ML18038B944
| ML18038B944 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 08/29/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18038B942 | List: |
| References | |
| 50-259-97-08, 50-259-97-8, 50-260-97-08, 50-260-97-8, 50-296-97-08, 50-296-97-8, NUDOCS 9709040346 | |
| Download: ML18038B944 (94) | |
See also: IR 05000259/1997008
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
License
Nos:
50-259.
50-260,
50-296
'Repor t Nos:
50-259/97-08.
50-260/97-08.
50-296/97-08
Licensee:
Valley Authority
Facility:
Browns Ferry Nuclear Plant, Units l. 2,
& 3
Location:
Corner of Shaw and Browns Ferry Roads
Athens.
35611
Dates:
June
22 - August 2,
1997
Inspectors:
L. Wert, Senior Resident
Inspector
J. Starefos,
Resident
Inspector
C. Smith,
Reactor
Inspector
(Sections
E2.4,
E2.5.
and E8.5)
Approved by:
H. Lesser,
Chief
Reactor
Projects
Branch
6
Division of Reactor Projects
9709040346
970829
ADQCK 0500025'P
6
P,DR
Enclosure
2
0
il
EXECUTIVE SUMMARY
Browns Ferry Nuclear Plant, Units 1, 2,
8 3
NRC Inspection Report 50-259/97-08.
50-260/97-08,
50-296/97-08
This integrated
inspection included aspects
of licensee operations,
engineering.
maintenance,
and plant support.
The report covers
a six-week
period of resident inspection
and inspection in the engineering
area
by a
Region II reactor inspector.
Operations
management
promptly addressed
a power supply problem associated
with Anticipated Transient Without a Scram logic. Repairs
were completed in a
timely manner
and with effective Operations controls.
(Section 01. 1)
Control
room operators
demonstrated
an increased sensitivity to compensatory
actions for inoperable
equipment or instrumentation.
The actions were
conservative
and completed at reasonable
intervals.
(Section 01.2)
Housekeeping
deficiencies
were identified in the Unit 3 shutdown board
room
chiller rooms
and
a ventilation tower.
Overall conditions in the Unit 2
Reactor
Building were improved.
In the plant stack.
conditions were
satisfactory
and the radiation monitoring system
was aligned
as required.
(Section 02.1)
Monitoring of identified leakage
problems did not identify improperly rigged
catch devices or devices
which were not properly sized to capture
leakage.
While the overall status of temporary leakage
containment
devices
was
acceptable,
several of the devices
were not effectively capturing the leakage.
(Section 02.1)
The overall performance of the workers during Standby
Gas Treatment
System
testing
was good.
Workers were attentive to details of the testing
and good
0
procedural
compliance
was observed.
The maintenance
workers coordinated their
efforts with Operations.
The inspector identified that the surveillance
instruction did not fully address
orientation of the hot wire anemometer
sensor
probe during air flow measurements.
(Section Hl.l)
The Unit 2 High Pressure
Coolant Injection system
was affected by steam
admission valve leakage
condensate
entering
a junction box through an unsealed
conduit.
Surveillance testing indicated that the system
was capable of
performing its safety f'unction in the automatic
mode.
The valve steam leakage
problems
were known by the licensee
and had existed prior to the most recent
refueling outage.
The licensee's
detailed evaluation
focused
on effects of
valve seat
leakage.
The potential effects
due to external
leakage
were not as
fully evaluated.
The licensee's
actions,
including questioning of system
performance during the surveillance testing,
troubleshooting
and immediate
repair activities.
and planned future corrective actions were good.
(Non-
Cited Violation 50-260,296/97-07-03.
Failure to Identify Water Intrusion Into
High Pressure
Coolant Injection System Junction
Box. Section
E2. 1)
The inspectors identified that two steam packing exhauster line stack
isolation dampers
had been positioned differently than configuration control
drawings for approximately
one year to address
an equipment performance
issue.
The inspectors
did not identify any immediate safety concerns with the
equipment aligned in accordance
with the engineer's
instructions
and the
caution tag.
However, actions
had not been initiated to address
permanent
resolution of the problem.
(Section E2.2)
Weaknesses
iq the licensee's
lubrication oil analysis
program permitted'he
incorrect type of lubricating oil to be added to a second
'EDG several
months
after it had been installed in a different
EDG.
(Unresolved
Item 50-260/97-08-
02, Incorrect Oil.Used in Two EDGs, Section E2.3)
An error in the Haterials/Procurement
processes
resulted in workers procuring
the incorrect oil for addition to the
EDGs.
Similar examples of procurement
weaknesses
have, been identified previously.
The licensee
has initiated an
extensive Materials Upgrade Project to address
the issues.
(Inspection
Followup Item 50-260,296/97-08-05.
Materials Upgrade Project. Section
E2.3)
The licensee's
design control program was being implemented in accordance
with
the requirements
(Section E2.4)
45
One violation was identified for failing to perform
a
10 CFR 50.59 Safety
Evaluation for a change to the
FSAR that permitted
a new system alignment that
previously had been prohibited by the licensing basis.
The deficiency
apparently involved misapplication of "S"
DCN which cannot
be used for making
system alignment changes.
Secondary
cause
was complex design control process
which uses
numerous
alphabet
designated
DCNs with unique administrative
controls.
(Violation 50-260/97-08-01,
Failure to perform a
10 CFR 50.59 Safety
Evaluation for New System Alignment, Section E2.4)
Technical Operability Evaluations
were technically adequate.
(Section
EZ.5)
Procurement
issues
involving Ellis and Watts
(Shutdown
Board
Room Chillers)
commercial dedication plans were adequately dispositioned for release of
material.
(Section E8.5)
The inspector
concluded that the licensee's
overall investigative
and
corrective actions regarding
a series of Emergency
Core Cooling System
inverter failures were effective.
The inverters continue to be monitored by
the licensee
as
an a(1) system in accordance
with the maintenance
rule.
The
failures
and corrective actions were well documented
in the licensee's
corrective action system.
(Section
E8. 1)
During observation of a compensatory
raw cooling water sampling activity
required by the Offsite Dose Calculation Hanual.
two deficiencies
were noted.
The worker did not fully comply with the sampling procedure.
The safety
significance of the specific deficiencies
was small since the overall intent
of the steps
was met.
Additionally, the Chemistry Shift Supervisor indicated
to the inspector that he was not aware of how the Lower Limit of Detection
acceptance criteria was met.
(Non-Cited Violation 259/97-08-04,
Failure to
Follow Chemistry Sampling Procedure.
Section
R4. 1)
0
0
4l
Unit 1 remained in a long-term lay-up condition with the reactor defueled.
Units 2 and 3 operated at or near full power with the exception of routine
testing
and scheduled
maintenance
Mhile performing the inspections
discussed
in this report, the inspectors
reviewed the applicable portions of the Updated Final Safety Analysis Report
(UFSAR) that related to most of the areas
inspected.
Section
E8.2 describes
a
minor UFSAR discrepancy identified during the reviews.
NRC review also
identified that
a safety assessment
contained
an incor rect statement.
(Section
E2. 1)
~
t
01
Conduct of Operations
01.1
The inspector
reviewed actions taken when Unit 3 experienced
a loss of
power to anticipated transient without a scram
(ATMS) B logic power.
The inspector
reviewed the licensee's
plan to repair the breaker.
observed
some of the repair activities,
reviewed the clearance,
and
observed
a portion of the equipment restoration.
On June 21,
1997, Unit 3 experienced
a loss of power to anticipated
(ATWS) 8 logic power.
The licensee
determined
that the power interruption was caused
by a contact problem with normal
supply breaker
3-FUDS-248-3EBQ on the
3EB 250V
DC distribution panel.
The licensee cycled the breaker
several
times and verified that power
was restored to the
ATWS 8 logic panel.
Several
hours later, the
licensee transferred
ATMS 8 logic power to the alternate
power supply.
The licensee
performed shiftly voltage readings
on the normal supply to
0
ATWS B.
The inspectors
considered this to be an example of increased
sensitivity to compensatory
actions
by Operations
as discussed
in
Section 01.2.
On June 26,
1997, the licensee
removed the
3EB 250V
DC distribution
panel
from service to replace the 3-FUDS-248-3EBQ breaker.
The licensee
removed
a spare breaker
from another
part of the distribution panel
and
replaced the 3-FUDS-248-3EBQ breaker in accordance
with work order 97-
006508-000.
To remove the
3EB 250V
DC distribution panel
from service
for the breaker
replacement.
the licensee transferred
the 3EB 4160V
shutdown board control
power to.its alternate
supply, disconnected
the
3EB battery from the panel,
and disconnected
the
3EB battery charger
from the panel.
The ATMS B logic power was already transferred to its
alternate
power supply.
Technical Specification (TS) 3.9.B.6 requires
the licensee to notify the
NRC within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of the time that the 250V
shutdown board
3EB battery and/or its associated
battery board is found
to be inoperable for any reason;
continued reactor
operation is
permissible during the succeeding
seven
days.
The licensee
reported the
removal of the 250V shutdown board
3EB and the distribution panel
from
service
as required by TS 3.9.8.6.
The inspector
reviewed clearance
3-97-0507, verified that tags were hung
on equipment in the field. and that the equipment
was in its designated
clearance
position.
No concerns
were identified.
Following the breaker
replacement,
the licensee identified a problem with the physical
interlocks which keep the'panel
door closed
when the breaker is closed.
During troubleshooting
work, the inspector noted that
a number of the
breakers within the clearance
boundary were manipulated.
The inspector
discussed this with the tagging
SRO and
a component verification sheet
was prepared f'r designated
breakers
on the panel.
Operations
management
promptly informed the resident inspectors of the
problem with the normal..supply breaker
and their plan to effect repairs.
The repairs were completed in a timely manner
and with effective
Operations controls.
One of'he inspectors
observed Assistant Unit Operators
(AUOs) in the
diesel
generator
room during surveillance instruction (SI)
3-SI-4.9.A. l.a(3B), Diesel Generator
3B Monthly Operability Test.
The inspectors
reviewed the compensatory
actions initiated by the
control
room personnel
for inoperable instrumentation or equipment.
The inspectors verified that proper actions
were completed
when
important electrical
equipment
was placed in an alternate
alignment.
On July 20,
1997, the inspector observed
performance of surveillance
instruction 3-SI-4.9.A.l.a(3B), Diesel Generator
3B Monthly Operability
Test,
Revision 28.
The inspector attended
the pre-job briefing prior to
the test
and noted that the workers were told to ensure that they were
on the right component.
Discussion with the
AUO regarding draining
condensate
from the fuel oil day tank indicated that the
AUO was
knowledgeable of how to properly perform the activity.
The AUO
demonstrated
the technique to verify that the control cabinet
f'an was
operating.
In general,
observed
AUO performance
was good.
The inspector noted that several
steps of a section of the procedure
were performed before the preceding step
was signed off.
The inspector
observed that the procedure
steps
were being completed in order and that
the oversight
was administrative.
As discussed
in Inspection
Report
50-259,260,296/97-07,
similar practices
have
been previously noted
and
licensee
management
is reviewing the guidance currently set forth in
SSP-2.1,
Site Procedures
Program for signing off steps of continuous
use
procedures.
Over the last several
months.
the inspectors
have noted
an increased
sensitivity toward implementing compensatory
actions for plant equipment
problems.
