in a particular configuration
by plant procedures.
The
inspector
reviewed the freeze protection procedure
and considered it
adequate
to provide the necessary
protection to guard against cold
weather conditions.
Attachment
3 of this procedure is
a discrepancy
log
used to identify those
items listed in the procedure
which are in need
of maintenance.
The inspector
noted that this list of discrepancies
was
quite long, containing approximately sixty different items in need of
repair.
Although none of the .items
on the list were considered
to
require
immediate attention or affecting operability of a safety-related
system,
there were items which had
been
on the list since
September.
Step 5. 10.5 of the procedure requires that
an
ASOS review all items
on
this log every midnight shift to check the status of each
open
discrepancy.
The inspector discussed
this list with the Operations
crew
on shift and determined that the status of the items
on the list had not
been determined
for
some time.
A recent revision to the maintenance
computer software
had a'ffected the ability of the operators
to perform
the checks.
This was discussed
with the Operations
Superintendent
who
directed that this review be performed
and reinforced that thi's list be
maintained current.
A standing order was issued to provide these
instructions.
While the maintenance
of the discrepancy
log was
considered
inadequate,
the inspector could not find. a case
where it
resulted
in inadequate
freeze protection to plant equipment.
The list
generally consisted of items
such
as
damaged
door seals,
damaged
insulation,
and faulty space
heaters,
however other means of preventing
cold weather related
damage
was in place.
Toward the
end of the report
period the inspector verified that the log was being maintained current.
Subsequent
inspections
of freeze protection related
equipment identified
no additional discrepancies.
ENGINEERED SAFEGUARDS
SYSTEM VERIFICATION
During this report period the inspectors
performed
a detailed
inspection
of the Uni't 2 Core Spray system.
A walkdown of the system
was performed
to verify the system lineup was correct
and drawings accurately
reflected the as-built configuration.
Hangers
and supports
were
verified to have adequate fluid and in good working order.
Valves,
pumps,
and motors were inspected
to verify labelling was correct,
no
excessive
leakage existed,
and general
overall condition was acceptable.
Housekeeping
was verified to be acceptable
in the surrounding
area.
Instrumentation
was verified to be operable
and indicating appropriately
for system conditions.
Electrical
power was verified to be aligned for
the system in accordance
with plant procedures.
The inspector did not
identi'fy any concerns
that were not already identified by the licensee.
The
FSAR and system design
documents
were reviewed
and
compared to the
actual
system design
and operation.
The system design criteria,
BFN-50-
7075, section 3.7.1 (7), stated that the system provides
secondary
containment isolation connections
to the reactor building condensate
header, by means of locked closed valves.
The inspector noted that these
valves were not locked closed
and questioned
the licensee.
Site
engineering
subsequently
determined that the valves did not have to be
locked
and will revise the design criteria accordingly.
The inspector
OS
iS
2.5
concluded that the- Core Spray system
was properly aligned,
in good
mechanical
condition,
and capable of performing its intended function.
REVIEW OF
INPO EVALUATION REPORT
2.6
The senior resident
inspector reviewed'he final report for the
1995
INPO evaluation.
The inspector
concluded that, the report did not
include
any issues with a patential to substantially affect nuclear
safety -in the short term and thus
no specific followup NRC inspection is
necessary.
The
INPO report was, in general,
consistent with current
NRC
perceptions
of BFN performance.
OPEN
ITEMS REVIEW
2.6.1
VIO 260/94-24-02,
FAILURE TO
FOLLOW PROCEDURES
This violation addressed
four examples
regarding lack of procedural
adherence.
The licensee
responded
in correspondence
dated
December
2,
1994.
The first example involved
a failure to properly monitor reactor
water level during reactor cooldown,
as required 'by plant procedures.
At that time the licensee
was required to maintain reactor water level
indication displayed
on one of the integrated
computer
system
screens
located in the main control
room.
This. was in response
to
a problem
being experienced
with water level indication during the cooldown phase
of a reactor
shutdown in
BWR plants.
Because this requirement
was
no
longer required following the implementation of reactor vessel
level
instrumentation modifications,
the licensee's
corrective action for this
example
was to delete this requirement
from the applicable procedures.
In addition, the licensee
discussed
this event in the .monthly
SOS
meeting.
The second
example occurred
when
one of the reactor
recirculation loop temperatures
was not monitored or recorded
.as
required
by plant procedures
during reactor
cooldown.
Following the
discovery,
the appropriate
data
was recovered
from the computer files.
Corrective action for this event
was to discuss it at
an
SOS monthly
meeting
and review it with the Operators
as part of their training
program.
The third example occurred
when
SBGT system
were not
returned to their normal position following the performance of
surveillance testing.
The licensee
realigned the dampers correctly.
This example
was also discussed
at the monthly
SOS meeting.
In
addition,
the licensee
reviewed other non-Operations
surveillance
instructions to determine if the system restoration portion of the
procedure
provided adequate
guidance to ensure
proper post-test
realignment.
The review. included
563 Surveillance Instructions,
Chemistry Instructions,
and Technical
Instructions.
Sixty-six of the
procedures
required'evision
to ensure
proper.
system restoration.
The
fourth example occurred
when the licensee failed to return, a HPCI system
handswitch to the proper position following its operation,
as directed
by alarm response
procedures.
The switch was
supposed
to be used to
open
a drain valve
and then again to close the drain valve upon
completion of the draining process.
In this case,
the Operator failed
to realign the switch
as required
when the draining evolution was
completed.
Following identification of the issue,
the switch was
0
3.0
3.1
repositioned correctly.
The Operator
was counselled
and the event
was
discussed
both at the monthly
SOS meeting
and then with the Operations
shift members.
In response
to this violation and subsequent
procedural
errors,
the
l.icensee initiated
an Incident Investigation to. review operational
error
events
and develop corrective actions.
A follow-up evaluation
was
performed approximately six months after the completion of the
investigation to assess
the effect of the corrective action.
This
assessment
indicated
very. little change
regarding factors contributing
to procedural
adherence
problems.
Surveys
and interviews were completed
which indicated that the improvement
had not progressed
as far as the
licensee
had hoped.
The licensee attributes
the lack of progress
in
this area to the increased
workload associated
with the startup of
Unit 3.
Discussion with Operations
management
indicated that
a new
program to address
procedural
adherence
issues
is under development.
The inspector verified the specific corrective actions for this
violation have
been
completed.
This violation is closed.
One violation was identified in paragraph
2.2.
MAINTENANCE (62703,
92902,
40500,
61726,
92901,
37551,
92903)
MAINTENANCE AND SURVEILLANCE ROUTINE OBSERVATIONS
Maintenance activities
and surveillance tests
were observed
and/or
reviewed during the reporting period'n
accordance
with the guidance in
Inspection
Modules
62703, and. 61726
The following maintenance
and surveillance activities were reviewed
and
witnessed
during routine inspections:
WO 96-000812-00
Repair of Unit 3
Gas Return
To Suppression
Chamber
Check Valve 3-CKV-043-0163
3.2
On January
23,
1996, after
a Unit 3
PASS gas
sample
was analyzed,
(See
Paragraph
5.3) high oxygen content within the sample
was detected.
