ML18033B454
| ML18033B454 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 07/11/1990 |
| From: | Carpenter D, Little W, Patterso C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18033B451 | List: |
| References | |
| 50-259-90-18, 50-260-90-18, 50-296-90-18, NUDOCS 9007260278 | |
| Download: ML18033B454 (36) | |
See also: IR 05000259/1990018
Text
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UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323
Report NoseI
50-259/90-18,
50-260/90-18,
and 50-296/90-18
Licensee:
Valley Authority
6N 38A Lookout Place
1101 Market Street
Chattanooga,
TN
37402-2801
Docket
Nose I
50-259,
50-260,
and 50-296
License
Nose I
and
Facility Name:
Browns Ferry Units 1, 2, and
3
Inspection at Browns Ferry Site near Decatur,
Inspection
Conducted:
May 19 - June
18,
1990
Inspectors:
'
il M
Jp~ ..C ar~e 'er,
Sgt
ana er
/
.
.
atte
son,
estart Coordinator
Accompanied
by:
E. Christnot,
Resident
Inspector
W. Bearden,
Resident
Inspector
K. Ivey, Resident
Inspector
R. Bernhard,
Project Engineer
ate
cygne
7 /f
Date
igne
Approved by:
c
W. S. Lett, Section Chief,
Inspection
Programs,
TVA Projects Division
SUMMARY
at
Signed
Scope:
This routine resident
inspection included surveillance observation,
operational
safety verification, modifications,
licensed
operator
training,
reportable
occurrences,
action
on previous inspection findings, and
TMI action items.
Results:
A deviation
was identified for continuing problems with timely resolution of
drawing discrepancies paragraph
three.
The backlog of
DDs remains at 2000.
Previous
corrective action to
a
NOV to provide engineering
resolution within
CIC) 726CI278
90CI71-
PflR
ADOCK CI50CI02 9
9
30 days
has not been effective.
No mechanism exists to identify DDs on control
room drawings
used
by plant operators.
A violation
was identified for failure to control modifications activities,
paragraph
4.
Modifications personnel
commenced
work activities
on the south
when only work on the north header
had
been approved.
The
18 inch
was in operation at the time and the potential for equipment
damage
and
personnel
injury was significant.
An IFI was
opened
to track licensee
response
to
a significant interaction of
the
ECCS Analog Trip Units water that leaked through
a seismic
gap between
the
Unit I and Unit 2 control building,
paragraph
3.
The seismic
gap
and
ATU
cabinets
are not designed
to be watertight.
Water leaked
through the gap and
caused multiple ESF actuations
and activation of the ARI/ATWS.
An IFI was
opened
to track resolution of RHR injection valve erosion,
paragraph
3.
Erosion
was identified in one loop and
UT indications
were identified in
the opposite
loop.
The opposite
loop has not been
inspected.
Two LERs,
two IFIs, three
URIs,
two violations,
and
two TMI action items were
closed.
The major licensee
work activities this month
were completion of bulk work
items.
This included completion of hanger
and support modifications
and
75K
of Eg the modifications.
0
REPORT DETAILS
Persons
Contacted
Licensee
Employees:
- 0. Zeringue, Site Director
- L. Myers, Plant Manager
- M. Herrell, Plant Operations
Manager
J. Hutson, Project Engineer
J. Hutton, Operations
Superintendent
- A. Sorrell, Maintenance
Superintendent
G. Turner, Site guality Assurance
Manager
- P. Carier, Site Licensing Manager
- P. Salas,
Compliance Supervisor
- J. Corey, Site Radiological
Control Superintendent
R. Tuttle, Site Security Manager
Other
licensee
employees
or contractors
contacted
included
licensed
reactor operators,
auxiliary operators,
craftsmen,
technicians,
and public
safety officers;
and quality assurance,
design,
and engineering
personnel.
NRC Personnel:
- D. Carpenter,
Site Manager
- C. Patterson,
Restart Coordinator
E. Christnot,
Resident
Inspector
W. Bearden,
Resident
Inspector
- K. Ivey, Resident
Inspector
"Attended exit interview
Acronyms used throughout this report are listed in the last paragraph.
Surveillance
Observation
(61726)
The
inspectors
observed
and
reviewed
the
performance
of selected
SIs.
The inspections
included
reviews of the SIs for technical
adequacy
and
conformance
to
TS,
verification of test
instrument
calibration,
observations
of the conduct of testing,
confirmation of proper
removal
from service
and return to service of systems,
and reviews of test data.
The inspectors
also verified that
LCOs were met, testing
was accomplished
by qualified personnel,
and
the SIs
were completed within the required
frequency.
a.
The following SIs were reviewed during this reporting period:
1-SI-42.A.10
3-S I-4.A. 19 (3D )
2A Ventilation Radiation Monitors Calibration
and
Functional Test.
3D Diesel Generator
Monthly Operability
b.
. Problems with Wire Lifting and Jumpering
259,
260,
296/90-14-01
documented
two
examples
involving
inadequate
procedures
for the installation of temporary
jumpers
on
relays.
In both
cases
systems
important to safety
were adversely
affected
and that
had
the plant
been
in an operational
mode could
have resulted
in
a significant safety
problem.
The licensee
took
immediate corrective action by reviewing all procedures
requiring the
temporary jumpering of relay types
HFA,
CR 120A, and
HGA.
Results of
this review indicated that additional training was required.
The inspector
attended
a training class for operations
personnel
in
which handouts
were given to the students
that clearly
showed
the
contact
sequencing
of the three
types of relays.
Discussions
were
held during
the training sessions
with actual
relays
being
shown.
During
an
inspection
of the
relay
racks
and
relay
rooms,
the
inspector
observed
several
new permanently
posted operator aids that
easily identified the contact locations
and
sequences
of the type
MFA,
CR
120A and
HGA relays.
These
were
posted
in response
to this
and
previous
similar events.
Review of the
programmatic
concerns
with the surveillance
program continues.
No violations or deviations
were identified in the Surveillance
Observa-
tion area.
3.
Operational
Safety Verification (71707)
The
NRC inspectors
followed the overall plant status
and
any significant
safety matters
related
to plant operations.