Examples
included monitoring of 3B drywell control air
compressor
oil level due to 3A drywell control air compressor
being out
of service,
generator
PCB 234 cooling water conductivity monitored due
to annunciator disabled,
south emergency
equipment cooling water header
pressure
monitored due to a pressure transmitter being inoperable,
and
Unit 2 recombiner
room temperature
monitored
due to annunciator
alarm
0
il
disabled.
In general.
the control
room operators
exhibited more
sensitivity towards
compensatory
actions than was observed
during
previous inspections.
The inspectors
reviewed
an evolution in which control
room operators
were required to calculate transformer loading and observe
unusual
restrictions in an off-normal electrical switchgear alignment.
A
related potential .concern regarding this is discussed
in Section
E2.5 of
this report..
On July 24,
1997. the
2B 480
V Shutdown
Board was placed
on its "alternate" supply to support transformer work.
This invoked
several
special
operating restrictions
and necessitated
calculation of
loading by the operators.
The inspectors
reviewed the applicable plant
drawings
and instructions to determine the appropriate actions.
The
inspector verified that the restrictions
had been
met and that the
operators
performed the calculations correctly.
Two SROs in the Unit 2
control
room were able to explain the loading calculations
and had
performed
them correctly.
The inspectors
concluded that the
calculations
were not unreasonably difficult for the operators to
perform.
The work and the methods to meet the alignment restrictions
were planned through Maintenance
and Engineering
and set forth in a
detailed "fragnet" before the board alignment
was revised.
General
observations
during the report period were positive.
Control
room. operators
demonstrated
an increased sensitivity to compensatory
actions
when equipment or instruments
were inoperable.
Operators
successfully
performed calculations to meet special
operating
restrictions
due to an off-normal electrical switch gear
alignment.
02
Operational
Status of Facilities and Equipment
02.1
1
In addition to routine plant tours, the inspectors
reviewed installed
temporary leakage
containment
devices
and performed
a detailed tour of
the plant stack.
The stack tour specifically focused
on dilution
fans/dampers
and the stack radiation monitoring system.
il
0
On July 23, the inspectors
walked down the plant stack,
focusing on
operability of the dilution fans/dampers
and the stack effluent
radiation monitoring equipment.
Valves were positioned
as described
on controlled drawings with one
exception.
Section
E2. 1 of this report describes
review of a steam
packing exhauster
bypass line damper which had been caution tagged shut
since August 1996.
Several
valves were locked in position which the
Mechanical
Control drawing did not specifically require to be locked.
The inspectors
confirmed that the valves were appropriately listed in
the Operating Instructions.
Although some areas
.had large quantities of
insects
present,
overall housekeeping
conditions in the stack were
acceptable.
Material was properly stored with no excessive
accumulation
of equipment.
The radiation monitoring system
was aligned
as required
and appeared to be functioning properly.
The inspector noted that valve 2-65-513 (isolation valve in dilution
line to Standby
Gas Treatment
system header)
was incorrectly listed on
drawing 2-47E610-66-1
R024 as 3-65-513.
The licensee initiated
a
Problem Evaluation Report
(PER) to address this issue.
Early in the inspection period. the inspector.
noted poor housekeeping
conditions in the Unit 3 shutdown board chiller rooms.
The conditions
were corrected later in the inspection report period but the floor
drains in the rooms remained
clogged.
The inspectors
also noted
a pile
of high efficiency particulate filters in one of the vent towers above
the control building.
The filters were subsequently
removed from the
tower.
On July 16,, 1997,
one of the inspectors
examined
a sampling of
identified leaks
and leakage
containment
devices throughout the plant.
Condensation
from an identified steam packing leak on the Unit 2 High
Pressure
Coolant Injection (HPCI) system leaked into a junction box and
affected the HPCI control system (Section
E2. 1).
At the time, the
licensee
was tracking 27 non-contaminated
and 34 contaminated
temporary
'eakage
containment
devices.
The inspector
reviewed
14 of the non-
contaminated
leakage
devices.
Only one deficiency was noted.
Device
number 25, associated
with a recirculation
pump oil system leak,
was not
capturing all of the leaking oil and oil was running down adjacent
structural material.
The inspector
reviewed
16 of the 34 leakage
containment
devices for contaminated
systems.
Problems were noted with
II
five of the temporary devices.
Several
devices
were not effectively
capturing the leakage
due to undersized
devices
or not properly rigged
devices.
Plant management
was informed of the observations.
Subsequently,
the inspectors
noted that the observed
problems
had been
corrected.
The licensee tracks temporary leakage
containment
devices
and an updated list is reviewed each
week at the Plan of the Day
meeting.
The licensee
does not have
a formal process
which would ensure
specific regular or periodic review of the installed devices.
The
licensee relies
on routine Operations tours or system engineer
observations
to monitor identified leakage
problems.
Housekeeping
deficiencies
were identified in the Unit 3 shutdown board
room chiller rooms and
a vent tower.
With the exception of chiller room
floor drain blockage,
those issues
were corrected during the inspection
period.
In the plant stack, material
was properly stored
and there was
not an excessive quantity of stored equipment.
The radiation monitoring
system
was aligned
as required
and appeared to be functioning properly.
Licensee monitoring of identified leakage
problems did not identify
improperly rigged catch devices or devices which were not properly sized
to capture
leakage.
While the overall status of temporary
leakage
containment devices
was acceptable,
several of the devices
were not
effectively capturing the leakage.
08
Hiscellaneous
Operations
Issues
(92901)
08.1
l
, Core Thermal
Power
Exceeded
Operating License's
Haximum Power Level
Due to a Drifting
Temperature Transmitter.
Violation 296/96-01-01,
Core Thermal
Power
Above Licensed Condition Haximum. also addressed
this issue.
The
licensee's
corrective actions
were reviewed
and the violation was closed
in Inspection Report (IR) 96-04.
The IR noted that the licensee
completed several. corrective actions which were not listed in the
response
to the Notice of Violation.
The inspectors
continue to observe
that the Unit Operators
are informing the Unit Senior Reactor Operator
of recirculation flow changes.
The
LER is closed.
08.2
V
- 4-, Fire Protection
Program Equipment
Inoperable Without Compensatory Actions.
This violation addressed
two
examples in which required compensatory
actions
were not initiated for
inoperable fire protection program
equipment.
An improper clearance
il
rendered
a reactor building preaction sprinkler valve inoperable
and an
inoperable battery charger switch was not recognized
as fire protection
equipment.
The licensee
has strengthened
the processes
used to develop
and review clearances
since this event
and no similar incidents
have
occurred.
The second deficiency occurred
due to a vendor wiring error
in the control panel for.'the battery charger.
Since
1986, the licensee
has
had procedural
requirements
for wiring verification of new vendor
wired electrical
equipment.
No additional
examples of such problems
have been noted.
NRC checks of fire protection program compensatory
measures
have not identified any problems in recent
months.
Hl
Conduct of Haintenance
Hl.l
Utilizing -the guidance of Inspection
Procedure
61726, the inspector
obser ved major portions of five surveillance tests
conducted
on the "C"
train of SBGT.
0-SI-4.7.8.1. 8-3
O-SI-4.7.8.3-3
O-SI-4.7.8.1.A-3
O-SI-4.7.8.7
O-SI-4.7.8.8
"C" SBGT Humidity Control Heater Test
"C" SBGT Flow Distribution Test
"C" SBGT Filter Pressure
Drop Test
"C" SBGT Flow Rate Test
Seal
F
During the per iod of July 9-11.
1997, the inspector observed testing of
the
SBGT system
as required by technical specifications
(TS).
In
preparation,
the inspector
reviewed controlled drawings
and
descriptions of the system.
walked down portions of the
SBGT system,
and
reviewed operating
and testing procedures.
The inspector
observed that the humidity heater
control testing
was well
controlled, with close utilization of the procedure.
The inspector
observed that torquing of'he dyoctlphosphate test port flanges
was
performed properly with Quality Control involvement
as required
by the
procedure.
The inspector noted that mechanical
maintenance
workers coordinated with
Operations to obtain .permission to begin testing
and ensure that the
prerequisites
were met f'r the other four tests.
The workers were also
diligent regarding signing off the initial steps in the procedure
as
they were completed.
The workers
had marked the pitot tube and the hot
wire anemometer
tube with tape to expedite traverse point measurements.
During the
SBGT flow rate test,
two 20 point pitot tube traverses
were
obtained
from SBGT piping located in the plant stack.
The inspector
observed that the workers attempted to be accurate
and consistent
regarding
manometer
data.
The inspector
recorded
manometer
readings
and
performed the calculations of SBGT train flow independent of the
workers.
The inspector obtained flowrate values very close to the values
the workers obtained
and well within the acceptance criteria.
The uniformity of air distribution across
the High Efficiency
Particulate Air (HEPA) filters and charcoal
adsorbers
is required to be
checked
by TS 4.7.B.l.c.
Procedure
O-SI-4.7.B.3-3,
"C" SBGT Flow
Distribution Test, is used to perform this testing.
A hot wire
anemometer
is utilized to obtain
a nine point velocity profile on the
upstream
HEPA filter.
During the testing,
the inspector
observed that
rotation of the probe with respect to air flow affected the readings
obtained.
At one point,
an initial reading
was lower than the expected
value.
After obtaining the other two points in that column, the workers
'obtained
another
reading at the first point which was close to the other
two point values.
By referring to a piece'f tape
on the probe tube
extension,
the inspector noted that the orientation of the tube had been
changed
between the readings.
At the inspector's
request.
the workers
rotated the probe ninety degrees
at another point and it was confirmed
that the orientation of the probe affected the readings.
Although some
discussion
was held on the orientation of the probe, the workers did not
indicate that they. were aware of the significance of probe orientation.
Subsequently.
the inspector
reviewed the instruction manual
supplied by
the instrument vendor.
The manual stated that
a red dot painted
on the
-
end of the probe was to be toward the air flow to obtain valid readings
The inspector confirmed that there
was
a red dot on the probe
as
specified.
Discussions with maintenance training personnel
indicated
that the probe orientation was briefly addressed
during training
sessions
with the workers.
The inspector noted that the probe only
extends to 21 inches
and. the workers have to attach the probe to an
extension tube to extend it far enough into the train.
This increases
the difficulty in ensuring that the, probe is, oriented properly.
These
observations
were reported to plant management.
0
The licensee
subsequently
concluded that the performed SI was
acceptable.
However, the test procedure
was revised to require that the
maximum indicated flowrate (as the probe. is rotated)
be recorded at each
measurement
point.
The inspector concluded that this would provide
a
more accurate
assessment
of flow distribution within the train.
Additionally. the plant manager
informed the inspector that his
investigation indicated that the workers were aware of the significance
of probe orientation but had apparently not communicated their knowledge
to the inspector.
The inspectors
concluded that the licensee's
revision
to the procedure
adequately
addressed
the issue
and strengthened
instructions. to the workers regarding air flow measurements.
The
inspectors
did not identify reasonable
conditions where improper
probe
orientation would have failed to identify inadequate
air flows.
The SBGT Filter Drop Test and Housing Door Gasket
Seal Test were
completed satisfactorily
and results
were .within acceptance criteria.
During reviews of the SBGT system,
the inspector identified that the
Unit 3 control
room mimic had manual
bypass
decay heat line damper
DMP-
65-02 labeled
as
DMP-65-21.
This was reported to Operations
management.
The inspector subsequently verified that the control
room mimic was
corrected.
The overal,l performance of the workers during the testing
was good.
Workers were attentive to details of the testing
and good procedural
compliance
was observed.