After troubleshooting activities were performed, it was determined that
the
Gas Return to the Suppression
Chamber
Check Valve, 3-CKV-043-
0163,
was intermittently preventing
gas
samples
from returning to the
PASS.
After repairs to the valve were performed,
on January
26,
1996,
the system
was returned to service
and,resampling
was, performed.
The
inspectors
concluded that the repairs were, conducted
and the system
performed satisfactori,ly.
POST
MAINTENANCE TESTING
The inspectors
performed
a review of the Post Maintenance
Testing
(PHT)
Program at Browns Ferry.
PHT tracking
and backlog were examined.
Procedures
for
PHT and
PHT, related
PERs were reviewed.
Nuclear
Assurance
audits,
maintehance
'department self assessments,
and work
order feedback
forms were reviewed for data regarding
PHT.
Work orders
'0
'lN
3.2.1
in the planning stage,
ongoing work,
and completed
work orders
were
examined for PHT adequacy.
REVIEW OF
POST
MAINTENANCE TESTING
PROGRAM
The
PMT process
was controlled
by SSPs.
The process
was complex and
required the use of the following four procedures:
SSP 6.2
Haintenance
Management
System,
SSP 6.50
Post Maintenance Testing,
SSP 8. 1
Conduct of Testing,
and
PHT-0-000-TST001
PHT Maintenance Testing
Matrix.
The required
PHT was specified
by maintenance
planning personnel
during
work order preparation
then was reviewed
by a technical
reviewer,
quality assurance
and cognizant supervisor
as appropriate
and operations
SOS prior to conducting the testing.
PHT activities which deviated
from
the guidance of PMT-O-OOO-TST001,
the
PHT Maintenance
Testing Matrix,
required Technical
Support/Maintenance
Engineer concurrence.
The
completed
PHT was reviewed
by performing department
personnel
and the on
shift SOS.
The work order tracking system
showed
a backlog of approximately
90 work
orders awaiting
PHT.
The backlog included
63 Unit
1 items with 38 items
> 6 months old.
The
PHT backlog of Unit 0
Common equipment
was
29 with
8 items
> 6 months old.
Unit 2
PHT backlog
was
24 with 6 items
> 6
months old and Unit 3
PHT backlog
was
39 with 5 items
> 6 months old.
Browns Ferry weekly, performance
data indicated that. an average of 80 to
100,corrective
maintenance
work acti.vities were completed
per week.
The
92 item
PHT backlog represented
approximately
one week of work
activities.
The inspectors
determined that the
PHT backlog
was not
excessive
indicating that most
PHTs were being performed shortly after
completion of the maintenance
activity.
r
The
BFN weekly status
reports
indicated
an average of 3 failed
PMTs per
week.
These
items represented
work which changed
from awaiting
PHT
status
back to available for work status
due to either
a problem with
the planned
PHT, or work scope
changes
or plant configuration changes.
The number of failed
PHTs was low and did not indicate
a problem, with
PHT planning.,
3.2.2
REVIEW OF CORRECTIVE ACTIONS ASSOCIATED WITH PHT ISSUES
The inspectors
reviewed the
PERs related to PHT.
From January,
1995, to
January,
1996,
eleven
PERs were identified which were related to PHT.
The eleven
PERS included
one level
B PER,
seven level
'C PERs,
and three
level
D PERs.
The
PERs were reviewed to determine root cause.
Five
PERs were due to inadequate
PHT, four PERs were due to
PHT
administrative or documentation
problems,
and two PERs were due to
PHT/plant configuration problems.
Approximately 0.2X of PHT activi'ties
resulted
in
PERs
assuming
100
PHTs performed weekly.
Noncited Violation 296/95-64-03,
Equipment
Returned to Service Without
Proper
PHT Completion,
was discussed
in
NRC Inspection
Report
11
10
50-260,296/95-64 for the
one level
B PHT PER951842.
Incident
Investigation Unit 3 Control Rod 42-39 Triple Notch Event
December
4,
1995 was performed for the level
B PER951842.
The inspectors
reviewed
the incident investigation
and determined that the root cause
evaluation
was thorough.
The short'erm
and long term corrective actions
appeared
to be focussed
on root cause resolution
and were intended to strengthen
the
PHT cl'osure process.
The inspectors
reviewed Nuclear Assurance
maintenance
audits,
maintenance
department self assessments,
and work order feedback
process
forms and determined that these evaluations
did not identify problems or
offer recommendations
for improvement to the
PHT program.
During 1994,
the licensee
conducted
an internal review of the work order process
to
identify areas for improvement.
This internal evaluation identified
some problems with PHT for the sample work orders reviewed.
The
PHT
areas for improvement identified in the licensee's,internal
assessment
included:
some
PHTs not problem related,
some
PHTs not clearly worked,
some.
PHT adequacy
marginal,
some
PHTs out of sequence
with work steps,
and
some steps
under
PHT heading
not
PMT steps.
3.2.3
VERIFICATION OF
PHT
PROGRAM EFFECTIVENESS
The inspectors
reviewed
PMT adequacy for selected
work orders
scheduled
to be performed during the week of January
8-12,
1996,
and observed
some
PHT activities in progress.
Completed, work orders
were also reviewed
for PHT adequacy
and
program
implementation.
PHT activities observed
in progress
were acceptable
and were conducted
in accordance, with the requirements
of the
PHT program
SSP procedures.
Some minor deficiencies
were noted in the review of scheduled
and
completed
work orders.
PHT for the selected
scheduled
work orders
reviewed
was acceptable
and met the
PHT
SSP requirements
except for work
order 90-022313-000.
The specified
PHT for this work order was not
adequate
for the intended
maintenance
and did not meet
PHT
SSP guidance.
The licensee
indicated that the work order was returned to maintenance
planning for revision
and that
a
PER would be written.
The review of completed
work orders
noted
some minor deficiencies
where
PHT requirements
were generic
and did not always contain
acceptance
criteria specific to the component
addressed
in the maintenance
activity.
PMT specified
was not always in accordance
with the guidance
specified in the
PHT matrix.
These minor deficiencies
were similar to
the findings of the licensee's
1994 work order improvement review
indicating that the results of that improvement effort were not fully
implemented
and effective.
Il
~IN
3.3
EFFECTIVENESS
OF
LICENSEE
CONTROLS IN IDENTIFYING, RESOLVING,
AND
PREVENTING PROBLEMS
The inspector
reviewed Nuclear Assurance
and Licensing
(NA&L) audits,
surveillances,
self assessments,
problem evaluation reports
(PERs),
procedures
and trending reports.