Daily discussions
were held
with plant management
and various
members of the plant operating staff.
The
inspectors
made
routine visits to the control
rooms.
Inspection
observations
included
instrument
readings,
setpoints
and
recordings,
status
of operating
systems,
status
and alignments of emergency
standby
systems,
verification of onsite
and offsite
power supplies,
emergency
power sources
available for automatic operation,
the purpose of temporary
tags
on
equipment
controls
and
switches, annunciator
alarm
status,
adherence
to
procedures,
adherence
to
LCOs,
nuclear
instruments
operability,
temporary alterations
in effect, daily journals
and logs,
stack monitor recorder traces,
and control
room manning.
This inspection
activity also
included
numerous
informal discussions
with operators
and
supervisors.
General
plant tours
were conducted.
Portions of the turbine buildings,
each reactor building, and general
plant areas
were visited.
Observations
included
valve
position
and
system
alignment,
and
hanger
conditions,
containment
isolation
alignments,
instrument
readings,
housekeeping,
power
supply
and
breaker
alignments,
radiation
and
0
contaminated
area controls,
tag controls
on equipment,
work activities in
progress,
and radiological protection controls.
Informal discussions
were
held with selected
plant personnel
in their functional areas
during these
tours.
a
~
Water
Damage to ATU - Leaking Seismic
Gap
On
June
1,
1990,
unplanned
actuations
occurred
due
to
spurious
operations
of circuit cards
in the
ATU located in the
Unit 2 auxiliary instrument
room.
During
a test of the fire
protection
system
in the
cable
spreader
room located
above
the
auxiliary instrument
room, water ran through
a seismic
gap
and onto
the
top of the
ATU cabinets.
The
licensee
made
a four
hour
10 CFR 50.72 report to the
NRC concerning this event.
The sequence
of events of June
1,
1990 was
as follows:
Time
Event
1300
Air Test of Spreader
Room
A fire protection
was started.
1305
Water
leak in Unit 2 Auxiliary Instrument
Room.
1320
1326
1337
Unit
2
control
room
received
"Drywell
Pressure
Approaching
Scram" alarm.
Unit
2 control
room received
"ECCS Analog
Trip Unit Trouble"
alarm
and
permissive
alarms for ADS,
CS and
Emergency
DGs.
A,
C,
and
D
DGs automatically started,
System
I injection valve 2-FCV-75-25 opened,
Al
pump
automatically
started.
2-FCV-75-25
was
returned
to
the
closed
position by the plant operator.
ATWS/ARI logic channel
A operated.
The
ATWS/ARI logic initiated
a reactor
The licensee initiated an incident investigation
team to review the
event.
The sprinkler
heads
in the spreader
room had
been
replaced
with fast acting (lower temperature)
heads.
A post modification test
was
being
performed.
Whenever
an initiation signal
occurs,
a
preaction
admission
valve opens
and
charges
the normally dry piping
up to the sprinkler heads.
The heads
have
a fusible link which melts
at 165'F.
Those
heads
in the vicinity of the heat source
open
and
spray.
Prior to
a hydrostatic test of the heads,
a quick check
was
being
performed
using air.
The air blew
some
residual
water,
estimated
at
a maximum of ten gallons,
out
a broken sprinkler head.
0
The head
had
been
damaged after installation.
The water
came out the
damaged
head
and onto the floor and into the seismic
gap.
The seismic
gap is
a slip joint between
the Unit
1 and Unit 2 Control
Buildings.
The plate is free to move on one side
and at intervals is
tack
welded
on the other.
A piece of foam is
included
in the
spreader
room to make
the
gap
even with the floor.
The existing
design is not intended to be water tight.
The ATUs were installed approximately five years
ago.
By design,
the
conduit penetrations
through the panel
tops are not sealed.
The
ATU
cards
protrude
through
the front of panel
faces.
Their design
is
such that they are not water tight.
The auxiliary instrument
room is
considered
to be
a mild environment
and
no sealing is required.
Since this is
a significant actuation of ECCS,
an IFI will be open to
track resolution of the
problem.
This IFI is designated
259,
260,
296/90-18-01,
Interaction of ATU and Seismic
Gap.
Drawing Discrepancies
The inspector
reviewed the status of DDs on May 18,
1990.
There were
a total of 3,566 for all three units with 2,085 designated
as restart
for Unit 2.
Of the restart
DDs,
898
were
primary or critical
drawings
and
1187
were
secondary
drawings.
SDSP 2. 10, Controlling
Drawings,
defines
the
types
of drawings.
Primary
drawings
are
necessary
to start up,
operate,
and
shutdown
the plant.
Primary
drawings
are located in the control
room.
Critical drawings depict
system features
which are
used
by the plant Technical
Support Center
and
the
Chattanooga
Emergency
Control
Center
to determine
system
operation
and function.
Secondary
drawings
are all other drawings
that are not primary or critical.
The inspector discussed
with various plant operators
how the
DDs were
identified
on the plant drawings.
In the past,
drawings
had
been
"red-lined" to indicate
a
change
until
the
updated
drawing
was
issued.
The inspector could not determine
any method being used that
made
the operators
aware
of an existing
DD for a plant drawing.
These
discussions
included plant personnel
in the operations
support
group involved with preparation
of hold orders
to remove
equipment
from service.
The inspector
reviewed the plant procedures
and
a previous
commitment
to
a
NOV in IR 88-28.
Stated in the corrective steps
to the
NOY was
the closure
process
for DDs.
DDs initiated before
November 4,
1988
against Unit 2 required for restart
would be closed
before restart.
DDs after November 4,
1988 were required to be closed within 30 days
of receipt
by Nuclear Engineering.
The inspector
obtained
a computer
listing of the primary and critical drawing in 1989
on May 24,
1990.
Of 127 drawings
DDs only 61 were closed
and the average
closure
time
was
269 days.
Of 361 secondary
drawings, only 63 were closed
and the
average
closure
time was
354 days.
One
example of this problem
was
DD 2-89-0250 which was designated
a
" Unit 2 restart
primary drawing
on August 27,
1989.