The maintenance
workers coordinated their
efforts with Operations.
The inspector identified that the surveillance
instruction did not fully address orientation of the hot wire anemometer
sensor
probe during air flow measurements.
One minor deficiency
involving a control
room mimic display was noted.
The inspector
obser ved the performance of Surveillance Instruction
2-SI-4.1.A-8(F),
RPS High Water Level in Scram Discharge
Tank Functional
Test 2-LS-85-45E and 2-LS-85-45F,
Revision 12.
0
il
On July 8.
1997, the inspector
observed the performance of Surveillance
Instruction 2-SI-4. 1.A-8(F),
RPS High Water Level in Scram Discharge
Tank Functional Test 2-LS-85-45E
and 2-LS-85-45F,
Revision 12.
The
inspector observed portions of the SI from the cage
area
around the east
scram discharge tanks,
from the control
room,
and from the Unit 2
auxiliary instrument
room.
The individuals performing valve
manipulations in the field exercised clear communications
and verified
the correct components
before manipulation.
Second party verification
and independent verification was adequate.
During the performance of the testing,
the inspector
noted that the
individuals performing the test were careful to control
a test valve by
attaching it to the area
cage.
During previous testing,
water had
leaked by the valve causing
a half-scram (IR 97-01, Section M4.1).
In
addition, the inspector noted that the licensee
enhanced
the SI
procedure
by adding
a step to close the demineralized
water source
connection valve which provides
a second isolation between the manometer
and the water supply.
M8
Miscellaneous
Maintenance
Issues
(62707,
92902)
M8.1
, Failure to Follow Procedures
During
Core Spray Valve Maintenance.
NRC inspectors identified that
maintenance
workers were not signing off completion of steps
as the work
was completed.
Plant management
has continued to emphasize
%hat
procedural
steps
are to be completed
and,
when required,
signed
as the
steps
are completed.
Recently. the inspectors
have noted that
"continuous
use" procedures
are being revised to support step completion
documentation at appropriate locations in the procedure.
The inspectors
have noted overall
improvement in maintenance
workers signing off
prerequisites
or major steps
as they are completed.
However,
some
procedures
are not written in a, manner to support rigid step-by-step
signoffs.
Section Ml.1 of Inspection Report 97-07 describes
NRC
observation of Common Accident Signal. Testing in which workers completed
small groups of steps
before stopping to sign steps.
The steps
were
performed correctly and in sequence.
The inspectors
have observed
plant management
discuss
the issue of completion signoffs in Management
Review Committee meetings.
Procedures
are being revised
as
enhancement
areas
are identified.
Section Ml. 1 of this report describes
testing
observations
in which it was noted that the workers were sensitive to
sequential
step completion.
The violation is closed.
Cl
0
M8;2
. Licensee Identified Appendix
R
Deficiencies.
This violation addressed
several
Appendix
R issues
identified during extensive re-analysis of the Unit 2 safe
shutdown
program.
The Notice of Violation stated that no response to the
violation was required since the licensee
had adequately
addressed
the
issues
in Licensee
Event Report
(L'ER) 260/96-001.
Revision I of the
LER
was closed in IR 96-08.
The licensee thoroughly reviewed each of the
deficiencies
and concluded that no consistent
trend or methodology
problems were involved.
The inspector
reviewed documentation
which
indicated that modification F39514A had been completed which re-routed
several
instrumentation
cables to correct the problems.
The other
corrective actions in the
LER were completed
as well.
The violation is
closed.
M8.3
,
Appendix
R Noncompliance Results in the Plant Being Outside Its Design
Basis
and Being in a Condition Not Covered
by Plant Operating
Instructions.
Section
M8.2 describes
review of a violation which
addressed
the issues
in the
LER.
Revision
1 of the
LER was closed in IR
96-08.
Due to an administrative oversight,
Revision
0 was not closed at
that time.
The
LER is closed.
M8.4
, Toolpouch
Issues.
This URI contained
two central
issues.
The first issue
was
adequacy of the toolpouch maintenance
process for work on the emergency
diesel
generators
(EDGs).
The second
issue involved weaknesses
in the
procurement
processes
which could have allowed improper material
(glycol) to be added to the
EDGs.
The licensee
completed
an evaluation of whether the Toolpouch
Maintenance, process
was appropriate
for adding demineralized
water to
the emergency diesel
generators
cooling systems.
The licensee
determined that the toolpouch criteria and examples,
described in site
standard practice
(SSP)
procedure
SSP-6.2
(Maintenance
Management
System)
Appendix T (Implementing Toolpouch Maintenance),
could not be
used effectively to determine toolpouch maintenance
items.
Problem
Evaluation Report
(PER)
BFPER961761
addressed
this issue with an update
to procedure
SSP-6.2 Appendix T.
Craft supervisors,
foremen,
and
maintenance
planners
were briefed on the revised procedure
appendix.
The inspector
reviewed SSP-6.2 Appendix T, Revision 26.
and concluded
that the procedure .would currently not allow demineralized water
-addition to the emergency diesel
generators
cooling systems
using the
Toolpouch Maintenance
Process.
Due to another
problem that occurred involving the
EDG coolant expansion
tank, the licensee
developed
an operations
plant information posting
(PIP-97-179)
and installed it at each diesel
informing personnel
to
contact chemistry for any additions,
sampling,
or chemistry concerns.
Based
upon the licensee's
actions to clarify the procedure
for Toolpouch
Maintenance,
to inform responsible
individuals of the changes,
and
installing Plant Information Postings at each diesel.
the inspector
concluded that this portion of the Unresolved
Item is closed.
No
violation of regulatory requirements
was identified.
0
The second part of the URI identified the potential for ethylene glycol
to be issued
by TVA Power Stores for use in the Emergency Diesel
Generators.
(EDGs) despite the fact that Site Standard
Practice
SSP-13. 1,
Chemistry Program,
does not consider ethylene glycol as acceptable for
use in the
EDGs.
This portion of Unresolved
Item 50-259,260.296/96-13-
02 will be addressed
by Inspection Followup Item (IFI) 50-260.296/97-08-
05, Materials Upgrade Project.
This IFI is addressed
in more detail in
Section
E2.2 of this report.
Unresolved
Item 50-259,260,296/96-13-02,
Toolpouch Issues is closed.
E2
Engineering Support of Facilities and Equipment
E2.1,
Condensation
from a steam leak on the Unit 2 High Pressure
Coolant
Injection (HPCI) system
steam admission valve entered
an electrical
junction box and affected the HPCI system.
The inspectors
monitored the
licensee's
efforts to troubleshoot
and correct the problem.
The
inspectors
reviewed the licensee's
controls regarding junction box
0
sealing.
The inspectors
reviewed electrical wiring and
HPCI control
system drawings
as well as test data to verify the impact of the water
intrusion on the
HPCI system.
On July 11,
1997, during the performance of surveillance
instruction
(SI) 2-SI-4.5.E.l.d,
HPCI fHigh Pressure
Coolant Injectionj Flow Rate
Test at Normal
RPV fReactor
Pressure
Vesselj Pressure,
the HPCI system
did not meet the SI requirements
while the system
was in manual
mode.
The testing indicated
an acceptable
flow (5050 gpm). at
a discharge
pressure
capable of vessel
injection (1210 psig)..
The Unit 2 HPCI
system
was declared
inoperable f'r troubleshooting
and corrective
actions.
The licensee
reported the condition to the
NRC.
The
inspectors
observed portions of the troubleshooting activities and
monitored the licensee's
investigation into the cause of the problem.
Initial troubleshooting identified a problem with the speed indicator
card in the
EGN portion of the turbine governor.
The licensee
replaced
the speed indicator card and reperformed the surveillance test.
The
testing indicated similar results with a small
improvement in indicated
performance.
Erratic indications were noted when the speed control
on the
HPCI speed controller was touched,
indicating
ground problems.
The licensee
was concerned that the ground on the
speed controller may have
damaged
the speed indicator card,
so it was
replaced
a second time.
Additional troubleshooting identified that the
output of the speed control potentiometer
on the HPCI speed controller
was erratic.
After correcting the apparent
problems,
the licensee
ran
the SI again
and determined that the symptoms still existed.
Further
troubleshooting identified that
a ground existed in the circuit which
was traced to junction box 8272 on the HPCI skid.
Additional inspection indicated that water was leaking into junction box
8272.
This is
a junction box located adjacent to the
which contains
a terminal board
and electrical
connections.
On July 14.
1997,
one of the inspectors
observed the inspection
and repairs to the
junction box in accordance
with Mork Order 97-007072-000.
The inspector observed that water was entering the junction box and
essentially all the terminal points
on
a large terminal strip inside the
box were wet.
Corrosion was evident
on many of the connections.
The
inspector traced the source of the water
and determined that it was from
a packing leak on the 73-16 valve
(HPCI steam admission valve).
0
Condensed
steam
had accumulated
in insulation on piping. then dripped
out the other side of the insulation
on
a nearby pipe elbow and finally
dripped
on the top of the junction box.
.The water entered the box
through two unsea1ed
conduit connections
on the top of the box and ran
down the terminal strip.
The inspector noted that the leakage into the
box was difficult to observe.
There was not
a visible puddle
on top of
the box and the path of condensate
from the 73-16 steam
leakage to the
box was torturous (the steam
was not simply condensing
on
a nearby
surface
and dropping into the box).
The terminal strip was replaced,
the conduit connections
were sealed
with an approved sealant material,
and the 73-16 steam leak condensation
was routed to a drain.
The inspector
observed that the workers were
careful
about component verification prior to beginning work and
utilized procedures
to track configuration
as wi res were lifted and
reconnected.
The 73-16 internal
leakage
issues
had been identified on both Browns
Ferry units as early as
1994.
Engineering
has
been pursuing corrective
actions,
including a modification which would replace the valves, with
an improved design in a vertical orientation.
A management
decision
was
made to not replace the valve during the last refueling outage.
Technical Operability Evaluation
(TOE) 2-94-073-9014,
Unit 2 HPCI Steam
Admission Valve Leakage
Problems.
had been written to address
the
leakage
and related issues.
The
TOE has
been updated several
times
since the original version.
The current revision, Revision 4, is
a
highly detailed
assessment
of the degraded condition.
The Senior
Resident
Inspector
had reviewed the
TOE and discussed
the issues with
the
HPCI system engineer previously.
The
TOE thoroughly addressed
issues
associated
with leakage
past the seat of the valve.
The
TOE
addressed
external
leakage
impacts briefly from the perspective of room
temperature.
The inspectors
reviewed the licensee's
controls regarding sealing of
junction boxes
and concluded that there are two basic methods for
controlling the sealing of the boxes:
~
Drawing 0-45B891-1,
Coqduits
and Grounding Waterproofing
and
Sealing.
Details of Electrical
Equipment,
provides guidance
regarding sealing of junction boxes.
Note 2 of the drawing
states:
"Seal conduits
and boxes in the reactor building, control
bay,
pumping station,
and diesel
generator buildings in accordance
with notes
3 thru 9.
See Drawing 0-45E491-31
for list of junction
0
0
~f
boxes that are required to be sealed."
Junction
box 8272 is not
listed on drawing 0-45E491-31.
Note
1 on Drawing 0-45E491-31
states:
"Listed are the Unit 1,
2. and 3 and
common area
enclosures
which contain electrical
components that require
moisture protection.
Seal
these
boxes according to requirements
on. Drawing 45E891-1."