The inspector also attended
meetings,
and conducted
interviews with maintenance
personnel
and management
from
each group within NA&L to determine
whether the corrective action
programs
at Browns Ferry, were effective in identifying, resolving,
and
preventing
problems that degrade
the quality of plant operations
.and
safety.
The inspector's
specific area of focus
was to determine
how the
licensee's
controls
improved plant maintenance.
A detailed analysis of
NA&L audits,
monthly surveillances,
self assessments,
PERs,
and trending
reports dealing with maintenance
and issued
from April 1,
1995,
through
January
31,
1996,
was performed to assess
the licensee's ability to
identify and correct problem areas.
This review revealed that audi.ts
and assessments
were well planned,
and documentation
was excellent.
NA&L findings were in diverse
areas
and revealed that the auditors
were
knowledgeable,
experienced
and effective.
A review revealed -that the
licensee's
findings were similar to findings identified by
NRC during
the
same time period.
This indicated that the licensee
was properly
focused
on suspected
problem areas.
Evaluations
conducted
on issued
PERs were effectively derived
and documented.
Scope of the corrective
actions
were expanded to include other applicable related
systems,
equipment,
procedures,
and personnel
actions.
The inspector
attended
a
PER root cause
analysis
committee meeting to observe
the process.
Based
on discussions
among the members
the inspector concluded that the
committee
members
were knowledgeable
and capable of determining the
appropriate
root cause for the problems
addressed.
Each
member
participated
in the discussions,
diverse
views were addressed
properly
and agreement
reached.
All departments
have fully implemented
the
PER program.
As .a result
over
1400
PERs
were initiated in 1995 with over 80 percent of the total
falling in the lower threshold category.
This reflected senior
management's
goal to lower the threshold for reporting, evaluating,
and
trending plant problem evaluation reports to
a level that captured
low
level events,
encouraged
self-identification of conditions,
and provided
effective management
oversight of all conditions in
a "window" format.
Oversight of the corrective action program is implemented
by NA&L's use
of. performance
indicators
such
as:
PERs issued/closed/remaining
open;
PERs rejected;
and
PER extensions.
A review of each of the indicators
revealed that they were effectively controlled.
The inspector
also
attended daily management
review committee
(NRC) meetings to observe
the
effectiveness
of the review process.
Each
PER, regardless
of its level
of severity,
was presented
for senior
management
review.
Each
PER was
appropriately discussed
and other areas
or plant units were considered
in the corrective action.
12
To determine
how the licensee
controls were
implemented
the inspector
reviewed documents,
attended
morning maintenance
production meetings,
the plant operations
review committee
(PORC) meeting,
and the plan of
the day meetings.
The plan of the day meeting
was assessed
as
a very
effective meeting which in addition to daily planning covered the status
of many diverse subjects
which affected plant performance
and safety.
In addition, the inspector interviewed maintenance
managers,
project
coordinators,
and engineers.
Specific areas
examined
included materials
management,
maintenance
history to ensure
that repetitive failures would, be correctly identified,
and conduct of
maintenance
(work practice).
Each of the areas
had previously been
identified by the corrective action program or by
NRC findings to have
weaknesses.
The inspector
examined the measures
taken or in process of
being completed
and found that corrective actions in each
area
were
being aggressively
pursued.
Personnel
responsibl.e
were held directly
accountable
by the site Vice President.
This accountability required
a
bottom line status of improvements
from each organization for their "Top
Ten Issues List" (including the plant manager's
Top Ten Issue List), the
"Achieving Excellence
Program"',
"Red
and Yellow Windows", "Major Project
Issues"
and "Executive Performance
Review", using
a
12 week rolling
schedule
to establish
the specific time for each meeting.
Corrective
actions
taken in the areas identified above were very good
and should
strengthen
performance of each
area.
One area which the inspector considered
a weakness,
based
on the review
of PERs,
audits,
and assessments,
was that of work practices that dealt
with issues
such
as
human performance
and procedure
adherence.
These
items are
on Browns Ferry's
"Top Ten Issues List", and comprehensive
corrective actions
such
as making work orders
more user friendly were in
process.
However, the inspector
noted
as 'a result of attending
maintenance
production meeti'ngs,
plan of the day meetings,
reviewing
documents,
and conducting, interviews, that the licensee did not
consistently exhibit an effective
and proactive attitude towards their
"STAR (Stop, Think, Act,
& Review) Program".
The inspector noted that
although proper attention
was being directed at correcting programmatic
barriers, insufficient action
had
been taken to train individuals tasked
to perform
a specific function on how to focus his or her attention
on
properly performing that function regardless
of the situation
around
them.
The inspector interviewed
a
NASL supervisor
about this
and found
that
NASL had audited the concern
and found that,
although plant
personnel
knew what
STAR stands for, when specific situations
were
presented
to individuals
and they were
asked
how to apply
STAR to
prevent
a discrepant
condition from occurring,
the individuals could not
do so.
3.4
SCHEDULING AND PLANNING OF MAINTENANCE ACTIVITIES
This portion of,the inspection
was conducted to review the licensee's
planning
and scheduling of on-line maintenance activities.
The
inspection
included
a review of the procedures
controlling the area;
attendance
at scheduling
and plan of the day meetings;
interviews with
the Daily Scheduling
Manager,
a Work Week Manager,
and the personnel
iN
13
responsible for scheduling surveillances
and preventative
maintenance;
review of .the twelve week rolling schedule;
and review of the licensee's
matrix, which was developed to prevent the simultaneous .scheduling of
work on systems/components
critical to .the high risk scenarios
in the
licensee's
IPE.
The focus of the inspection
included
a detailed
analysis of the licensee's
Work Week Schedule
9604 issued to control the
work accomplished
during the week of January
21 - 27,
1996.
The licensee
uses
a scheduling
scheme
which employs the use of a one
year SI schedule,
a twelve week rolling schedule,
an
IPE matrix, work
week schedules,
and the plan of the day meeting to schedule
and control
the work on the three
BFN units.
The one year SI schedule
provides
a
schedule of all Technical Specification required surveil-lances for the
upcoming calendar year.
This schedule
is developed
in consideration of
the twelve week .rolling schedule,
and .is based solely on the required
surveillance
frequency in Technical Specifications,
with no
consideration of the. SI grace period or when the SI is actually
performed.
The twelve week .rolling schedule
is
a medium range
schedule,
which provides the fundamental
technical, framework for the scheduling of
work during
a twelve week period.
This schedule
(framework) is repeated
every twelve weeks.
This schedule
is designed
to maintain the plants in
as safe
a condition
as is possible,
allowing necessary
work and
surveillance to be performed
as required/needed.