This
DD was for
drawings
828E555AARl and
2-730E321-13A
R001.
The description stated
that
the
connection
designations
for the control
rod insert
and
withdraw block relays don't agree.
The inspector
concluded that the corrective action in response
to a
previous
NOV was not met and that the plant procedures
for timeliness
of resolution of DDs were not being followed.
Accordingly, this is a
deviation
from
a
commitment
made
in response
to
a previous
260/88-28-01,
Failure
to
Control
and
Correct
Known
Drawing
Discrepancies.
This is identified
as
DEV 260/90-18-02,
Failure to
Correct Drawing Discrepancies.
The
DD system
was
revised
in March
1990 to involve the
system
engineers.
Under the present
system
the
DDs are
now called
PDD,
Potential
Drawing Discrepancy.
A
PDD is first processed
by the
system
engineer
and if a
change is
needed
a
D-DCN is issued.
This
differs from the old system
where nuclear engineering
was primarily
involved.
However,
despite
the
change
the
time limits appeared
excessive
with
the
computer
aided
drafting
system
in
place.
Depending
on the type of drawing, the system engineer
could evaluate
the
PDD for
10 to
30
days with an additional
30 days for design
engineering
to issue
the
DD.
Meanwhile,
there
appeared
to
be
no
system to indicate the
PDD to the plant operators
while the drawing
was being revised.
A meeting
was
held with the Site Director, Plant Manager
and others
to discuss
on June
7,
1990.
The licensee
presented
the
Browns
Ferry
Drawing
Improvement
Program
and stated
that
DDs within the
DBVP boundaries
will be resolved
when
the
system
is returned
to
service prior to restart.
After a system is in service,
primary and
critical drawings will be corrected within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.
The inspector
stated
that
these
actions
should
be
addressed
in response
to the
deviation.
RHR Valve Body Erosion
On May 21, 1990, the licensee
discovered that the Unit 2
RHR outboard
loop injection isolation valve, 2-FCV-74-66,
had experienced
abnormal
degradation.
Wall thickness
was determined
by visual
inspection
to
be less
than the required
thickness of 1.57 inches.
A finger-sized
area in the valve body was found to have eroded to approximately 0.75
inches of the thickness.
UT data
on the
same
valve in the opposite
loop,
2-FCV-74-52,
indicated
areas
in the seat
area that were also
less
than the minimum wall thickness.
The licensee
plans to inspect
this valve before restart.
This condition is
documented
in
CARR
BFP900163.
The licensee
had performed this inspection in response
to information
contained
in General
Electric
RICSIL No.
034
and
which identified that significant wall
thickness
reductions
had
been
discovered
in similar valves
at other
facilities.
The valve
body erosion in those
cases
was believed to
have occurred
as the result of thrott1ing the globe valves
below the
design flow rate,
causing excessive
cavitation.
The inspector
reviewed
TVA engineering calculation,
MD-02074-900059,
which
documented
the
licensee's
initial determination
of minimum
acceptable
wall
thickness
for
pressure
retaining
components
associated
with this
case.
In that calculation
the
minimum wall
thickness
for the design
pressure
and temperature
of 1362 psig
and
562 degrees
was
1.575 inches.
However, the inspectors
were informed
by licensee
management
that the condition had
been further evaluated
and
determined
that the condition
was
considered
acceptable
on
an
interim basis
due to
an actual
expected
maximum operating
pressure
of 356
psig at the
valve rather
than
the design
pressure
of the
affected
portion of
RHR piping.
That pressure
would be the design
shutoff head of the
RHR pumps,
which .is considerably
less
than
1362
psig, resulting in a smaller required wall thickness.
Although the
licensee
required
the valve to be repaired
to return the valve body
to an acceptable
condition,
the licensee
believes this assumption
is
valid due,to
the
presence
of
a normally closed
inboard injection
valve and
LPCI check valve in each loop.
The inspectors will follow the licensee's
progress
in this area.
The
inspectors
are particularly concerned
with the results of the visual
inspection
of 2-FCV-74-52
and
the
licensee's
planned
corrective
actions
in this area.
This item will be tracked
as IFI 260/90-18-03,
RHR Valve Body Erosion.
System Pre-Operability Checklist
The inspector
reviewed
the licensee's
program for returning
systems
to service
following the
completion .of all
system modifications
required for startup.
These activities are controlled
by SDSP 12.7,
System
Pre-Operability
Checklist.
This
procedure
applies
to all
systems
or portions of systems
identified by the Plant
Manager
as
requiring
a Phase II SPOC or
a System Checklist.
In order to check out the program
and familiarize the staff with the
program,
the licensee
has selected
nine balance of plant systems
to
SPOC.
The systems
include extraction steam,
vacuum priming, building
heating,
and
demineralizer
backwash air.
As result of these
activities
39 Work Orders/Maintenance
Requests
and several
DDs were
identified.
These
items will require closure prior to turning over
the
systems
to operations.
The inspector will continue to observe
and review the licensee's
activities in this area.
0
0
4.
Modifications (37700,
37828,
72701)
The
NRC
inspector
reviewed
and
observed
the
Unit 2 modification
activities.
This included review of procedures,
discussions
with craft,
gC inspectors,
supervisors,
and managers,
observation of field activities,
and
reviews of
WPs,
DCNs,
and
ECNs.
The
reviews
and
observations
consisted of the following:
a.
High Potential
Cable Testing
(51063)
The licensee
completed
the wet conduit high potential testing of the
ten worst
case
conduits.
The licensee
identified six additional
anomalies
involving two conduits
as follows:
Conduit ES2051-IB contained
13 cables
with 63 total conductors.
Twelve cables
and
62 conductors
successfully
passed
the testing.
One cable, containing only one conductor,
1/C LS175-2 failed.
Conduit
ES2052-IB,
contained
27
cables
with
90 conductors.
Twenty-five cables
containing conductors
passed.
Five failures
in
2 cables,
3/C
LS182-A2
and
2/C LS191-A2, were identified.
This
damage
was apparently
caused
by
a missing
on the
conduit inside
a junction box.