Terminal or connection
boards
are not
normally considered
as
components that would require sealing.
The
junction boxes that are required to be sealed contain
environmental qualification sensitive electrical
equipment.
~
Attachment
5 of Procedure
EII-O-OOO-TCC106, Troubleshooting
and
Configuration Control of Electrical
Equipment contains
guidance
for resealing of conduit boxes
opened during performance of'he
troubleshooting
procedure.
Page
2 of the attachment
contains
specific guidance for junction box sealing
and drainage hole
verification.
Page
1 contains
a note "per drawing 45B891."
As
described
above.
since
JB 8272 is not listed on the drawing,
these instructions would not result in the JB being sealed after
work was completed in the box.
The inspector
had observed that it is
a
common work practice at Browns
Ferry to thoroughly seal junction. boxes after work .activities are
completed, if the box was found sealed,
including some boxes not listed
on 45E491-31.
In most cases.
similar boxes
have conduits with
watertight threaded
conduit boss
hubs
or the connections
are sealed with
an approved sealant.
The inspectors
noted that the conduit connections
on the identical junction box on Unit 3 HPCI appeared to be sealed
but
no drainage hole is present.
The inspector
reviewed the history associated
with the licensee's
processes
for junction box and conduit sealing.
In August 1987, water
was introduced into the scram discharge
instrument
volume
instrumentation
through
an unsealed
conduit after an inadvertent fire
suppression
system actuation.
A Notice of Violation was issued in
Inspection
Report 87-33 on this issue.
Report
(CAQR)
BFN 870913 was initiated.
Initially, the licensee's
planned corrective actions included sealing of all junction boxes in the
intake structure,
control bay. reactor building.
and diesel
generator
building.
In an October
17,
1991. letter to the
NRC.
TVA revised the
commitment.
An evaluation of plant areas
subject to moisture intrusion
and required to support Unit 2 operations
was performed.
TVA identified
areas
where conduit and junction boxes could be subjected to
condensation
from moderate
and from open
16
head fixed water spray fire protection systems.
The list of junction
boxes to be sealed
was reduced.
The violation was closed out in
IR 91-16.
The inspectors
reviewed plant instructions,
design specifications,
and
drawings regarding the
HPCI room junction boxes.
The inspectors
concluded that the boxes are not required to be included
on the list of
junction boxes to be sealed:
~
Drawings 47W225-103
and -104 address
the harsh environmental
data
for the Unit 2 HPCI room.
(HELB)
profiles indicate that the HPCI room is not considered
a harsh
environment for any HELB scenarios
except for a line break in the
HPCI room itself.
Since
a
HELB in the HPCI room would involve the
HPCI steam piping. the HPCI system is not expected to perform in a
harsh environment.
The fire protection systems
in the Unit 2 and Unit 3 HPCI rooms
were converted to closed
head
systems prior to each unit restart.
In addition, to actuate the local spray device,
a heat detector
must actuate
a preaction valve to initiate water
spray to the
nozzles.
As such,
HPCI room junction boxes would no longer be
considered
as vulnerable to moisture intrusion from inadvertent
fire suppression
system actuation.
The inspector's
review also identified that Inspection Followup Item 84-
41-04 indicated that the licensee
had previously identified
a need to
relocate the HPCI
EGN control box.
Due to high moisture
and
temperatures,
the licensee
implemented
ECN P3184 which moved the
controls from adjacent to the
HPCI turbine (in JB 8272) to a location on
a
HPCI room wal.l.
.(Earlier work by General Electric had preliminari ly
indicated that the HPCI room would be
a harsh environment,
but this was
later revised).
The inspectors
reviewed portions of the
ECN package
and
did not identify any requi rements to seal. JB 8272 during the work.
the licensee stated that the HPCI system could
have performed its function (prior to being
removed from service f'r
repairs).
The inspectors
reviewed electrical
drawings
and test data
and
concluded that the information supported
a conclusion that the
system
was operable.
The observed
problems were due to the water
affecting the speed indication/control circuit which did not affect HPCI
as far as automatic startup
and injection.
The inspectors
noted that
the water and corroded terminations could have affected automatic
0
injection.
had this condition persisted,
since
some of'he wetted
terminations
are associated
with the
EGM control circuitry.
Appendix 8, Criterion XVI. requires that. measures
shall
be established
to assure that conditions adverse to quality. such
as failures.
malfunctions, deficiencies.
deviations,
defective material
and
equipment,
and nonconformances
are promptly identified and corrected.
In
this case,
Unit 2 High Pressure
Coolant Injection system controls were
affected
due to steam admission valve leakage
condensate
entering
a
junction box through unsealed
conduit.
The valve steam
leakage
problems
were
known by the licensee
and had existed prior to the most recent
refueling outage.
The licensee's
detailed evaluation
focused
on effects
of valve seat
leakage
and potential effects
due to external
leakage
were
not as fully evaluated.
Although several
factors
made it difficult to
see the leakage into the junction box, the degraded
condition was not
identified until after
HPCI was affected.
Conditions inside the
junction box indicated that water had been entering the box for several
months prior to identification.
Corrective actions include:
HPCI was declared
and after
some troubleshooting,
traced the cause to water entering the box.
The damaged terminal
strip was replaced.
the box was sealed.
Leakage containment
around the 73-16 valve was improved.
All installed. "leakage containment
devices"
(the devices
are
numbered
and tracked)
were examined to ensure that no other
similar problems existed.
Walkdowns of HPCI.
RCIC.
and feedwater
pump rooms where steam
condensate
could leak on junction boxes will be performed.
Conduit terminations would be sealed
on those
deemed to be
unacceptable.
Training modules will be developed to address this event
and
management
expectations
on reviewing aff'ects of plant leaks
and
the reporting of such leaks.
A Site Bulletin will be issued to heighten
awareness
of plant
personnel
to this event.
il
0
The inspectors. concluded that the licensee's
corrective actions
are
adequate.
The condition was identified by the licensee
as
a result of
questioning during the performance of surveillance
testing.
Although
available
information indicates that the
HPCI system could have
performed its intended safety function during the testing,
the condition
was adverse to quality and was not promptly identified.
This l.icensee-
identified and corrected violation is being treated
as
a Non-Cited
Violation (NCV), consistent with Section VII.B.1 of NRC Enforcement
Policy.
(NCV 50-260/97-07-01,
Failure to Identify Water Intrusion Into
High Pressure
Coolant Injection System Junction Box).
The Unit 2 High Pressure
Coolant Injection system
was affected
by steam
admission valve leakage
condensate
entering
a junction box through
unsealed
conduit penetrations.
The valve steam leakage
problems were
known by the licensee
and had existed prior to the most recent refueling
outage.
The licensee's
detailed evaluation
focused
on effects of valve
seat
leakage
and potential effects
due to external
leakage
were not as
fully evaluated.
The inspectors
concluded that three key issues
played
a role in the HPCI
control system being affected prior to identification of the problem.
Effects of longterm external
valve leakage
were not evaluated in a
sufficiently detailed
manner to identify the leakage into the junction
box. Identified long-standing valve leakage conditions were not
periodically evaluated
by means other than routine rounds.
Some
electrical junction boxes adjacent to steam operated
equipment
are not
sealed
against moisture intrusion.
The licensee's
actions.
including questioning of system performance
during the surveillance testing, troubleshooting
and immediate repair
activities,
and planned future corrective actions were good.
mP
During a tour of the plant stack
on July 23,
1997,
(Section 01.2) the
inspectors
noted that caution tag 0-96-0355-1
was present
on damper 0-
DMP-66-953A.
The tag had been installed in August 1996 and stated that
the damper
was to be shut.
Since the controlled drawings indicated that
~
i
0
the damper
was to be open
and the tag had been in place for almost
a
year, the inspectors
reviewed the damper position and caution tag issues
more closely.
Caution Tag 0-96-355-1 stated that 0-DMP-66-953A was to remain shut.
Two isolation dampers
(0-DMP-66-953A and 953B) are located in a pipe
from the steam packing exhaust to the stack
[Steam Packing Exhauster
(SPE)
bypass linej.
Two backdraft
are located between the
isolation dampers.
There is an. additional set of isolation dampers
and
backdraft
in parallel with this line.
The inspectors
noted that
Configuration Control Drawings 2-47E809-2
(Revision 21) and 2-47E610-66-
I indicated that the bypass isolation dampers
were to be open.
Note 11
on 2-47E809-2 stated that air flow was required to open the backdraft
dampers to prevent condensation
from forming water on the backdraft
After some review, the inspectors
determined that Design
Change Notice
(DCN) T35568A had been
implemented in September
1995 which
had revised the 953A and
953B normal positions to "open."
The
DCN
stated that the isolation dampers
were to remain open to prevent
moisture accumulation
on the backdraft dampers.
In the past,
condensation
of the
SPE steam
had accumulated
above the dampers
and
degraded
the dampers.
The caution order
0-96-0355 referenced
PER 960695
and Technical
Operability Evaluation
(TOE) 0-96-66-0695 which addressed
the problems
with the backdraft dampers.
The TOE specifically addressed
acceptability of the condition at the time of exceeding
10 standard
cubic feet per minute leakage
on the. backdraft
The
TOE was
closed in September
1996 after work was performed
on the dampers
and the
leakage rate was reduced.
Apparently, the caution tag was subsequently
issued to isolate the
SPE bypass,
forcing flow through the main
discharge line. to address
low flow conditions in the lines.
The
inspectors
did not find any open document directly relating to permanent
resolution of the problem which resulted .in the caution tag.
However,
Work Order 97-000712-000
was open which notes that the dampers
are shut
by the caution order and requests
an inspection of the backdraft
The inspectors
noted that the dampers
had remained positioned
differently than configuration control drawings for approximately
one
year.
0
20
The licensee
subsequently
completed
a 10CFR50.59 screening
review and
safety assessment
in accordance
with Site Standard
Practice
SSP-9.4
on
July 24,
1997..
The assessment
concluded. that the alignment was
acceptable
from a nuclear safety viewpoint and did not represent
a
unreviewed safety question.
Work Order 97-000712-000
was rescheduled
to
an earlier date to perform inspections of the backdraft
During a subsequent
review, the inspectors
noted that the safety
assessment
included
an incorrect statement.
The assessment
stated that
the situation did not represent
a change to the facility as described
in
the
This resulted in a safety evaluation not being performed at
the time the assessment
was completed.
'One of the inspectors identified
that the drawing depicting damper configuration and note ll (described
above)
was included in the
FSAR.
On August 13,
1997,
a safety
evaluation
was completed which satisfactorily addressed
the condition.
The inspectors identified that the steam packing exhauster line stack
isolation dampers
had been. positioned differently than configuration
control drawings for approximately
one year to address
an equipment
performance
issue.
There is not
a specific regulatory requirement to
have
a completed safety assessment/evaluation
for such
a condition.
The
inspectors
did not identify any safety concerns with the equipment
aligned in accordance
with the engineer's
instructions
and the caution
tag.
The inspectors
concluded that the primary concern is that actions
were not initiated to address
permanent
resolution of the problem.
The inspector
reviewed the circumstances
surrounding
two instances
of
incorrect oil added to the Unit 1/2 EDGs.
F
The inspector
determined that two separate
aspects of this problem
should be addressed.
The first aspect dealt with the fai lure of the
licensee to promptly identify that zinc additive oil had been put in the
2A EDG.
This fai'lure led to the incorrect oil also being put into the
20
EDG approximately four months later.