The schedule
separates
plant systems
by electrical division, schedules
work on
ECCS systems
in
different work weeks,
considers
the interaction of systems
which are
shared
between
the three units,
and forces
a review of the backlog of
work on every plant system at least
every twelve weeks.
The
IPE matrix
identifies the important interactions
between
the systems for all three-
units
as addressed
in technical specifications,
and in the most
significant risk based
scenarios
in the licensee's
IPE..
The matrix
provides additional
guidance to work week managers
in the scheduling of
work, which prevents
systems
from being
removed
from service
simultaneously
which are important in the risk based evaluation of the
IPE.
The work week schedule
is the backbone of the licensee's
work
control
and scheduling
program.
The work week schedule
schedules
all
planned
work for a given work week (a period of seven days).
The
scheduling of the work for a particular work week begins
several
weeks
in advance,
and is under periodic review and revision by site scheduling
and the involved plant departments
up until the time of execution.
The
final tool used
by the licensee
to schedule
and control work is the plan
of the day meeting.
The'lan 'of the day is used to schedule
emergent
work.
Priorities are given to emergent
work which involves control
room
or equipment in a degraded
status.
Work in these
categories
is worked
as
soon
as possible,
and other emergent
work is
prioritized for work in accordance
with, a later .work week schedule
or
during
an outage.
In order to evaluate
the effectiveness
of the licensee's
work control
and scheduling
process,
the inspector
conducted
a detailed
review of the
work scheduled
in licensee
work week 9604 ('anuary 21-27,
1996),
which
corresponded
to work week eight of the twelve week rolling schedule.
The inspector
was assisted
in this review by the work week manager
14
responsible
for that schedule.
This review consisted of a lengthy.
process
involving the evaluation of approximately
600 work items,
.involving surveillances,
preventative
maintenance
items,
and corrective
maintenance
items.
The inspector discussed
each
item on the work week
9604 schedule with the work week manager in an effort to obtain
a
complete understanding
of each work item.
In many cases
the applicable
SI,
PH or
WO was reviewed to learn the extent of work.
Each item was
then
compared to the SI schedule,
the twelve week rolling schedule
and
the
IPE matrix in order to assess
its impact
on plant safety.
This
inspection effort resulted
in the following observat'ions
and
conclusions:
The scheduling of SIs was in strict compliance with the
one year SI
schedule
and the twelve week rolling schedule,
and SIs were consistently
worked on schedule.
Several
work items (corrective maintenance
and
PHs) were noted which
were not scheduled strictly in accordance
with the twelve week rolling
schedule.
However,
in every case,
the work .did not have
any negative
impact
on plant safety.
If work was scheduled'n
deference
to the
twelve week schedule
on
an important safety
system,
the work did not
involve removal'f the syste'
'from service.
And,, i'f work was scheduled
in deference
to the twelve week schedule,
and did involve removal of the
system
from service,
the system
being worked was not important to the
safe
shutdown of the plant in the case of an event.
Scheduling of PHs was considered
to be the weakest link in the
scheduling,and
work control process,
The inspector determined that the
scheduling of. PHs involved consideration
and
use of the
25K grace
. period,
and
as
a result,
scheduling of this work. was easily postponed
during schedule
development.
Additional review of this area determined
that
PMs were accompl.ished after the late date approximately
15-20
percent of .the time.
However, it was noted that the licensee
did have
a
program in place, which,involved engineering
review for compensatory
measures
each time the late date
was missed.
This issue
was discussed
with the Daily Scheduling
Manager
and with the Site Vice President.
The
Daily Scheduling
Manager
was already
aware of the weakness
in the
scheduling of PHs,
and
was in the process
of scheduling firm completion
dates
in accordance
with the twelve week rolling schedule.
Computer
programming
problems
were hampering this effor't, but he was committed to
resolution of this issue.
When this issue
was discussed,
the Site Vice
President
confirmed that the completion of PHs
on schedule
was
considered, just as important
as completing SIs
on schedule.
Scheduling of corrective maintenance
appeared
to be adequate.
The
scheduling of emergent
work was in accordance
with the
scheme
discussed
above.
The inspector
reviewed data concerning the backlog of corrective
maintenance.
This data
showed that the backlog of on-line maintenance
work items (for Unit 2 and'ommon)
had decreased'ince
implementing the
twelve week schedule
concept
up until about August
1995 (from about
2500
items in January
1995 to about
2000 items in August 1995), but 'had
remained
about the
same
since that time.
It was also noted that when
)l~
lip
15
Unit 3 was brought
on line it only added approximately
500 items to the
on line backlog.
The inspector did not draw any specific conclusions
from this review.
3.5
., The inspector noted that all items scheduled
in a given work week were
scheduled
down to the day
and shift they were to be accomplished.
This
was discussed
with the Site Vice President,
and it was learned that the
reason for this amount of detail in the scheduling
was to improve
schedule .adherence.
The inspector
had previously reviewed data
on
schedule
adherence
and
was
aware that it was very good at about
70-80K
(i.e., work at
BFN is accomplished
on scheduled
approximately
70-80X of
the time).
The inspector
reviewed the procedure
which controls the scheduling
and
work control process,
SSP 7. 1,
Work Control, Revision
14, dated
December
21,
1994.
One weakness
was noted in this procedure
involving
requirements
regarding the implementation of the
IPE matrix.
The
inspector
noted that the procedure
did not provide any requirements
concerning
the use of this matrix in the scheduling
process.
TVA, in a
letter,
dated
December
19,
1994 committed to the incorporation of the
IPE matrices
in the scheduling
process for all
TVA plants
by the
end of
1995.
This commitment
appeared
to have. been
accomplished
at
BFN, based
on discussions, with various scheduling
personnel
and based
on
a review
of the matrix developed for this purpose.
However,
formal requirements
concerning
the use of this matrix have not been incorporated
into the
sites
scheduling
procedure.
This issue
was discussed
with the Daily
Scheduling
Manager
and the Site Vice President.
Both indicated that
action
was underway to proceduralize
the use of the matrix.
The inspectors'eview
of this area
concluded that the licensee
had
a
very strong
program to control the planning/scheduling
and control of
on-line maintenance activities,
which is directed at the completion of
surveillance
and maintenance
in a very aggressive
fashion, while
maintaining the plants in as safe
a condition
as possible.
OPEN
ITEMS REVIEW
3.5.1
VIO 259,
260, 296/94-17-01,
INSTRUMENT CALIBRATION DEFICIENCIES
This event'occurred
when licensee
personnel
did not properly update the
Preventive
Maintenance
program to reflect
a change
in the High Pressure
Coolant Injection minimum flow valve flow indicating switch unique
identification number.
The
UNID had
been revised to correct
a
discrepancy
between
the instrument label in the plant
and the equipment
computer database;
however,
the
new UNID was not added to the Preventive
Maintenance
program.
Therefore,
the flow'witch was not being
cal.ibrated.