The licensee
stated
that
none of the failures could
be attributed to
pullby damage
similar to that found at the
TVA Watts
Bar facility.
The licensee
also stated
that
none of the cable/conductors
involved
were encompassed
by the
10 CFR 50.49 requirements.
Since five conductors
failed
due to
damage
resulting
from missing
where
the
conduit joins the junction box,
the
licensee
decided
to inspect
approximately three-hundred
junction boxes
which
contain
electrical
cables
encompassed
by
the
requirements
to identify
any
missing
If any
are
identified,
then
the
cables/conductors
affect would
be evaluated
for additional testing.
b.
Post Modification Testing
The
NRC inspector
reviewed
the licensee's
activities in the areas
of
post modification testing.
This consisted of observations
of ongoing
tests,
review of initial data
and test results.
The specific areas
reviewed are
as follows:
(1)
The
inspector
attended
a licensee
meeting
at which
was
discussed.
The
present
modifications activities,
which are
being
performed in a bulk construction
mode, created difficulty
in identifying PMTs required to close out various
ECN/DCNs,
WPs
and
MRs.
The
BFN management
instituted
a
PMT group
made
up of
individuals
from different site
organizations
to coordinate
0
these activities.
The licensee
stated that the system engineers
have the responsibility for the conduct of PMT.
(2)
The
NRC inspector
reviewed
and
observed
portions of PMT-184,
ATWS/ARI.
The test
was written to verify the operation of the
ATWS in Unit 2.
The system functions tested
by the
PMT were:
Recirculation
Pump Trip
(RPT) - This function
reduces
reactor
power
by
tripping
the
recirculation
pump
end-of-cycle
(EOC) trip breakers.
Alternate
Rod Injection (ARI) - This function provides
an
alternate
way of initiating
a
by isolating
and
bleeding
down the air header
to scram valves
and the scram
discharge
volume isolation valves.
The
implementation
of the
ATWS/ARI was
through
ECN/DCNs
P7045,
P7089,
P7090
and
W5163.
The activities
consisted
of such
testing
as
channels
A and
B
ATWS in the Test Mode, channels
A
and
B in the
Normal
Mode,
Manual Initiation of ARI, and
Breaker Trip Test.
The
NRC inspector
reviewed the results of the following; Section
5.2,
Channel
A Test
Mode, Section 5.5,
Channel
B Normal
Mode,
and Section
5.9.RPT
Breaker Trip Test.
The following drawings
were reviewed
as part of the rest results
review:
2-47E2610-85-2
and
5
Unit 2, Mechanical
Control
Diagram
CRD Hydraulic System
2-47E820-2
and
7
2-45E670-13
and
19
Unit 2,
Flow Diagram Control
Rod
Drive Hydraulic System
Unit 2, Wiring Diagram
DIV I
and
DIV II Analog Trip Units
Schematic
Diagram
At the
close of this reporting
period
184
had not
been
completed.
Based
on
the
areas
observed
and
reviewed
no
significant deficiencies
were identified.
Field Activities
The
NRC inspector
observed
and
reviewed
the licensee's
activities
involved in the implementation of
DCN 6820A, which was initiated to
accomplish
the following change to the
EECW system:
Division
I
Motor Operated
Valve
2-FCV-67-21
was
powered
from
non-divisional
480V
RMOV Board
2C.
The starter
compartment
in Board
2C
was relocated
to
480V
RMOV Board
2A (Division I).
Cables
for
Valve 2-FCV-67-21 were 2ES475-I,
and
. 2ES480-I.
They were not required to be replaced
or rerouted
since
they did not terminate
at the
board
and
the
new design
did not
affect their routing.
This
DCN was issued to reroute or replace
the entire length of cables
and
In addition,
two motor starter
coils in the starter
relocated
to the
480V
RMOV BD 2A were replaced
with coils of a lower operating voltage.
The
DCN generated
WPs 2147-90 thru 2151-90,
which required activities
including:
WP 2148-90,
Implement the installation of new raceway
recovery
for the cable runs.
d.
WP 2151-90,
Implemented
the relocation of the
MOV.
The
NRC inspector
reviewed
the
DCN
and
the
WPs
and
observed
the
termination of the
cable
run at
the
480V
RMOV Board
2A.
The
inspector
noted that the
WP 2150-90
was
present
at the work site,
the craft
personnel
were
knowledgeable,
and
the
gC
inspector
performed the inspections
required
by the
MAI procedure.
In addition to the termination observation
the
NRC inspector
observed
portions of the
PMT as well as the trouble shooting performed
on the
local
NORMAL/EMERGENCY transfer
switch.
After installation,
the
valve did not perform
as required.
The
system
engineer
and craft
personnel
traced
the problem to the switch.
All activities observed
were
done
in
a controlled
manner,
by using
approved
procedures
and
with adequate
inspection activity.
Dresser
Coupling Failure
At approximately 2:00 p.m.
on May 29, 1990,
a Dresser
Coupling failed
on
an
18 inch diameter
section of piping in the
3B/3D
RHR Service
Water Tunnel.
The failed coupling
was
on the North
EECW Supply
prior to the Unit
3 Reactor
Building penetration.
The
failure occurred
during modification work on penetration
support,
3-47B451-R0015,
located
downstream of the coupling.
When the last of
the four thru-bolts
on
the
support
being
removed
was cut,
the
coupling failed, allowing the
18 inch header
to slide through
the
into the Unit 3 Reactor
Building.
Although the
two
sections
of piping joined by the Dresser
Coupling did not physically
separate
and
remained essentially intact,
the horizontal
movement of
one of the two sections
of pipe allowed large
amounts of
EECW water
to flow out of the coupling, into the
RHRSW tunnel,
and then outside
to
the
storm drains.
The
licensee
estimated
that
the total
piping movement
was approximately
3 inches to the north.
e
10
The support
removal
was
being
performed
as part of an effort to
upgrade
the piping penetration
in accordance
with
DCN W7630 and
WP
8490.
The failed coupling
had full length pipe-to-pipe
tension
and
compression
restraint rods,
but the'ods
were shortened
on April 12,
1990,
in accordance
with
DCN W8435
and
WP 2146-90.