The second
aspect of the
problem dealt with the procurement control deficiencies
which permitted
the incor rect oil to be used in both
EDGs.
On February
1,
1997,
Nechanical
Naintenance
(NN) added lubricating oil
to the Unit 1/2A EDG in accordance
with work order
(WO) 97-001076-000.
The
WO documented
work instructions in a step text format which directed
NN to add oil to the
EDG through the oil strainer
box and referenced
Item Identification Code (TIIC) CAQ-0608.
The inspector
reviewed the
archived copy of the Power Stores
procurement
form (Form 575) and
verified that TIIC CAQ-0608 was procured.
One 55 gallon drum ot oil was
added to the 2A EDG.
On July 2.
1997,
NN added
55 gallons of oi-1 (TIIC
CAQ-0608) to the 20
EDG while performing
WO 97-006843-000.
The licensee
was informed of high zinc content in oil chemistry samples
for the 2A EDG on July 9,
1997,
when
a preliminary copy of the chemistry
report was faxed to the site from TVA Central
Labs.
The report included
data
from several
lube oil samples
for the 2A EDG.
The following five
samples.
taken
on the dates
noted, identified that zinc exceeded
the
vendor limit of 10 ppm maximum:
03/06/97
03/27/97
05/10/97
06/09/97
06/19/97
148
ppm zinc
125 ppm zinc
170 ppm zinc
169
ppm zinc
166 ppm zinc
Subsequent
testing
on July 14.
1997.
revealed that the zinc content in
2D
EDG was
147 ppm.
The concern with zinc in the lube oil is that oil containing zinc
additives could, over
a period of time, result in damage to the
bearings
which contain silver.
Unit 1/2
EDG A/8/C/0 oil samples
taken
July 14,
1997, indicated
<1 ppm silver, which indicated that no
significant degradation
had occurred.
The licensee
determined that TIIC
CAQ-0608 was not procured
as
a zinc tree oil.
On July 14,
1997, the licensee
drained the lube oil from the "A" EDG and
installed
new filters and oil using work order
(WO) 97-007028-000.
Preliminary test results
from the oil sample taken
on July 14,
1997,
indicated that the zinc levels in the 2A EDG had dropped to ll ppm.
The
licensee
replaced the oil in the
2D
EDG on July 25,
1997.
0
22
The inspector
discussed
the review of the oil chemistry test results
with the component
engineer.
The component
engineer typically reviewed
chemistry reports f'r oil samples after the report arrived at the site.
The review process
did not prompt questioning if expected
sample reports
were excessively
delayed:
The inspector
concluded that weaknesses
in
the licensee's
review of oil analysis
reports permitted the introduction
of the same high zinc oil into a second
EDG.
This issue will remain open pending additional
NRC inspection of the
licensee's
corrective actions to preclude recurrence of the problem.
This item will be identified as Unresolved
Item 50-260/97-08-02,
Incorrect
Oi 1
Used in Two EDGs.
During investigation of the high zinc levels identified by chemistry oil
samples,
the licensee
determined that an error had occurred during the
review and change of TIIC numbers.
TVA Corporate
had evaluated
lubricating oils for generic
use in TVA's nuclear plants.
Apparently.
during the process,
an incorrect generic oil substitute TIIC number was
coded to replace the currently used
EDG oil TIIC number.
This incorrect
oil was placed into two of the
EDGs as discussed
previously.
Another recent procurement
example involved incorrect sized lightbulbs
being used in Appendix
R emergency lights.
The. licensee identified this
issue in BFPER971175.
The inspector
previously identified a concern that ethylene glycol could
have been issued'or
use in the
EDGs contrary to Site Standard
Practice
SSP-13. l. Chemistry Program.
This issue
was described in NRC IR 50-
259.260.296/96-13.
The inspectors
discussed
their concerns
regarding procurement
deficiencies
during
a meeting with licensee
management
on August 5,
1997.
Subsequently,
the inspectors
were briefed on the licensee's
ongoing .initiatives in the Materials/Procurement
area.
The licensee
has
identif'ied numerous
issues with the materials
procurement
processes
at
BFN and at the other nuclear sites.
A team has
been established
which,
in recent weeks,
has finalized an action plan to address
the Materials
issues
and potential actions for improvement.
The inspectors
specifically noted that this Materials Upgrade Project is expected to
address
the
common causes
of the concerns
noted above.
The licensee
intends to address
numerous
other
issues.
For example,
progress
has
been
made regarding
a careful
review and identification of critical
il
23
parts for an important safety system.
The proposed actions include
extensi.ve
data
base revisions
and simplifications to complex processes.
Additional
NRC review of the Materials Upgrade Project is warranted.
These
issues
are identified as Inspection
Followup Item 50-260,296/97-
08-05, Materials Upgrade Project.
Weaknesses
in the licensee's
lubrication oil analysis
program permitted
the incorrect type of lubricating oi-1 to be added to a second
several
months after it had been installed in a different
EDG.
An error
in the Materials/Procurement
processes
resulted in workers procuring the
incorrect oil for addition to the
EDGs.
Similar examples of procurement
weaknesses
have been identified previously.
The licensee
has initiated
an extensive Materials Upgrade Project to address
the issues.
E2.4
The inspector
reviewed selected
plant modi.fications in order to veri fy
that (1)
10 CFR 50.59 Safety Evaluations
were technically adequate
and
the screening criteria had been correctly applied;
(2) plant
modification packages
identified all plant procedures
that required
revision because of the design changes;
(3) post modification test
scoping
documents
were technically adequate to demonstrate
achievement
of design objectives;
and (4) work instructions adequately
addressed
the
scope of the plant modification and was consistent with the hardware
changes.
Implementation of the design control process
was also verified
to have complied with the requirements of the licensee's
ANSI N45.2. 11-
1974 design control program.
r
i n
The following plant. modifications were reviewed during this inspection:
~
DCN No. T34764A, Replace Obsolete
Melestrom Pressure
Switches with
SOR Pressure
Switches,
Revision 0.
~
DCN No. T39722A. Modify RFW Heater
Isolation Logic, Revision 0.
~
DCN No. W35344A. Replace
APRM/RBM with Power
Range Neutron
Monitors, Revision 0.
Ci
~
DCN No. W36756A,
Upgrade
Scram Solenoid Valves, Revision 2.
~
DCN No. S39677A,
Revise
Load Limitations, Revision 0.
The licensee's
design control program permits the development
and
implementation of various alphabet
designated
plant modifications
as
defined in procedure
SSP-9.3,
Plant Modifications and Design
Change
Control, Revision 22, Section 5.0 Definitions.
Review of the above two
Ts, two Ws and one
S plant modification revealed that in general
the
design
change
packages
were developed
and implemented in accordance
with
the design controls delineated in plant procedure
SSP-9.3.
The
'nspector
considered
the overall design control process to be complex
and cumbersome
because of the various administrative processes
required
for each type of plant modification.
As a typical example plant
procedure
SSP-9.3 defined the
S-DCN as
a type of DCN that is used to
support documentation
changes
only.
An S-DCN shall not be used for
setpoint
changes.
system realignment,
nor labeling changes.
This design
process
was used incorrectly for system alignment changes,
as described
in the following paragraphs.
Based
on review of DCN No. S39677A the inspector
determined that the
scope of the design
change
involved revising load limitation notes
on
drawings
0-45E732-1,
0-45E732-3,
0-45E7349-1,
and 1-45E749-2.
The load
limitation note was revised to permit simultaneous
operation of
transformers
TS1E and
TDE from the 4160 Volt Diesel Generator Auxiliary
Board "B" based
on
a maximum load limit of 500
KVA.
Design basis
calculation
ED-Q0057-950036,
AC and
DC Load Limitations for Units 2 and
3 Operating.
was reviewed
and verified to have established
a load limit
of 500
KVA for this system alignment.
The licensee
revised drawing
numbers
0-45E732-1
and 0-45E732-3 which were
FSAR Figures 8.5-12A and
8.5-13A respectively.
An FSAR change
request
was also prepared
as part
of the
DCN package in order to incorporate the design
changes
into the
licensing basis
document.
The inspector
reviewed the Safety Assessment
performed for plant
modification
DCN No. S39677A and determined that it failed to identify
the need for a Safety Evaluation.
Revision of the load limitation notes
on the
FSAR Figures
changed the technical
content of the Figures in the
FSAR and should have
been evaluated in accordance
with the requirements
of 10 CFR 50.59.
This change permitted
a new system alignment which had
previously been prohibited because of the current licensing basis.
The.
licensee failed to perform
a
10 CFR 50.59 Safety Evaluation because
the
change
was considered
a documentation
change only.
This fai lure to
25
perform
a
10 CFR 50.59 Safety Evaluation for simultaneous
operation
of'ransformers
TSlE and
TDE involving a new system alignment
was
identified as Violation 50-260/97-08-01.. Failure to perform
a
Safety Evaluation for new system alignment.
The inspector
reviewed the safety assessment/safety
evaluation
prepared
for the other plant modifications in order to verify the technical
adequacy
and compliance with the requirements
of 10 CFR 50.59.
The
safety assessments/safety
evaluations correctly applied the screening
criteria in assessing
the impact of the changes to the plants licensing
basis delineated in the
UFSAR and the Technical Specification.
Additionally, the safety assessments
clearly described
the changes
implemented within the scope of the plant modifications
and concluded
that
an unreviewed safety question did not exist because of the design
changes.
The inspector
concurred with the conclusions
documented.
The licensee's
design controls required that
DCN Impact Review Forms be
completed
by Systems
Engineering,
Operations
and Maintenance for T and
W-DCNs.
Each organization
was responsible
for identifying the
procedures/instructions,
for which they have responsibility, that
required revision prior to:
(1)
Returning the modified equipment/system
to operation
(2)
Final closure of'he
DCN
Plant procedures
or instructions -that are required to maintain the
systems
in a functional/operable
status
were required to be revised
prior to return to operation.
Additionally, procedures
other than those
that are revised prior to return to operation
need to be revised before
closure of the
DCN.
Detail guidance for completing .the Impact Review
Forms
was provided in Appendix
E of SSP-9.3.
The inspector
reviewed
completed
Impact Review Forms for the above plant modifications
and
verified that the requirements
had been satisfied.
One item was identified during this review in connection with DCN
W36756A.
This plant modification was prepared to replace existing
ASCO
scram solenoid pi:lot valves,
scram discharge
valves vent and drain pilot
valves,
and scram discharge
valve isolation test valve with solenoid
valves that had
a longer qualified life.
The Impact Review Form for
this plant modification was verified as having been completed to
initiate revision to procedure
MCI-0-085-HCU001.
The inspector
determined.
that mechanical
corrective instruction MCI-0-085-SOLOOl and
Il
il
26
electrical corrective instruction ECI-0-085-SOL001 which implement
essential
maintenance
requirements for Environmental Qualification
Binder BFNOEQ-SOL-0010 were not listed as requiring revision on the
Impact Review Form.
Discussions with TVA management
revealed that
procedure
MCI-0-085-HCU001 had been replaced
by the two plant procedures
identified above.
Several
changes
in the
ASCO valve model
number's
were
documented in the plant modification package
and these
changes
occurred
in response to industry wide concerns
involving the elastomer
material
used with the valves.
The most recent revision of the
DCN identified
the replacement
as
ASCO model
HV 266000-7J for which plant
procedures
had not yet been identified on the impact review forms.