Additionally, the setpoint for the switch was modified.
The process for changing,
a setpoint did not include
a mechanism to
ensure/verify
implementation of the changes
to the appropriate
procedures.
When this condition was identified the switch had the wrong
setpoint
and not been calibrated, for approximately
37 months.
80'
16
The licensee
responded
'in correspondence
dated August 29,
1994.
Corrective action for this violation was to revise the preventive
maintenance
procedure
and properly calibrate the affected switch.
SSP-6.3,
Preventive
Haintenance
Program,
was revis'ed to provide the
necessary
mechanism to ensure
preventive maintenance
procedures
were
updated
when UNID's were changed.
In addition,
SSP-6.8,
Instrumentation
Setpoint,
Scaling,
And Calibration Program,
was revised to require the
DCN process
be used
when. changing setpoints.
This process
includes
controls to ensure
other affected
procedures
are revised
and instruments
are recalibrated
to the .new setpoints
as necessary.
During the licensee's
review of this incident, it was identified that
other instrument setpoints
had
been revised without the .instrument
being
recalibrated
to the
new setpoint.
Upon discovery,
the licensee
performed the appropriate calibrations.
The inspector
reviewed licensee
documentation
and verified the affected calibrations
were completed
and
incorporated
into the appropriate
preventive maintenance
procedures.
Based
on completion of these corrective actions, this violation is
closed.
No violations or deviations .were identified.
4.0
4.1
ENGINEERING (37551,
92903,
40500)
REVIEW OF
SPENT
FUEL
POOL
COOLING SYSTEM AND FSAR,DESCRIPTION
OF
OUTAGE
FUEL UNLOADING PRACTICES
During this report period the inspector
performed
a detailed
walkdown of
the Unit 2 spent fuel pool cooling system using plant drawings,
applicable portions of the
FSAR,
and the system design specifications.
The inspector verified the plant drawings were accurate,
component
labelling was accurate
and physical condition of the system
was
acceptable.
Particular attention
was given to verifying that fuel pool
level instrumentation
and associated
annunciator logic power supplies
were divisionalized.
The inspector did not identify any deficiencies
not already identified by the licensee.
It was noted that the fuel pool
cooling pumps
had work requests
to repair leaking seals.
Packing
leakage
has
been
an ongoing problem with these
pumps
on all three units.
The inspector discussed
this with maintenance
personnel
and determined
that this problem has not led to
a failure of any of the pumps.
As previously stated,
the inspector
reviewed the system design basis
documents
and discussed
operating practices with the licensee
as they
pertained to core offload during refueling outages.
In the past the
licensee
has
performed
both full core
and partial core offloads.
A
partial core offload is planned for the upcoming Unit 2 cycle 8
refueling outage
scheduled
to begin in Harch,
1996.
The system design
documents
and .FSAR state that the fuel pool cooling system is capable of
removing the decay heat
from a full core offload at the
end of the fuel
cycle plus the decay heat of the spent fuel from the two previous
refuelings.
These
documents
state that the
RHR system would be required
to be operated
in parallel with the fuel pool cooling system
.in order to
IN'
17
remove this heat.
The inspector
noted that the calculations
which
determined
the 'heat
loads
and the heat
removal capability used limiting
values for fuel pool temperature,
reactor building closed cooling water
temperature,
and time after shutdown prior to fuel offload.
Discussions
with the licensee
indicated that historically the fuel pool cooling
system
has
been
able to remove the heat from a full core offload without
needing
the assistance
from the
RHR system.
The inspector
reviewed the
licensee's
procedures
applicable to the fuel pool cooling system .and
found them to contain
adequate
instruction to ensure
acceptable
pool
temperatures
are maintained.
MEASURES TO
PREVENT MOISTURE INTRUSION INTO SAFETY-REL'ATED EQUIPMENT
During routine tours over recent
months,
the inspectors
have noted water
leaking into the intake structure
through the thermolag enclosure
around
junction box 4915.
Currently, the thermolag is removed
and the box has
been
opened to address
the water intrusion issue.
This junction box
contains cabling associated
with some of the
RHRSW pumps
and is
important to safe
shutdown of the reactors.
The inspector
noted that
several
splices
are located within the enclosure.
In accordance
with
the fire protection
program,
the thermolag is
a required fire barrier.
The water leakage
has prevented
the licensee
from finishing work
activities
on the JB since
a 30 day "cure" time is required
on the
thermolag material.
Through review of .intake building access
records
and discussions
with personnel
assigned
as fire watches,
the inspector
verified that the licensee
has
been
implementing the compensatory
actions required
by the fire protection
program.
The inspector questioned
plant management
on the status of the
repairs
and whether the water .leakage
issue
was being addressed
appropriately.
On January
12,
1996, the inspector
was briefed
by.
engineering
management
and discussed
the repair activities with
maintenance
personnel
at the site of the leak.
The leak into JB 4915
and the west wall of the intake structure is being pursued.
The
inspector
was provided
a copy of an onpoing general
plan to resolve the
water problems.
A drain was found in the bottom of the JB enclosure
and
was subsequently
cleaned
out so that inleakage
could flow out of the
box.
One major source of the water appears
to be from unsealed
conduit
openings
located in "Handhole
15" northwest of the intake structure.
The
handhole is open at the bottom and ground water accumulates
well above
the conduit openings.
Plans
are to instal.l moisture seals
on the
conduit openings.
On January
16, the inspector
noted that
an initial
attempt to seal
the conduits
had
been completed,
but significant water
leakage
into the JB through the conduits
(and out the cleaned
out drain
path)
was still present.
The inspector
was
aware that water intrusion problems
had occurred at
TVA nuclear sites in the past
and reviewed documentation of past
corrective actions at
BFN.
The licensee's
actions regarding
NRC
Water Leakage
From Yard Area Through Conduits
Into Buildings, were reviewed.
The inspector
noted that at least
one
example of water
leakage
at
BFN due to unsealed
conduit openings
in
18
handholes
had
been
noted
and repaired.
The licensee
focused primarily
on secondary
containment
seals,
took credit for preventive maintenance
checks
performed
on manholes,
and concluded that
a review to identify
potential water leakage
paths
from yard, areas
into 'buildings containing
safety related
equipment
was not warranted.
Technical
Support personnel
conducted
a detailed
walkdown of conduits
passing
through secondary
containment
under elevation
572.5
and noted deficiencies
were corrected.
Actions in response
to
a Corrective Action Tracking Document associate'd
with water inleakage
included
a preventive
maintenance activity (BFN-0-
MISC-040) which requires
a check of plant
pumps for manholes,
valve
pits,
and tunnels.
NRC review of the licensee's
actions regarding water
inleakage into manholes
was documented
in IR 94-27
and the preventive
maintenance
activity was noted.