At the time of
the coupling failure
DCN W8435
was still open
pending
inspection of
the coupling retention pins.
The inspection
could not
be performed
unti 1 the north
was taken out of service.
The
inspector
discussed
the practice of performing
work of this
nature with the system
in operation.
Although the licensee
had not
completed
the event evaluation
by the close of the reporting period,
one of the
contributing
factors
was failure
by modifications
personnel
to follow the
documented
work instructions.
Procedure
SDSP-7.9,
Integrated
Schedule
and
Work Control,
Section
6.4.1,
requires
that prior to
commencing
work activities that
have
the
potential
for affecting
equipment
operation,
which
may affect the
safe operation of the unit, that
a Plant Operation
Impact Evaluation
Sheet
be filled out.
It should specify operational
effects
on the
system of the planned
work activity, designation
of identified work
boundaries,
and
documentation
of approval
by Plant Operations
of
permission
to start work.
In this case
the Plant Operation
Impact
Evaluation
Sheet
had
been
approved
by operations
for the south
only with
a note to notify the
SOS prior to starting work on
the north header.
The caution
"Hold Order for South
Header Only" was
written directly
on the Plant
Operation
Impact Evaluation
Sheet.
Therefore
the modifications
crew commenced
work on the north header
without
proper
approval
in
accordance
with
SDSP-7.9.
This
constitutes
a violation
and will be tracked
by VIO 260/90-18-04,
Failure to Control Modifications Activities.
Due to the significant
number of personnel
errors
that
have
occurred
by the modifications
section
during the last year, this event
can not'be considered for a
non-cited violation.
The inspector
noted during review of recent
trending
data
on
personnel
errors
by site
personnel,
that
modifications personnel
have continuously contributed to at least
50K
of the total identified errors
on
a monthly basis
during the period
October
1989 - May 1990.
In addition to the licensee's
failure to control modification work
activities, the inspectors
have the following concerns:
There
exists
some
question
about
whether
the retention
pins
were functional at the time of the failure or if the pins would
have prevented
the failure.
There
seems
to
be
some question
concerning
the adequacy
of the
sequence
of the criteria used to control
removal of the supports.
Since the event is still under investigation
and the event report has
not
been
issued,
review of this will be performed with the closure
of the violation.
0
11
- The inspectors
are
concerned
that although this portion of the
System
was not needed
to support safety-related
equipment required
by
Technical
Specifications
the
event
constituted
a
significant
breakdown
in the licensee's
program for reviewing
and screening
of
modification work.
Additionally, had
the
two sections
of piping
completely separated,
the craft personnel
performing the work could
have suffered injury.
Licensed Operator Training (41701)
An inspector
monitored
portions
of the
scheduled
licensed
operator
requalification training conducted
during the
week of May 21-26,
1990.
The classroom
instruction that were monitored covered restart training on
completed Unit 2 modifications
and reactor water level instrumentation.
The
inspector
was
informed
by
the
licensee
instructor
that
the
modifications
taught
were
those
completed
modifications
that
management
considered
significant,
which
changed
the operation
of the
plant
and directly affected
the operators.
No effort was
made to list
all modifications
completed
during the extended
shutdown period,
as those
are
covered
by the licensee's
required
reading
program.
The inspector
noted that for those
selected
modifications
covered,
the material
was
adequately
presented
to reflect
how the unit has
changed,
as well as
how
the
respective
change
to
the
hardware
affected
the
duties
of the
operators.
Each modification
was
addressed
individually by
ECN with the
purpose
and brief description
provided to the operators.
Simplified
diagrams
based
on revised
plant drawings
were
used
to explain
hardware
changes
and
changes
in the
system
and
component
operations.
The
instructor
emphasized
that
many of these
changes
were
the result of
problems
with the original
har dware
design that were identified during
restart testing.
Classroom instruction
was also presented
on modifications to reactor water
level instrumentation,
including the relocation of all reference
legs to
outside
the drywell.
A separate
lecture
was also given
on the current
design of the
RPV water level instrumentation
including the operation of
the
Analog Trip System.
The inspector
noted that this portion of the
classroom instruction
was adequate
to provide the operator with sufficient
information to recognize
and properly diagnose
various malfunctions that
could occur in the level
instruments.
Application of current Technical
Specification
requirements
to potential
instrument
malfunctions
was
conducted.
No violation or deviation were identified.
Reportable
Occurrences
(92700)
The
LERs listed
below were
reviewed
to determine if the
information
provided met
NRC requirements.
The determinations
included the verifica-
tion of compliance with TS and regulatory requirements,
and addressed
the
adequacy
of the
event description,
the corrective
actions
taken,
the
0
12
existence
of potential
generic
problems,
compliance
with reporting
requirements,
and
the
relative
safety
significance
of
each
event.
Additional in-plant
reviews
and
discussions
with plant
personnel,
as
appropriate,
were conducted.
a
~
(CLOSED)
Unplanned
Due to Failed Relay.
On March
14,
1990,
a
blown fuse
in the Unit 3
PCIS logic panel
resulted
in the actuation
of engineered
safety features,
including
SBGT and Control
Room Emergency Ventilation actuations
and Refueling
Zone Ventilation isolation.
b.
No
The licensee's
investigation of the event
revealed
that the
blown
fuse occurred
due to failure of a relay in the
PCIS logic circuitry.
The failed relay
and
blown fuse
were replaced
and
the
PCIS logic
reset.
The relay that failed
was
type
MG-6 relay
which failed
due to
a burnt coil.
The licensee
considered
this
failure as
an isolated
case.
Although other events similar to this
had occurred before,
no record of any failure of this type of relay
at Browns Ferry could
be found.
Additionally, the licensee
searched
the
data
base
and
consulted
with the vendor.
Both
indicated that this type of relay
had
a
good performance
history in
the industry.
The inspector
reviewed the licensee's
LER submittal
and Event Report
II-B-90-032,
and
held discussions
with various
licensee
personnel
associated
with this
event.
The
inspector
determined
that
the
licensee's
evaluation
of this event
was
adequate.
This
item is
closed.