This
omission appeared to be an anomaly in that the voiding of procedure
MCI-
0-085-HCU001
and its replacement
by other procedures
was not entered
into TVA's document
and records
management
system.
Several
changes
in
ASCO valve model
numbers
and elastomer
types also exacerbated
this
situation.
Problem Evaluation Report
PER No.
BFPER971046
was written to
document this deficiency and initiate corrective action.
The inspector
considered this item to be of'inor safety significance.
The inspector
performed additional
reviews of the plant modification
packages
including work completion statements.
Drawings and design
change authorizations
required for completing the plant modification
including post modification tests
documents
were identitied in the work
completion statements.
Review of selected
post modification test
scoping
documents
revealed that test acceptance criteria were adequate
to demonstrate
achievement of design objective.
No deficiencies
were
identi.fied during this review.
The inspector concluded that the licensee
was implementing the design
control program in accordance
with the requirements of ANSI N45.2. 11-
1974.
One Violation was identified for fai lure to perform
a
10 CFR 50.59 Safety Evaluation during implementation of an "S" DCN.
i
I
v
1
(37550)
The inspector
reviewed selected
Technical Operability Evaluations
(TOEs), in order to evaluate the technical
adequacy of the formal
engineering
input used for aid in determining operability.
The TOEs
were also reviewed to verify compliance with the guidelines of Generic
27
Letter 91-18 for ensuring the functional capability of a system or
component.
TOE No. 0-97-085-0974, Justification for Continued Operation with Scram
Solenoid Valves Containing Incorrect Material
TOE No. 0-97-085-0974,
Revision 0,
was written to provide justification
for continued operation with regard to potential safety related
problem
involving ASCO model
HV 266000-007J
solenoid pilot valves.
The
Automatic Switch Company
(ASCO) in a letter to the
NRC dated
May 27,
1997, provided additional information concerning the potential safety
related problem with ASCO model
HV 266000-007J
scram solenoid pilot
valves
(SSPVs).
In this letter
ASCO identified a total of six plants
that had received the suspect
Browns Ferry was listed as having
received five.
Corrective actions described in the letter included
a
Justitication for Continued Operation
(JCO) prepared
by the General
Electric Company
and which were distributed to the affected plants.
The
JCO recommended that pre-tested pilot valves assemblies
be installed
on
all suspect
valves before they reach the predicted three to four year
end-of-life.
Additionally. the JCO recommended that augmented air
leakage testing
be considered for the plants until the changeout
can be
completed.
The inspector
reviewed TVA's JCO in order to verify that GE's
recommendations
had been incorporated
and compensatory
actions
were
being taken
for the degraded
Based
on this review the inspector
determined that four Unit 2 SSPVs would be changed
out at the next
refueling outage
(RFO) scheduled for the end of September
1997.
Similarly, one Unit 3 SSPV would be changed
out at the next
scheduled f'r September
1998.
TVA concluded that the service life of
the
based
on their installation date
was well within the
recommended life of the elastomers.
Compensatory
actions to be
performed for the Unit 3 SSPV will involve, additional
scram time testing
on a frequency of 16 weeks for control rod 26-31 until replacement of
the pilot head subassembly
per
WR C385168.
The inspector identified no
deficiencies
during review of. TOE No. 097-085-0974.
TOE No. 0-94-086-0169,
0/G "D" Instrument Air Root Valve
TOE No. 0-94-086-0169
was written to evaluate the installation of a non-
safety valve in a safety related
system.
System
086, diesel starting
0
28
air system right bank instrument root valve 0-RTV-086-0602D was
installed by Work Order 91-39183-00
and was requi red to maintain system
pressure for enabling the "D" diesel
generator to start.
The licensee
determined that the .apparent
cause for installation of the non-safety
valve to be an inadequate
procedure in that procedure
SSP-6.2.
Maintenance
Management
System,
did not provide clear guidance
concerning
replacement
parts.
The procedure
paragraph
3.9. 1 was revised
on October
26,
1994, to preclude future occurrence of this issue.
The installation
was accepted
as-is
based
on the valve design
and post installation
tests.
The valve installed
was
a
NUPRO B4J rated at 250 psi at 300
degree fahrenheit.
System design temperature
and pressure
was given as
300 degree fahrenheit
and 200 psi.
The TOE was closed
based
on post
maintenance
tests results which verified no leakage through the seat
and
no visible leakage at the valve with the system in service.
The basis for closing the
TOE did not consider
seismic requirements.
The inspector
considers this to be of'inor safety significance given
the small
mass of the instrument root,valve and the redundancy
designed
into the diesel starting air system.
Additionally. the inspector
considered
the licensee's
corrective actions were adequate to prevent
reoccurrence.
TOE No. 0-94-026-9006,
Fire
Pump Auto Start Circuit
This TOE was written to evaluate the installation of temporary jumpers
on the fire pump auto start ci rcuit while plant modification
DCN No.
W18627A was being implemented.
The plant modification added
redundant
Class
1E fuses for cables
FE100 and A1225 in order to resolve electr ical
separation
concerns of non-safety related circuits degrading safety
related circuits.
Installation of the temporary jumpers provided
electrical
power from 120
VAC preferred
bus
on panel 9-24, breaker
512
to auto start terminal points
WFXl and
WFY1.
The auto start circuit was
therefore enabled while fuses
0-FU2-026-512A and
B were being installed.
This temporary plant modification was implemented
by work plan 0626-93
for which
a
10 CFR 50.59 safety Evaluation
had been
per formed.
No
deficiencies
were identified during review of TOE No. 0-94-026-9006.
TOE No. 2-96-211-9003,
Transformers
TSlE and
TDE Simultaneous
Operation
This
TOE was written to permit paral,lel operation of transformers
TS1E
and
TDE from the 4160
V Shutdown
Board "B" despite specified
restrictions
on approved design output drawings.
The TOE failed to
recognize that
a plant modification should have been
used to implement
0
ik
29
this design change.
Failure of the
TOE to initiate a plant modification
was recognized
by TVA management
and
PER No.
BFPER960512
was written to
initiate
DCN No. S39677A for revising the load limitations notes
on
drawings
number 0-45E732-1,
0-45E732-3,
1-45E749-1,
and 1-45E749-2.
The
DCN is further reviewed in Section E2.4.
The
TOE documented
a technical evaluation for the load limit specified
on the referenced
drawings
and provided quantitative acceptance criteria
of 77 Amps for a load limit of 555 KVA.
The inspector
reviewed design
basis calculation
ED-00057-950036,
Revision
2 and verified that
a load
limit of 500
KVA had been established
as the load restriction for
simultaneous
operation of transformers
TS1E and
TDE.
Based
on the load
limit of 500
KVA the inspector calculated the load current to be 69.3
Amps which was ditf'erent from the value given in the TOE.
The TOE also stated that procedure 0-0I-578,
480/240
VAC Electrical
System,
Revision 53, should be revised to include instructions for
simultaneous
operation of transformers
TS1E and TDE.
The inspector
reviewed the procedure
and verified that the procedure
had been revised
to permit parallel operation of,both transformers
based
on
a load limit
of 500 KVA.
A 10 CFR 50.59 Safety Evaluation
had also been
perf'ormed to
incorporate these
load limit restrictions into revision 48 of the
procedure.
Section 3. 14 delineated
the precautions
and limitations for
parallel operation of the transformers.
Based
on review of the
procedure,
the inspector determined that the procedure did not provide
quantitative acceptance criteria within the body of the procedure
for
parallel operation of transformers
TS1E and
TDE under load limiting
conditions.
Section 8.6 of the procedure delineates
the instructions
for transferring
480
V shutdown board
"1A" from the normal to the
alternate
power supply.
Section 8. 10 provides similar instructions
for
transferring the 480
V diesel auxiliary board
"A" from the normal to the
alternate
power supply.
The procedure did not identify within either
sections
8.6 or 8. 10
a load limiting value of 500
KVA for system
alignment
implemented
by performance of both of these sections.
The
licensee stated that the precaution
and limitation statement
in Section
3. 14 which required calculation of the load current under this mode of
plant operation
was adequate for this plant evolution.
The inspector
considered
the procedure
adequate,
.however,
omission of quantitative
acceptance criteria within the body of the procedure
could result in
human errors.
The Resident
Inspector
observed
implementation of such
an evolution as discussed
in Section 01.2.
0
0
30
The inspector concluded that the TOEs were technically adequate
with
some minor exceptions.
E8
Hiscellaneous
Engineering
Issues
(92903)
E8. 1
1
,
Emergency
Core
Cooling System
(ECCS) Inverter Failures.
This IFI addressed
several
fai lures of the Unit 3
ECCS inverters which have occurred since July
1996.
The cause of the inverter failures
and potential affects of
ambient
room temperatures
were not fully understood.
A total of five
incidents
have occurred
on the Unit '3 inverters, inverter component
replacements
were required in four of'he instances
and in one case
a
fuse cleared.
Inspection Reports
259,260,296/96-08,
96-12,
and 96-13
contain description of NRC review of several of the incidents.
The
licensee
has submitted Licensee
Event Reports
on the failures.
The licensee
performed extensive investigation into the failures
including:
~
The failed Silicon Controlled Rectifiers
(SCRs) were analyzed
by a
vendor
and
an independent testing
company.
The analysis
noted
that the epoxy encapsulant
in the failed SCR did not completely
fill the lower cavity and
an air bubble
may have been present.
The SCR failed at
a corner where it is most susceptible to voltage
stress
and the analysis
concluded that the fai lures were related
to an overvoltage condition.
~
Extensive online monitoring of the inverters
and investigation by
the licensee
ruled out potential
causes
such
as electronic noise,
radio. transmissions,
power supply transfers,
or other plant
evolutions.
Reviews of Operating
Experience
Data indicated that
inverter fai lures which had occurred at other facilities were not
similar. to these failures.
~
A technical
assessment
was .conducted
by a TVA corporate electrical
engineer
and
a representative
of SCI.
The review concluded that
the most likely cause of four of the five failures was
damaged
or
defective
SCRs.
The other failure (fuse clearing) apparently
0
involved a loose air-core inductor which shorted
a capacitor
bus.
The
review stated that the inverter
vendor
has concluded that the inverter
components
are optimized for stable operation for the range of voltage,
loading,
and ambient temperatures.
Corrective actions
implemented included:
125
amp inverter fuses
were replaced with 100
amp fuses
on Unit 3
(and will be replaced
on Unit 2).
The fai led SCRs were Solidstate Controls Incorporated
(SCI)
type TD 42.
The vendor has replaced
TD 42 SCRs with TD 46 type.
The TO 46 SCRs have larger I't ratings than the
TO 42 SCRs.
A modification
(DCN T39853)
was implemented
on Unit 3 and is
planned
(DCN T39852) for Unit 2 which adds
a 250
VDC to 24
VDC
converter.
This converter will provide an alternate
supply to the
Analog Trip Units if'n inverter failure occurs.
This
significantly reduces
the potential satety affects of an inverter
failure.
IR 96-08 noted that
a
NRC inspector identified that
some of the
inverters did not have the minimum clearance to the wall stated in the
vendor
manual.
The inspector noted that an SCI field service repair
report.
dated February
1997, stated that the inverter temperatures
were
well within limits.
Problem Evaluation Report
(PER) 961123
was
initiated to address this issue.
The inspector
reviewed the completed
PER.
The licensee's
investigation concluded that one of the causes of
the problem was that the vendor instruction manual which contained the
clearance
requirements,
was not supplied
on the front end of the
procurement
process
and thus the information was not incorporated into
the installation design.