The inspector
noted that the
hand hole
15 had recently
been
added to .the work instructions for the
PM (even
though
no
pump is located in the handhole).
As, a result of the above reviews,
on January
17, the inspector discussed
with plant management
the concern that there
may be "handholes"
or other
cable "pull points" containing unsealed
conduits which may permit water
leakage into,buildings containing safety related
equipment.
The scope
of previous actions did not envelope all potential
paths.
The inspector
also questioned
the condition of the cable
and splices in JB 4915 which
had apparently
been wetted for an extended
period.
Subsequently,
after several
followup meetings with engineering
personnel,
the inspector
concluded that the vulnerability of safety
related
equipment to water intrusion from the yard was limited to
conduits/cables
routed to the intake building and the
EDG buildings.
The inspector
was provided detailed information on the routing of RHRSW
cabling
and all safety related cabling between
the turbine building and
the intake structure,
The inspector
reviewed the Fire Protection
Report
and other docketed
information and concluded that the routing was
as
described
in those
documents.
The design
and construction of the conduit
routing further limited the equipment of concern to the intake
structure.
Electrical engineering
personnel
supplied information which
supported
the conclusion that the cabling, and splices
would not be
damaged
by exposure
to water unless
such
exposure
was for years.
There
has
been. no indication of degradation
in the cabling.
Two of the inspectors
walked down the cable tray tunnel
between
the
turbine building and the intake structure.
Additionally, the pipe chase
tunnels in the turbine building were inspected.
While there
were small-
amounts of ground water intrusion in the pipe tunnels,
the water was
well below the level of safety-related
equipment
and the tunnel
systems
appeared
to be functional.
In the cable tray tunnel, the
inspectors
observed that temporary repairs
had
been
performed to stop
water intrusion into the tunnel.
Since the repairs
were obviously
temporary
(pieces of wood braced
against
foam stuffed into openings),
the inspectors
questioned
plant management
about plans to permanently
repair the leaks.
Maintenance
management
subsequently
informed the
inspector that
a
DCN is being
approved to address
the problem.
hi'S
19
4.3
At the
end of this. inspection period, additional
maintenance
activities
were being completed
in an attempt to seal
the conduit openings
in
handhol'e
15.
The inspector discussed
with engineering
personnel,
the
plans to thoroughly clean out the interior of the junction box to reduce
the chance that the drain would again
become blocked.
The inspector
requested
that the cables
and splices inside the box be examined before
the box is sealed
to verify that
no damage
had occurred.
The inspector
observed
workers cleaning out the box.
The licensee is considering
available
methods of sealing .the west intake wall during .the upcoming
refueling outage.
The inspector
concluded that, while the licensee
had not been aggressive
in the past regarding the inleakage into the intake building, the
current work activities are adequately
addressing
the issues.
The
inspector
concluded that there is no current safety-related
equipment
problems
associated
with the inleakage
into the intake structure.
DRYWELL AIR MONITORING SYSTEM ALARM SETPOINT
On December
23, the licensee
noted that the Unit 2 drywell inleakage
rates
had increased slightly and that intermittent alarms
were being
received
by the containment
atmosphere
monitor.
Drywell floor drain
samples
were taken but were inconclusive in identifying the cause of the
leakage.
The licensee
developed
a plan which included increased
monitoring of the floor drain. inleakage,
drywell'tmosphere
monitoring,
and altering, the operation of various
equipment located in the drywell.
The
RCIC inboard
steam
supply valve,
2-FCV-71-2,
was backseated
in
accordance
TI-317 because it has
been the source of increased
drywell
leakage
in the past.
However, in this case, it had
no appreciable
affect
on the leakage rate.
The speed of each reactor recirculation
pump was also varied, to determine if the leakage
could
be associated
with the seals,
but no noticeable
decrease
in leakage
was noted.
Because
the leakage
was causing
the
CAN to be in constant
alarm the
alarm setpoint
was raised
corresponding
to the increased
background
rate.
The licensee
performed .this in accordance
2-TI-24, Determination
Of Hain Steam Line And .Primary Containment
Leak Detection Radiation
Monitors Alarm And Trip Setpoints.
The inspector
noted that the
indicated reading of the
CAN was approximately
2E-9 microcuries/cc
and
the alarm setpoint
was
1. 18E-8 microcuries/cc.
This results in the
setpoint
being significantly greater
than three times the average full
power reading.
Technical Specification Table 3.2.E., requires that the
setpoint for the drywell air sampling
system
be set at three times
average
background.
The'ns'pector.
was unable to determine if the method
being
used
by the licensee
to establish
the alarm setpoint
was in
accordance
with this requirement.
The inspectors
noted that the
CAHs
have alarmed in the past
when drywell inleakage
has increased
and appear
to be performing their function.
This item is addressed
as Unresolved
Item 260,296/96-01-02,
Drywell
CAM. Setpoint Determination
Method,
pending
NRC review of the licensee's
alarm setpoint
procedure
and its
compliance with the Technical Specification.
20
4.4
REVIEW OF
OPEN
ITEHS
4.4.1
(CLOSED)
VIO 260/94-01-06,
APPENDIX R DESIGN
ERRORS
The first example resulted
from a licensee
determination that in fire
area
16 and fire zone 2-4,
power supply cables for redundant
RWCU valves
were not adequately
protected .nor separated
as required
by 10 CFR 50
Appendix R.
A second
example
concerned
cables
associated
with the
1D
Raw Cooling Water
pump which were not adequately
separated
from the
4Kv
Shutdown
Board A. It was determined that,a fault in the
Raw Cooling
Water
pump could propagate
to the shutdown
board
and
damage other
equipment required during
an Appendix
R event.
The licensee
responded
in correspondence
dated April 13,
1994.
Upon discovery of these
conditions,
the licensee initiated firewatch coverage
in the affected
areas.
Long term correcti.ve actions for the first example
include the
modification of the
RWCU system to install
an additional valve which
will isolate
upon detecting
a high coolant temperature
downstream of the
non-regenative
heat exchangers.
This will preclude
damage to the low
pressure
RWCU piping and subsequent
loss of reactor inventory.
DCN
W27992A is the controlling document for this modification which is
scheduled
to be installed during the upcoming cycle 8 refueling outage.
The inspectors
reviewed this modification, which was installed
on
Unit 3 prior to restart,
and found that it satisfied the concerns
identified in the violation.
The Appendix
R Safe
Shutdown
program
has
been modified for Unit 3 and will be similarly revised to incorporate
the Unit 2 modification.
Long term corrective actions for the second
example
included the installation of isolation fuses to isolate the
faulted cable
from the shutdown
board,
thus pres'erving the shutdown
board for use
by Appendix
R equipment.
This modification was installed
by
DCN T28107A.
The inspector
reviewed the applicable plant drawing
and'erified
it had
been appropriately revised to include the
new fuses.