(CLOSED)
Installation
of
New
Without
Functional Testing.
This
event
was
identified
by
the
licensee
and
concerned
the
installation of 99 new mechanical
installed
between
1982 and
1985 which were not functionally tested
before their installation.
This event
was
caused
by an unclear
procedure
that did not specify
post-modification
testing for
new
There
is
no clear
regulatory,
code, or plant administrative
requirement to functionally
test
new snubbers
before installation.
There is
a test requirement
for reworked snubbers.
The intent is to validate the functionality
of any snubber prior to installation in the plant.
The licensee
has
revised
the
procedure
to meet this intent.
For the
99 identified
installed
in the plant,
a
sample of 10 were functionally
tested
and
no problems
were identified.
The entire
group
has
been
added
to the population of existing snubbers
for functional testing
in accordance
with TS ISI requirements.
This
LER is closed.
violations or deviations
were identified.
0
13
7.
Action on Previous
Inspection
Findings
(92701,
92702)
a ~
(CLOSED)
IFI 259,
260,
296/89-17-04,
Changes
That
Require
Update.
This
item
was identified during
an
inspection of the licensee's
transitional
design
change
program review area.
The inspector
noted
that
FSAR updates
would not occur until the
ECN/DCNs affecting
updates
were closed
out.
The closure
process
of ECN/DCNs at
BFNP
could take several
months
and could possibly hold
up an
FSAR update
for an unreasonable
amount of time.
b.
co
d.
The licensee
changed
the applicable
procedure
to ensure that the
update
process
would start
as
soon
as
the system return to service
activity was
completed
rather
than
the
ECN/DCN closure activity.
This item is closed.
(CLOSED) IFI 259, 260, 296/89-35-02,
Storage of gA Records.
During
a review of the licensee's
program for handling
and storage of
completed
and approved test results,
the inspector
noted
a potential
conflict concerning
temporary
storage
of
gA records
that existed
between
the 'SAR commitment described
in TVA-TR75-1A, Revision 10,
Table
Sheet
7,
and
the requirements
specified
in SDSP-2.5,
guality Assurance
Records.
The
inspector
reviewed
ANSI
N45.2.9-1979Property "ANSI code" (as page type) with input value "ANSI</br></br>N45.2.9-1979" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process.,
Requirements
for
Collection, Storage,
and Maintenance of (}uality Assurance
Records for
Nuclear
Power Plants,
various
documents
provided
by the licensee,
and
held discussions
with licensee
management
personnel.
Based
on this
review the inspector
determined
that
no conflict exists
between
the
FSAR commitment and SDSP-2.5.
The licensee's
program
as described
in
these
documents
complies
with
This
item is
closed.
(CLOSED)
URI 260/89-06-04,
Testing
DGs at Rated
Loads.
This
item
was initially identified during
a review of procedure
O-SI-4.9.A. la (A), Diesel
Generator
A Monthly Operability Test,
and
involved the acceptance
criteria of 2600
KW, plus or minus
50
KW.
The
URI was written because
the
BFNP
have several
ratings
such
as:
3050
KW for 30 minutes
per year,
2950
KW for 7 days
per year,
2850
KW for
2000
hours
per year,
and
2600
KW continuous.
The
licensee
changed
the
TS
and
SI to indicate that the
DGs would
be
tested
at the continuous
rating or greater for at least
one hour.
The inspector
did not consider this
a violation because
the
DGs were
adequately
tested.
This item is closed.
(CLOSED)
URI 259,
260, 296/89-19-01,
Possible
Failure to Adequately
Control
Work Activities Involving Systems
Important to Safety.
e
. This
item was identified
as
a result of
a walkdown of the intake
structure
when manhole
cover hold
down bolts were discovered
missing
in
Rooms
A
and
D.
The
licensee
reviewed
the event
and
initiated
a
LER due to loss of flood protection for the rooms.
It
was also
noted that the hold down bolts were required to be made of
brass
and that the bolts in rooms
B and
C did not appear to be made
of brass.
The inspector
reviewed
MRs 911334,
911335,
911339,
911340,
911341,
911342,
819580,
and 819581 which documented
the installation of brass
bolts
on the manhole
covers
in the
RHRSW Rooms.
The inspector also
walked
down
rooms
B and
C and
noted that all the hold down
bolts for the four manway covers,
two per room,
appeared
to be made
of brass.
Each
manway cover had
a label which stated that this flood
protection
cover
was
not
be
removed without the permission
of the
SOS.
The inspector
did not consider this
a violation because
at
no time
were all flood protection
manway covers
removed.
Additionally, the
non-brass
hold
down bolts were in place for only
a short time until
brass
bolts could
be obtained.
This item is closed.
'.
(CLOSED)
URI 259,
260, 296/89-33-02,
TS
LCO Exceeded for Standby
Gas
Treatment
System.
This
item concerned
whether
the
LCO for
SBGT required
under
TS 3.7.B.la
and 3.7.B.3
had
been
exceeded.
The
TS required all three
trains of SBGT to be operable at all times
when secondary
containment
is required,
except that
one
SBGT train may
be inoperable for seven
days during reactor
power operation
or fuel handling activities.
If
these
requirements
cannot
be met,
TS 3.7.B.4 required that the unit
be placed
in
a condition where
SBGT is not required.
The licensee
interpreted
this
LCO to
mean
the
seven
day exclusion
applied only
during power operation or while conducting activities
above the fuel
pool.
To eliminate
any ambiguity for the
SBGT system
and
the
secondary
containment,
the licensee
revised
the
TS to eliminate the reference
to primary containment integrity.
The revised
TS also
includes
the
GE Standard
TS
LCO actions
when the
The
inspector
has
reviewed
the revised
TS
and
found it acceptable
to
preclude misinterpretation.
Under the revised
TS
a violation would not have occurred.
There
was
no safety significance to this event
due to the extended
shutdown
and
although
the original
LCO may have
been
exceeded, it was only by 20
minutes
in
a
seven
day
LCO.
The licensee
was very responsive
and
took prompt and complete corrective action by revising the TS.