The licensee
concluded that the lack ot
clearance
was not
a factor in the recent failures and noted that the
Unit 2 inverters are installed closer to the wall than the Unit 3
inver ters
and have not experienced, the
SCR failures.
The licensee
obtained concurrence
from the vendor that the installed configuration is
acceptable
and incorporated
documentation into the vendor
manual.
The
inspector
reviewed
a memorandum which clearly stated that the vendor did
not feel that the cabinet spacing
was
a problem.
Site Engineering
issued
a
memo to the Procurement
Engineering
Group reinforcing the
obligation to obtain special
design requirements
on the front end of a
contract
and request that such information be addressed
on vendor
drawings
so that it can be incorporated into the design package.
0
0
32
The inspector concluded that the licensee's
overall investigative
and
corrective actions regarding the inverter failures were timely and
effective.
No failures of the replaced
have occurred.
The
inverters are being monitored by the licensee
as
an a(1) system in
accordance
with the maintenance
rule.
The failures
and corrective
actions
were well documented
in the licensee's
corrective action system.
IFI 296/96-08-02 is closed.
E8.2
1
, Resolution of FSAR
Discrepancies.
During a review of the Final Safety Analysis Report
Section 4.7.7, the inspector
questioned
the following statement:
"Testing of the RCIC pump discharge
valve and air-operated
is accomplished
by first shutting the upstream discharge valve."
The
licensee
reviewed the statement
and determined that
a discrepancy
existed
between the
FSAR statement
and the way that the testing is
currently conducted.
The licensee initiated BFPER971070
on July 8,
1997.
The IFI remains
open pending additional
NRC review of the
licensee's
UFSAR review program.
f8.3
Torus Water, Level
Exceeded
Technical Specification
(TS) Limit Due to a Past
Engineering
Error.
This
LER addressed
the licensee's
identification that
a 2 inch
offset in the narrow torus water level instrumentation
had resulted in
torus level slightly exceeding the -1 inch TS limit in the past.
This
issue
was reviewed in detail
by NRC inspectors
as documented in IR 95-
64.
Non-Cited Violation 95-64-09, Violation of Torus Water Level TS,
addressed
the deficiency.
The
LER is closed.
E8.4
n
, Failure of the High
Pressure
Coolant Injection Steam Supply Valve During Testing.
The
licensee
determined that pitted seal-in contacts
in the steam supply
circuitry caused
the. problem.
IR 95-31 describes
NRC review immediately
following the failure.
The inspector
reviewed closed
PER 950690
and
maintenance
work records.
The documentation
indicated that the valve
was stroked
on September
8.
1995.
(which verified the contacts
were
operating)
and the contacts
were inspected
on December
1,
1995.
Work
Order 95-14730-00 stated that the contacts
were found in good condition.
The inspector also verified that procedure
EPI-0-000-MCC001 is scheduled
to be performed
on the breaker during the upcoming refueling outage.
No
other
problems with these contacts
have occurred'since
the 1995 failure.
The
LER is closed.
0
0
0
E8.5
33
In April of 1996 TVA's Vendor Audit Services
received information from
NUPIC concerning continuing weaknesses
in Ellis and Watts commercial
grade dedication
processes
and this vendor was
removed from the Accepted
Supplier List (ASL).
Vendor surveillance
report number 96S-18,
dated
June
17,
1996,
documented
TVA's evaluation of commercial
grade
dedication
packages
for several
Browns Ferry purchase
orders.
The
vendor surveillance
was performed at Ellis and Watts, Batavi a,
Ohio on
May 9-10.
1996.
The inspector conducted
interviews with TVA's personnel
from.the Procurement
Engineering
Group
(PEG)
and reviewed objective
evidence which provided reasonable.
assurance
that material
accepted
from
Ellis and Watts, had met specified technical
and quality requirements.
The fol,lowing documents
the results of this review:
Purchase
Order
(PO) 96N2D-156126
was issued
for two Spartan
solenoid
valves which had not yet been shipped at the time of the evaluation.
This contract
was canceled
and the material
was never received
from the
vendor.
PO 96N2R-167653
was .issued for ten Spartan
solenoid valves.
approved Ellis and Watts revised
commercial
grade dedication plan
CDPN-
0723 on May 10,
1996.
Critical characteristics
had been verified by a
combination of inspection
and commercial
grade survey.
Additionally, a
sample of these valves were examined
and no deficiencies
were
identified.
The material
was received
and accepted
from the vendor.
PO 95N2R-171612
was issued for two solenoid valves; this material
was
processed
and received prior to the vendor being
removed from the ASL.
Commercial dedication plan CDPN-0729 was approved
by TVA and critical
characteristics
were verified by a combination of inspection
and
commercial
grade survey.
The package
was determined to be acceptable.
PO 95N2R-149040
was issued for two Metrex chiller valves.
Commercial
dedication plan CDPN-0702 was reviewed
and approved
by TVA with the
following exceptions:
~
Verification of material for pressure
boundary items was not
validated
by the vendor.
0
0
0
34
~
Hydro test pressure
values
documented
in the
CDPN and the actual
test results
were different.
The
CDPN showed test pressure of 280
psig and the test report specified. Z25 psig.
Additionally.
PO 96NZR-16556 issued for three Hetrex chiller valves
was
determined to be satisfactory
based
on review of dedication plan
CDPN-
0719 with an exception similar to the first one identified above.
The
exceptions
were resolved via correspondence
with the vendor and material
tests
performed
by TVA's Central Laboratory Services.
The chemical
composition of the valve material
was identified in Centra1
Laboratory
Services
Technical
Report
No. 96-1098,
dated July 8.
1996.
PO 96N2R-166372
was issued
for one crank case heater
and its commercial
grade dedication plan CDPN-0720 was reviewed
and .approved
by TVA.
An
examination of the heater revealed.
however, that it differed from the
sketch provided by the vendor with regard to the length of the leads
required for power connection.
The two heaters
also differed in
appearance.
Based
on the results of TVA's investigation of this issue
one heater
was determined to be acceptable
for shipment
and the other
was not released for shipment
pending the vendor
making an equivalency
determination for the other.
The inspector concluded that the actions taken by TVA for release of
material
received
from Ellis and Watts was adequate to ensure that
technical
and quality requirements
involving critical characteristics
of
procured items were satisfactory.
E8.6
1
This violation identified that
on February
2 and 4,
1993, the licensee failed to ensure that the
provisions of 10 CFR 50.7 were implemented in that Stone
and Webster
Engineering Corporation,
a contractor to the Tennessee
Valley Authority
at the Browns Ferry Nuclear Plant, discriminated against
a worker
engaged
in a protected activities.
Specific corrective action for this violation was reviewed
and
documented
in NRC Inspection Report 50-260,
296/96-13.
This violation
is closed for record purposes;
however. the staff will continue to
monitor plant specific indicators related to discriminatory employment
practices.
These indicators include, in part, allegations of
discrimination reported to the
NRC and proceedings initiated as
a result
of complaints
made to the Department of Labor alleging discrimination
0
0
35
practices.
These indicators include. in part. allegations of
discrimination reported to the
NRC and proceedings initiated as
a result
of complaints
made to the Department of Labor alleging discrimination
for engaging in protected activity.
R4
Staff Knowledge and Performance
in Radiological Controls
and Chemistry
R4.1.
The inspector
observed
sampling ot the
Raw Cooling Water
(RCW) system.
In accordance
with Inspection Procedure 71750,
compliance with
procedural
and Offsite Dose Calculation Manual
(ODCM) requirements
was
examined.
b.
II
On July 17,
1997,
one of the inspectors
observed
sampling of the Unit 1
RCW system.
The sampling
and analysis
was being conducted
because
the
Unit 1
RCW effluent radiation monitor (RM-90-132D) was inoperable.
Table
1. 1-1 of the
ODCM (Action D) requires
sampling at least
once every eight
hours during
RCW releases
.when the monitor is inoperable.
The monitor
had been inoperable since July 4,
1997.
The inspector
observed that the
licensee
had good administrative
methods to ensure that the sampling
was
performed within the required intervals'nce
per six hour sampling
requirements
were actively tracked
by the Chemistry Shift Supervisors
and turned over between the Radiological Laboratory Assistants
(RLAs).
The data
package
for completion of the procedure
contained signatures
for verification that the time requirements
were met for each
sample.
The sampling
and analysis is controlled by Surveillance Instruction 0-
SI-4.2.D-3B,
RCW Effluent Radiation Monitor (Off-Line) Inoperable,
and
Chemistry Instruction (CI)-403, Reactor Building Sampling Procedure.
The
RLA notified the Unit 1 Operator
and reviewed the surveillance
requirements prior to obtaining the sample.
However, the
RLA did not
perform several
steps in accordance
with the procedure.
Step 7.7 of O-SI-4.2.D-3B states that the sample
volume is to be
collected for gamma
scan
per Attachment
15 of CI-403.
Step 1.2 of CI-
0
36
403 required that valve 1-24-880 be verified open.
This valve is
a
small
manual isolation valve between the
RCW outlet line and the sample
pump.
The RLA failed to verify that the, valve was open.
Step 1.3 of CI-403 required the worker to check the operating status of
the sample
pump.
Sampling is performed differently depending
on sample
pump status.
The step contained specific directions that the sample
pump is operating if the
"MOTOR ON" light on Panel
25-336 is
illuminated.
The sample
pump is not operating it the
"MOTOR OFF" light
is illuminated or if all Panel
25-366 lights are extinguished.
All the
lights were extinguished.
(The error in panel
numbers
had been
previously identified and was being addressed).
In response to the
inspector's
questions.
the worker discussed
that he had verified that
the
pump was operating
by direct observation of the pump and sample tlow
indication on the panel
instead of the procedural
requirements.
The
inspector observed that the sample
pump appeared to be running and there
was sample flow indicated.
Subsequently, it was determined that the
"MOTOR ON" light bulb had burned out.
The remaining steps
were performed
as required.
The RLA also contacted
Operations
and requested
independent verification that the sample valve
had been shut.
Required information was entered
on the data sheets
for
O-SI-4.2.D-3B and
a
gamma
scan
was performed.
The printout of the
gamma
scan
was forwarded to the Chemistry Shift Supervisor
(CSS) f'r review.
Steps
7. 10-7.12 of the SI require the
CSS to review the data
and verify
acceptance criteria were met.
The printout listed minimum detectable
activity (MDA) in microcuries per milliliter for different isotopes in
the sample
and stated that no activity had been identified in the
sample.
The inspector
asked the
how he verified the acceptance
criteria that the Lower Limit of Detection
(LLD) of the analysis
was
less than the Effluent Concentration Limit (ECL) (total) .as described in
step 7.9.3 of the SI.
The
CSS responded that he was not sure
how to do
that from the data
on the printout.
Subsequently,
Chemistry department
supervision
informed the inspector that the counting equipment in the
lab .was set
up to meet the requirements
for Lower Limit of Detection.
This was accomplished
by setting
a conservative
minimum count time
period into the routine used
by the
RLAs to count the samples.
The inspector
noted two minor administrative errors in the procedure.
Attachment
2 of O-SI-4.2.D-3B (page
9 of 9) contained
an incorrect title
line and referenced
the Residual
Heat Removal Service Water radiation
monitor.
The inspector
was subsequently
informed that this error
had
been detected
the previous
week and was being corrected.
Step 1.3 of
0
4l
37
the SI contained
an incorrect panel
reference
number.