The inspector verified the proper size fuses
were installed in the field
and were properly labelled.
Based
on this inspection, this violation is
closed.
4.4.2
(CLOSED) THI '296/II.F.2.4,
INSTRUHENTATION FOR DETECTION OF
INADE(UATE
CORE
COOLING
This THI item addressed
the need for additional instrumentation/controls
to supplement/take
the place of existing instrumentation to provide
an,
unambiguous
indication of inadequate
core cooling.
This was performed
by replacing reactor water level sensing lines, installing Rosemount
analog transmitters
and analog trip units.
The design
changes
performed
on Unit 3 were essentially
a duplication of those
performed for the
recovery of Unit 2.
This item remained
open following the restart of
Unit 3 in order that final post modification testing could be performed
on the subject instrumentation.
(A partial
review of this item had been
performed during the recovery effort and was documented
in IR 95-16).
The licensee
performed this testing,
in accordance
with 3-TI-149
(Reactor Water Level Heasurement),
during the power ascension
of Unit 3.
This inspection effort focused
on the review of the TI-149 results.
The
inspector's
review of the testing results
indicated that the reactor
21
water level instrumentation
accurately
tracked the reactor water level
from low power conditions
up to and including rated
power.
Based
on
this review, this item is closed for Unit 3.
No violations or deviations
were identified.
5.0
5.1
5.2
PLANT SUPPORT
(71750)
ROUTINE SECURITY OBSERVATIONS;
WALKDOWN OF
PROTECTED
AREA FENCE
The inspectors
performed
a walkdown of the protected
area fence.
The
fence
was verified to be in good .condition with no holes in the fence
fabric nor any loose fence posts.
However, the inspectors
noted that
the northern portion of,the protected
area
fence line, due to
construction
work in the area,
was in need of ground strapping repair.
One section of intrusion monitoring was also out of service for ground
repair.
It was the inspector's
understanding
that such repairs
are
scheduled
to be completed
in the near-term.
The inspectors verified the
appropriate
compensatory
action
was taken
and the area
adequately
protected.
The inspectors
observed
personnel
and packages
entering the
protected
area
and verified they were searched
either by special
purpose
detectors
or physical
patdown.
ALARA POST-JOB
REPORTS
On November 29,
1995, during
a routine walkdown of the refuel'ing floor,
an inspector observed, removal of items from the Unit 3 Spent
Fuel
Pool
(SFP).
One item removed
was
a vacuum hose which had
been
used to remove
cavity debris during drain-down for vessel
reassembly.
Some debris
included stellite/cobalt particles
found from control rod ball bearing
replacement
work. Initial plans included;
removal of the hose
from the
SFP,
placement of the assembly into plastic bags, further placement
in a
transfer cart,
and final transport of the
hose to
a shielded
box located
at the Unit
1 end of the refuel floor.
After the hose
was removed,
water was,drained
and the hose
was bagged.
Initial survey readings of
about
2 R/hr contact
(0.5 R/hr whole body) were observed;
however,
during transport,
more whter drained out of the assembly
and into the
bag
and dose rates
increased
to about
12 R/hr contact
(3 R/hr whole
body).
The hose
was quickly placed into the shielded
box; however,
rates
continued to increase
and readings
outside the box read
about
6
R/hr contact
(2 R/hr whole body).
An on-the-spot decision
was
made
by
the job. coordinator to remove the hose
from the box and immediately
place it back into the:SFP.
The inspector
noted that
ALARA post-job
"lessons
learned."
included considerations
for better shielding
and
better anticipation of expected
doses
outside of shielded containers.
As
a follow-up to the above observations,
an inspector also reviewed
PER
¹951852A.
On December
8,
1995, during
2A
RWCU pump work, maintenance
personnel
encountered
contamination/radiation
levels higher than
previously experi'enced.
Thr'ee individuals were contaminated
and
one
exceeded
his administratively, permissible, dose.
In explanations
detailing the issues, it was explained that the transport cart used to
22
ferry the
pump from the
pump room to the decon
chamber
was inadequate
because little shielding
was built into the cart.
The inspectors
noted
that there
was
a statement
that "this deficiency (had)
been
noted
on
previous post-job reports but (was) never rectified".
From their review of the
ALARA post-job reports,
the inspectors
concluded that it was not clear that the licensee
was using information
provided by the workers.
The inspectors
noted that workers
had
made
apparently
reasonable
recommendations
for dose reduction but it was not
clear that management
had reviewed the information for application to
future jobs.
The above described specific issues
were discussed
with
management
as examples of how better
ALARA post-job "lessons
learned"
follow-up may have helped to reduce
exposures.
Management
acknowledged
that improved use of such information may have
been beneficial
and
immediately reviewed the specific issues of concern
and initiated
changes
to improve the timeliness of post job reviews.
5.3
POST-ACCIDENT SAMPLING SYSTEM (PASS)
ACTIVITIES (UNIT 3)
On January
23,
1996,
an inspector
observed
PASS gas sampling activities.
BFN technical
personnel
performed this activity in accordance
with 3-TI-
331,
Post Accident Sampling Procedure,
Revision
1, Appendix D,
Gas
Atmosphere
Sampling.
The inspector noted the following:
Throughout
PASS panel
setup
and sampling activities,
many
"individual steps"
consisted of both conditional
phrases
&
substeps,
which is inconsistent with the guidelines of SSP 2.2,
Writing Procedures.
For example
Step 7.2.3 stated:
"Ensure the LI(UID PRESSURE
INDR, 3-PI-043-7661,
is reading less
than
150 psig.
If the pressure
reading is elevated,
THEN STOP .the
PASS setup,
NOTIFY. the Chemistry Shift Supervisor
and the Shift
Operations
Supervisor,
and
SUBMIT appropriate priority work
request.
(Sampling
may continue with Shift Operations
Supervisor
approval.)"
Step 7.2.9,
presented
information which confused the technicians:
"IF there
has
been
a PCIS Group
6 isolation,
THEN N/A Step 7.2. 10,
CONTACT the Unit Operator,
and
RE(VEST the following valve
operations
(handswitches
are located
on Panels 9-54 and 9-55).
Otherwise,
N/A this step."
PASS panel labeling consists of both "old" and
"new" system
numbering labels which could confuse,
rather than help, the
technicians
in determining which valve, or which controller,
should
be operated.
The Unit 3
PASS panel
has the
same green color,, label,ing
and
overall lay-out as Unit 2. This presents
a potential for wrong
unit/system operation
which would be conceivable
in accident
situations.
<<i
4
al,
ijg;i
23
TI-331 calls for good communications with control
board operators.
This can
be accomplished
by use of either in-plant telephones
or
radios.
,However,
due to high noise levels in the area,
both
telephones
and radios
may prove to be difficult to 'use for clear
communications.