Based
on the ambiguity of the original
TS and the above corrective action,
a violation will not be issued
and this
URI is closed.
0
0
15
(CLOSED)
VIO 296/85-13-01
Failure
to
Shutdown
With
Two Reactor
Protection
System
Water Level Instruments
Following
an
inspection
conducted
to determine
the
circumstances
surrounding
the inoperability of two Unit 3
RPS Reactor
Water Level
Instruments
(LIS-3-203 A, B) during
a reactor startup
on February
13,
1985, it was determined
that the responsible
licensee
personnel
did
not
commence
a reactor
shutdown in accordance
with required actions
stated
in Technical
Specification
3. 1, Table 3. 1.A.
T.S. 3.1 states
there
shall
be
two operable
or tripped
systems
for each trip
function. If the minimum number of operable
channels
per trip system
cannot
be
met for both trip systems,
the licensee
shall initiate
insertion of all operable
control
rods
and complete insertion of all
rods
within four
hours.
Even
though
there
existed
sufficient
redundant
information
which
should
have
alerted
the
operators
that two required water level switches
were inoperable,
the
licensee
did not
shutdown
and
continued
power escalation.
The
reactor
was eventually
shutdown
on March 9, 1985, to conduct further
investigations
required
by
TVA management
following review of the
circumstances
associated
with the event.
This resulted
in the
NRC
issuing
a
severity
level II violation with
a civil penalty
(EA-85-51).
The
inspector
reviewed
the licensee's
responses
to the violation
along with various
documents
and records
provided by the licensee
to
support
completed corrective actions
in this area.
That review is
documented
in Inspection
Report 89-35, with this item remaining
open
pending
further
review
by
the .inspector
of additional
planned
licensed
operator training and site management's
response
to several
identified concerns
documented
in the licensee's
Unit 2 Operational
Readiness
Review Interim Report dated
June 9,
1989.
The inspector
reviewed
the licensee's
internal
response
to the
ORR
Interim Report dated
October 30,
1989,
and the
Phase
Two
ORR Report
dated
March 9,
1990.
Additionally, the inspector monitored training
for licensed
operators
on
RPV water level
as
documented
in paragraph
five.
The inspector
determined that all concerns
identified in the
above inspection report
have
been adequately
addressed.
This item is
closed.
(CLOSED)
VIO 259,
260,
296/87-38-01,
Deficiencies
in Division of
Nuclear Engineering
(DNE) Training Program.
During a special
NRC team inspection
conducted
in the licensee's
offices
in Knoxville, TN,
an
inspector
identified that
licensee
Individual Training Records
(ITRs) were not being maintained
as
gA
documents
as
required
by
Appendix B, Criterion XVII and
the
licensee's
NIZAM.
During that inspection
licensee
personnel
stated
that
those
requirements
were
satisfied
by
the
course
attendance
rosters
rather than the ITRs, however the licensee
was not
able
to produce
rosters
to document
completion of training matrix
0
16
. requirements
for selected
individuals
during
a
followup visit
conducted
by the inspector.
The
inspector
reviewed
the
licensee's
original
response
to
the
violation dated April 22,
1988.
In that response
the licensee
stated
the
reason
for the violation
was
inadequate
management
attention
resulting in the failure to implement procedure
requirements,
poorly
worded or misunderstood
procedures,
and incorrect identification of
required training
on training matrices.
Specific corrective actions
and recurrence
control measures
were detailed to address
the problems
with full compliance to be achieved
by August I, 1988.
Subsequent
to
the
licensee
response,
the
licensee
reorganized
to the existing structure
with the 'older
DNE organization
being
replaced
by
NE.
Additionally,
EA Audit KXE89901,
was
performed
by
the licensee,
which identified an overall weakness
in
NE training that
was similar to the condition cited in the
above violation including
recurrence
of the
same
problems.
The recurrence
of the
problems was weported
by the licensee
to the
Region II office on January
27,
1989,
and various licensee
CA(Rs were
generated
to document
the audit findings.
This resulted
in the
licensee
submittal
of
a revised
response
to the violation.
The
inspector
reviewed
the licensee's
revised
response
to the violation
dated
October
18,
1989.
In that
response
the licensee
stated
the
reason
for the failure
was that
the
recurrence
control
measures
implemented
by the
licensee
had
been
ineffective
and corrective
action insufficient.
There
had
existed
a continuing
lack of
management
attention
and accountability for ensuring
NE personnel
received
and
documented
training- as
required
by
NE procedures.
As
additional
corrective
actions
the
licensee
committed
to
the
following:
Assignment of a Manager of Training for NE.
His responsibili-
ties
would
include
identification of required
training,
verification that required training records
are maintained,
and
ensuring that
NE management
personnel
periodically certify that
training matrices
and records of required training are current.
Revise
Nuclear Engineering
Procedure
(NEP) - 1.2, Training, to
identify the Manager of Training's responsibilities
among other
additional
requirements
designed
to
more clearly define
NE
management
personnel's
responsibilities
in implementing
NIZAM
requirements.
Performance
of
an
audit
by
the
Nuclear
equality
Assurance
organization to verify implementation.
The licensee further stated that full compliance
would be achieved
by
March 5,
1990.
This commitment to the
NRC was again revised
by TVA
letter dated
March 16,
1990, to allow time for final confirmation of
records
by TVA.
17
.
The inspector
reviewed
CAQR BFK890207904,
which had
been written for
the
Browns Ferry site to address
the programmatic
aspects
associated
with various other
CAQRs which had resulted
from the above
licensee
QA Audit. Additionally, the inspector
reviewed
NQASE Audit Report No;
BFA90010 dated
February
16,
1990, which was performed to verify the
adequacy
of the site training and qualification programs.
Included
in the audit plan
was
a review of training for site
based
design
engineers
and
support
personnel
and
possible
verification
of
corrective
action
and closure of
CAQR BFK890207904.
During the
evaluation,
the audit
team
found that although
the training matrix
had
been
updated
and efforts to update
ITRs were evident,
the effort
was
not complete.
ITRs
were out-of-date
due
to
problems
with
maintaining
current
required
reading.