The inspector
was
informed that Chemistry personnel
had recently identified that error as
well and would correct it.
Browns Ferry Technical Specification (TS) 6.8. 1. l.i requires that
written procedures
shall 'be established.
implemented,
and maintained
covering the activities referenced
in the
ODCM.
Table 1. 1-1 of the
states that releases
of'CW may continue, with the number of radiation
monitoring instrumentation
channels
less than the required
minimum.
provided that
a temporary monitor is installed or at least
once
per
eight hours grab samples
are collected
and analyzed for radioactivity.
The worker did not correctly implement written procedure
CI-403 which is
utilized to accomplish the
ODCM requirements.
This failure constitutes
a violation of minor significance
and is being treated
as
a Non-Cited
Violation, consistent with Section
IV of the Enforcement Policy.
The
violation had no actual
impact on the validity of the raw cooling water
sample.
This is addressed
as Non-Cited Violation 259/97-08-04,
Failure
to Follow Chemistry Sampling Procedure.
The licensee
had strong administrative controls in place to minimize the
possibility of missing
a 'ODCM required compensatory
RCW sample.
The
indicated to the inspector that he was not aware of how the LLD
acceptance criteria (stated in ODCM and the procedure)
was met, although
it was his responsibility to verify that the criteria was met.
The
worker did not fully comply with the sampling procedure.
The safety
significance of the specific deficiencies
was small since the overall
intent of the steps
was met.
However, considering that Chemistry
department
management
has
been emphasizing
procedural
compliance in
recent
months,
the inspector
concluded that the deficiency should be
addressed
by the licensee.
The inspector
noted indications that
management
has also initiated efforts to improve Chemistry, procedures.
R8
Miscellaneous Radiological Protection
and Chemistry Issues
R8.1
v
In accordance
with the guidance in Inspection
Procedure
71707, the
inspector
per formed
a review of the licensee's
10 CFR 19 required
postings at selected bulletin boards
around the site.
0
38
On June 25,
1997, the inspector
noted that an outdated
NRC Form 3 was
posted
on
a bulletin board at the East Gatehouse
protected
area entry
point.
The inspector brought this to the attention of the Site
Licensing Supervisor
and 'a problem evaluation report
(PER)
BFPER971039
was initiated.
In addition,
a current copy of Form 3 was temporarily
placed over the outdated version which was in a locked case
and could
not immediately be removed.
Subsequently,
the licensee
informed the
inspector that the board was not the licensee's
required board,
but was
maintained
by a contractor.
The
NRC Form 3 was
removed from the board.
The inspector also noted'hat
an old version of 10 CFR Part 19 was
posted.
The inspector discussed
with the licensee
how the required
postings
were maintained.
The licensee indicated that they perform
a
periodic review of the posted
documents at seven locations
around the
plant.
The most recent
review was performed
on June 5,
1997.
The
licensee
addressed
the outdated version of 10 CFR Part 19 by adding
an
item to the per iodic review checklist to replace
21 from the
NRC Rules
and Regulations.
On July 11,
1997, the inspector
sampled four of the seven places that
the licensee displays
10 CFR 19 required postings.
The East
and West
Gatehouse
boards
included the
NRC Form 3, Part 19. Part 21.
and
a
licensee
Notice to Employees
which discusses
required postings
and where
they can be viewed.
The remaining two boards
sampled
included the
NRC
Form 3 and the licensee
Notice to Employees.
The inspectors
questioned
the clarity of some of the items in the Notice
to Employees.
On July 17,
1997. the inspector discussed
changes
made 'by
the licensee to the Notice to Employees.
The licensee clarified the
contacts for assistance
in reviewing required documents.
In addition,
the licensee clarified the posting to more accurately reflect the
NRC
position on identity protection of individuals that present thei r
concerns to the
NRC.
The inspectors
considered that the licensee's
actions
were acceptable.
l
F l
Review of
Licensee
FSAR Commitments for
CANs associated
with Units
1 and 3.
Review of this item was documented in Inspection Report 96-06 but due to
an administrative oversight the item was not closed out.
The review was
sufficient to close out the item. the IFI is closed.
0
e
39
Pl
Conduct of Emergency Preparedness
Activities
P1.1
The inspector observed portions of the emergency
preparedness
training
drill which was administered
on July 30.
1997.
The inspector
observed
the drill from the Technical Support Center
(TSC).
The drill appeared to be
a good training opportunity for
participants.
The participants in the TSC provided recommendations
for
improvements
during the post drill critique.
P8
Hiscellaneous
Security and Safeguards
Issues
P8.1
, Failure to Adequately
Control Unattended
Vehicles Within the Protected
Area.
The inspectors
reviewed the licensee's
corrective actions which included
a notice to
vehicle drivers entering the protected
area,
a Site Security memorandum
which directed patrols to increase
checks
and searches
of designated
vehicles within the protected
area,
and training of Facilities and
Instrument
and Controls personnel.
In addition, the licensee
addressed
control of vehicles within the protected
area in the Plan of the Day
Report dated September
23,
1996.
The inspectors
sampled vehicles to
ensure that the vehicles were controlled.
This item is closed.
P8
Hiscellaneous
EP Issues
P8.2
r
Dose Assessment
capability. This item was opened to evaluate whether,
in the event of an
emergency at Browns Ferry,
methods were in place for on-shift personnel
to perform basic offsite dose calculations
using real time
meteorological
data.
Subsequent
detailed in-office review of the licensee's
Emergency
Plan
determined that the licensee
had not committed to have on-shift dose
assessment
capability.
Subsequently,
the licensee
revised
Emergency
Plan to provide for on-shift dose
assessment
capability and revised
their Emergency
Plan, Implementing Procedure
EPIP 14, Radiological
Control Procedures",
Revision 11, to provide that capability.
il~
40
The licensee's
submitted
change to Emergency
Plan Implementing
Procedures
(EPIP)
14, Radiological Control Procedures,
Revision 12,
deleted Section 3.9 f'rom EPIP 14, Revision
11. Section 3.9 had
instructed on-shift personnel
to run Forecast
Radiological
Emergency
Dose
(FRED) to make emergency classifications
in the event of a
radiological release.
FRED was the licensee's
dose assessment
computer
located in the Technical
Support Center
(TSC).
Other changes
in EPIP 14, Revision 12,
enhanced
the manual
method for
offsite dose calculation by adding two tables with multiplication
factors,
one for
a stack release,
and one for a building or ground
release.
The multiplication factors were selected,
based
upon wind
speed
and stability class for distance of 1 mile,
5 miles,
and
10 miles
from the plant.
To determine the dose rate, the radiological release
rate was multiplied by these multiplication factors.
The inspectors
worked through the procedure without any difficulty. EPIP 14. Revision
12 was of sufficient detail to permit on-shift personnel to perform
a
basic dose calculation at given distances
for the plant using real time
meteorological
data.
Exit Meeting Summary
The resident inspectors
presented
inspection findings and results to
licensee
management
on August 5,
1997.
Other meetings to discuss
report
issues
were conducted during the report period.
A formal meeting with
plant management
was also conducted
on July 11,
1997.
During the July
11,
1997, meeting,
the licensee indicated that additional discussion
was
appropriate
regarding two findings in the engineering
areas.
A
subsequent
telephone call with NRC Region II (RII) management
and
a
reactor engineer
from the RII staff, reviewed the licensee's
position on
the two findings.
A subsequent
exit meeting
was conducted
on August 20,
1997, after
additional information was available regarding the High Pressure
Coolant
-Injection system problem, the Standby
Gas Treatment
System testing
items,
and the engineering
review issues.
The licensee
acknowledged
the
findings presented.
Proprietary information is not included in this
inspection report.
II
1
T. Abney, Licensing Manager
J. Brazell, Site Security Manager
R.
Coleman. Acting Radiological Control'anager
J.
Corey, Radiological Controls
and .Chemistry Manager
T. Cornelius.
Emergency
Preparedness
and Planning.
C. Crane, Site Vice President,
Browns Ferry
R. Greenman,
Training Manager
J.
Johnson,
Site Quality Assurance
Manager
R. Jones,
Assistant Plant Manager
S.
Kane, Acting Site Licensing Supervisor
G. Little, Acting Operations
Manager
K..Singer, Plant Manager
J. Schlessel,
Acting Maintenance
Manager
H. Williams. Site Engineering
Manager
IP 37550:
IP 37551:
IP 40500:
IP 62707:
IP 61726:
IP 71707:
IP 71750:
IP 73756:
IP 81502:
IP 92901:
IP 92902:
IP 92903:
IP 93702:
Engineering
Onsi te Engineering
Licensee Self-Assessments
Maintenance Observations
Survei 1'lance Observations
Plant Operations
Plant Support Activities
Inser vice Testing of Pumps
and Valves
Fitness
For Duty Program
Followup-Plant Operations
Followup-Maintenance
Fol,lowup-Engineering
Prompt Onsite
Response to Events at Operating
Power Reactors
. ~
0
50-260/97-08-01
260/97-08-02
260/97-08-03
259/97-08-04
IFI
260,296/97-08-05
Open
Open
Closed
Closed
Open
Failure to perform
a
Safety Evaluation for
New System
Alignment (Section E2.4)
Incorrect Oil Used in Two EDGs
(Section
E2.3)
Failure to Identi fy Water'ntrusion
into HPCI System Junction
Box
(Section
E2.1)
Failure to Follow Chemistry Sampling
Procedure
(Section
R4. 1')
Materials
Upgrade Project (Section
M8.4 and E2.3)
IFI
259,260,296/97-01-01
Open
Resolution of FSAR Discrepancies
(Section E8.2)
Q.Q5K
Closed
Core Thermal
Power
Exceeded
Operating License's
Maximum Power
Level
Due to a Drifting Temperature
Transmitter
(Section 08. 1)
296/95-64-01
Closed
Fire Protection
Program
Equipment
Inoperable Without Compensatory
Actions (Section 08.2)
260/96-03-01
Closed,
Failure to Fol,low Procedures
During
Core Spray Valve Maintenance
(Section
MB. 1)
0
260/96-04-01
Closed
Licensee Identified Appendix
R
Deficiencies
(Section M8.2)
259,260,296/EA
.95 220
Closed
Violation of 10 CFR 50.7
(Section
E8.6)
Closed
10 CFR Part 50 Appendix
R
Noncompliance Results in the Plant
Being Outside Its Design Basis
and
Being in a Condition Not Covered by
Plant Operating Instructions
(Section M8.3)
'URI
259,260,296/96-13-02
Closed
Toolpouch Issues
(Section M8.4)
IFI
.296/96-08-02
LER
Z60/95-009
. IFI
259.296/95-55.-01
Closed
Closed
Closed
Closed
Emergency
Core Cooling System
(ECCS)
Inverter Failures
(Section
EB. 1)
Torus Water Level
Exceeded
Technical
Specifications
(TS) Limit Due to a
Past Engineering
Error
(Section
E8.3)
Failure of the High Pressure
Coolant
Injection System Supply Valve During
Testing (Section E8.4)
Review of Licensee
FSAR Commitments
for CAMs Associated with Units
1
8 3
(Section R8.2)
259.260,296/96-10-01
'losed
'ailure to Adequately Control
Unattended
Vehicles Within the
Protected
Area (Section P8.1)
50-260,296/96-05-04
Closed
On-shift Dose Assessment
capability.
pending -additional
NRC review
(Section P8.2).
t
!
i
0