The Unit 3
PASS panel
does not have
a nearby
telephone
and both Unit 2 and Unit 3 panels lack adequate
sound
insulation ("Hear-Here" ) booths
near the panels.
During a previously observed
PASS sampling activity (IR 50-296/95-16),
a
NRC inspector
had noted several
deficiencies.
Improvement
was
observed
in the recent
sampl'e.
The following compares
issues
found in
1995
and recently observed activities:
Februar
1995 Issue
Januar
1996 Activities
Over looked procedure
steps result in
in an incorrect flowpath.
Detector calibration stickers
had incorrect calibration dates.
Questions
on whether or not
radiation meters energized/operating.
Technician's
local procedure
did not
match remote (operation's)
procedure.
No requirement within instruction to
secure
PASS line-up after sample.
No procedure
steps
were missed
and
the flowpath selected
was correct.
Labeling was noted
as correct.
Indicators functioned
as designed.
Local procedure
was identical to
the remote procedure.
TI-331 called for correct alignment
and technicians
returned line-up to
"as found" condition.
Insufficient questioning attitude
on the part of the workers involved
in the activity.
An adequate
questioning attitude
was
observed
by the inspector.
The sample
was subsequently
analyzed;
however,
due to an apparent
check valve problem,
(See
paragraph
3. 1 of this report).
High oxygen
levels were detected
and the sample results
were unsatisfactory.
On
January
26,
1996,
using procedure
TI-331, another
sample
was collected
and analyzed.
and satisfactory results
were obtained.
The inspector
concluded that
PASS procedure,
3-TI-331, while adequate for
obtaining/analyzing
gas
samples,
could
be improved.
The technicians
and
job foreman
appeared
knowledgeable with procedure
contents
and
methodologies for obtaining samples
and the inspector
found these
activities to be satisfactory.
5.4
RADIOLOGICAL CONTROLS;
REQUIRED POSTINGS
UNITS 1,
2 AND 3
On January
29,
1996,
an inspector,
during routine plant walkdowns,
examined various field postings for their compliance with BFN procedure
RCI-1. I, Standardized
Radiological
Postings,
BFN procedure
RCI-17.,
Control of High Radiation Areas
and Very High Radiation Areas,
and
Vt'N,
10 CFR 20 requirements.
The inspector noted the following:
Unit 2, East
RHR Heat Exchanger
Bay - A "High Radiological
Area"
sign is posted;
however,
the posting did not display probable
area
dose rates.
Unit 2, Pressure
Suppression
Chamber Water Tank Area
Same
comments
as East
RHR Heat Exchanger
Bay.
Unit 2,
East
and West scram discharge
volume cage
areas
and
walkways
A "Radiation Area" sign is posted:
however,
the posting
did not address
probable
area
dose rates.
Units 1,
2 and
3 Refueling Floor - Some areas of the refueling
floor, which clearly contain radioactive material,
are marked
"Radiological Area"; i.e.,
area
around
Vessel
Head Lifting Device
and storage barrels located at the Unit
1 end of the refuel floor.
However., similar areas; i.e., the Unit
1 pit area which contains
radioactive material, is simply marked "Radioactive Material
Area".
The inspector
found that the plant postings
were in compliance with
guidance
contained within the licensee
procedures
and
Overall, plant radiological .postings
are adequate
and meet regulatory
requirements.
No violations or deviations
were identified.
6.0
Review of UFSAR Commitments
A recent discovery of a licensee
operating their facility in a manner
contrary to the Updated Final Safety Analysis Report
(UFSAR) description
highlighted the need for a special
focused review that compares
plant
practices,
procedures
and/or parameters
to the
UFSAR descriptions.
During
a portion of the inspection period (February 1-3,
1996) the
inspectors
reviewed the applicable sections of the
UFSAR that related to
the inspection
areas
discussed
in this report.
7.0
EXIT
The inspection
scope
and findings were summarized
on February
2,
1996,
by L. Wert with those
persons
indicated in paragraph l.
Interim exits-
were conducted
on January
12,
1996 and February
1,
1996.
The inspectors
described
the areas
inspected
and discussed
in detail the inspection
results.
A listing of inspection findings is provided.
During one of
the interim exits,
the issue involving the
STAR Program
was discussed
with senior plant management,
and the inspectors
were informed that when
the
STAR Program
was initially started
at Browns Ferry, strong
emphasis
was stressed
on its use.
However, since that time the emphasis
has not
been stressed
as effectively as it could have been.
Proprietary
<0
25
information is not contained
in this report.
Dissenting
comments
were
not received
from the licensee.
Item Number
VIO 296/96-01-01
Status
Open
Descri tion and Reference
Core Thermal
Power Above
Licensed Condition Maximum,
paragraph
2.2
URI 260/96-01-02
Open
Drywell
CAM Setpoint
Determination
Method,
paragraph
4.3
VIO 260/94-24-02
Closed
Failure To Follow Procedures,
paragraph
2.6.1
. VIO 259,
260, 296/94-17-01
Closed
Instrument
Cal ibrati on
Deficiencies,
paragraph
3.5. 1
VIO 260/94-01;06
Closed
Appendix
R Design Errors,
paragraph
4.4. 1
THI 296/II.F-.2.4
Cl osed
Instrumentation for Detection
of Inadequate
Core Cooling,
paragraph
4.4.2
8.0
ACRONYHS
ASOS
CFR
CR
DCN
FHE
IR
HWe
HWt
NA&L
NRC
As Low As Reasonably
Ach'ievable
Assistant .Shift Operations
Supervisor
Browns Ferry Nuclear Plant
Boiling Water Reactor
Continuous Air Monitor
Code of Federal
Regulations
Control
Room
Design
Change Notice
Emergency
Core Cooling System
Emergency Diesel
Generator
Final Safety Analysis Report
General
Electric
High Pressure
Coolant Injection
Institute for Nuclear
Power Operations
Individual Plant Evaluation
Inspection
Report
Junction
Box
Megawatts-Electrical
Megawatts-Thermal
Nuclear Assurance
and Licensing
Nuclear Regulatory
Commission
VN'<lf
PDR:
PER
'PMT
R/hr
RHR'HRSW
SF.P
'SOS
T,I
TS'VA.
UNID
V,IO
Post Accident Sampling System
Public Document
Room
Problem~Evaluation
Report
Preventive .Maintenance
Post Modification Testing
REM per hour
.Reactor
Core Isolation Cooling
Residual
Heat
Removal.
Residual
Heat. Removal Service Water
Reactor 'Water
Cleanup
Standby
Gas Treatment
Spent
Fuel
Pool'urveillance Instruction
Safety
Parameter.
Display System
Shift Operation. Supervisor
Site Standard
Practices
Stop, Think, Act, and Review
Technical
Instruction
Technical Specifications
Valley Authority
Unique Equipment Identification
Unresolved
Item
Violation .
Work Order
cN