As
a result of these
problems,
the licensee
audit
team could not close
the
CAQR.
This
audit
had
been
completed
on January
17,
1990,
but was
reopened
due
to the licensee
management
decision that the audit had occurred
too
early because
the
new program
was not yet fully implemented.
After
the issue
was readdressed,
a followup audit was completed
on March 7,
1990,
and resulted
in NQASE's determination that adequate
corrective
action
had occurred.
The
inspector
reviewed
the licensee's
program
and
determined
that
although
the
newly assigned
training coordinator
was not dedicated
solely to maintenance
of training
and
could not devote
the
time
necessary
to
manage
the
program,
licensee
management
has
more
properly placed the responsibility for administration of the training
with line
management,
thus
eliminating
the
need
for
a training
coordinator.
The inspector
reviewed Revision
3 to
NEP 1.2, Training,
and determined
that the procedure
established
adequate
controls for
training of NE personnel.
This item is closed.
No violations or deviations
were identified.
8.
TMI Action Items
a 0
(CLOSED) 259,
260,
296/TMI Action Item II.F.1.6, Containment
Monitor.
This
item
was
to review implementation of
a
monitoring
system for monitoring the containment
atmosphere.
In IR 82-07 it was
stated that
a system which indicates
continuously in the control
room
during reactor operation
had
been installed.
The only remaining item
outstanding
was
to replace
the Unit 3
sample
return
pump with
a
higher capacity
pump.
NRC Safety Evaluation,
dated
June
16,
1983,
concluded
that the requirements
of TMI Action Item II.F.1.6
have
been met.
NRC Generic Letter 83-26, dated
November 1, 1983, provided
recommended
TSs for TMI Action Item II F. 1.6.
TVA letter,
dated
e
18
. March 7,
1984,
responded
and stated
that
Units 1,
2,
and
3
had
adequate
TSs for the
containment
monitors.
The work for this modification
was
completed
under
P0315
and workplans
10054,
10039,
7885,
10048,
6721,
and
6722.
The
inspector
reviewed
the
applicable
correspondence
concerning
this
item.
Based
on
IR 82-07, TS,
and installation of the equipment, this
item is closed.
b.
(CLOSED)
260/TMI Action
Item II.F.1.3,
Containment
High-Range
Radiation Monitor.
This item was to review actions
taken
in response
to requirements
for
a
containment
high-range
radiation
monitor.
Technical
Specification
Amendment
125,
dated
August 19, 1986,
was
issued
which
incorporated
the limiting conditions for operation
and surveillance
requirements
for the
drywell radiation
monitors.
The
licensee
notified the
NRC on February
16,
1990, that for Unit 2 the design
had
been
finalized,
equipment
installed,
procedures
issued,
and all
necessary
training
completed.
The work for this modification
was
completed
under
P0324.
The
inspector
reviewed
the monitor
indication and annunciator
alarm in the control
room.
The indication
is
on
panels
2-9-54
and 2-9-55,
Containment
Atmosphere
Monitoring
Panels.
The alarm is
on panel
2-9-7.
This item was discussed
with
plant operators
on shift,
who were knowledgeable of the instrumenta-
tion and alarm.
Based
on this review and discussion
with NRR, this
item is closed.
9.
Exit Interview (30703)
The inspection
scope
and findings were
summarized
on June
18,
1990 with
those
persons
indicated
in paragraph
1 above.
The inspectors
described
the areas
inspected
and discussed
in detail the inspection findings listed
below.
The licensee
did not identify as proprietary
any of the material
provided
to or
reviewed
by
the
inspectors
during this
inspection.
Dissenting
comments
were not received
from the licensee.
Item Number
259,
260, 296/90-18-01
260/90-18-02
260/90-18-03
260/90-18-04
Descri tion and Reference
IFI, Interaction of
ATU and
Seismic
Gap,
paragraph
3.
DEV,
Failure
to
Correct
Drawing
Discrepancies,
paragraph
3.
IFI,
RHR Valve Body Erosion,
paragraph
3.
VIO,
Failure
to
Control
Modifications
Activities, paragraph
4.d.
0
0
19
ANSI
ATU
BFNP
CAQR
CFR
DBVP
DCN
DEV
IFI
IR
ITR
KW
LCO
LER
NE
NQASE
NQAM
NRC
ORR
PDD
Automatic Depressurization
System
American National Standards
Institute
Alternate
Rod Injection
Analog Trip Units
Anticipated Transient Without Scram
Browns Ferry Nuclear Plant
Boiling Water Reactor
Condition Adverse to Quality Report
Code of Federal
Regulations
Control
Rod Drive System
Design Baseline Verification Program
Design
Change Notice
Drawing Discrepancy
Deviation
Diesel
Generator
Division of Nuclear Engineering
Engineering
Assurance
Emergency
Core Cooling System
Engineering
Change Notice
Emergency
Equipment Cooling Water
End-of-Cycle
Engineered
Safety Feature
Flow Control Valve
Final Safety Analysis Report
Inspector
Followup Item
Institute of Nuclear
Power Operations
Inspection
Report
Individual Training Records
Kilowatt
Limiting Condition for Operation
Licensee
Event Report
Low Pressure
Coolant Injection
Motor Generator
Maintenance
Request
Non-Cited Violation
Nuclear Engineering
Nuclear Plant Reliability Data System
Nuclear Quality Assurance
8 Engineering
Nuclear Quality Assurance
Manual
Nuclear Regulatory
Commission
Operational
Readiness
Review
Primary Containment Isolation System
Potential
Drawing Discrepancy
Post Maintenance/Modification
Test
Quality Assurance
l
0'
20
SDSP
SOS
TS
WP
Quality Control
Residual
Heat Removal
System
Residual
Heat Removal
Reactor Protection
System
Recirculation
Pump Trip
Reactor
Pressure
Vessel
Restart Test Program
Standby
Gas Treatment
System
Site Directors Standard
Practice
Surveillance Instruction
Shift Operations
Supervisor
System Preoperability Checklist
Technical Specifications
Valley Authority
Unresolved
Item
Ultrasonic Testing
Violation
Work Order
Work Plan
Work Request
-1
0