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From YouTube: NTSB Public Meeting Day 3 March 3, 2011
Description
NTSB Public Meeting Day 3
March 3, 2011
Natural Gas Pipeline Explosion and Fire
San Bruno, CA September 9, 2010
A
B
Please
raise
your
right
hand,
do
you
swear
or
affirm,
to
tell
the
truth?
Thank
you.
Please
be
seated
for
the
record.
We
have
mr
jeff
foreman,
mr
charles
dippo,
miss
curtin,
christina
sames,
mr
frazier
farmer,
mr
robert
smith,
mr
joshua
johnson
and
mr
allen,
mayberry
on
the
panel
and
we'll
start
with
mr
jeff
foreman.
If
you
could,
please
state
your
full
name
title
and
a
brief
description
of
your
duties
and
responsibilities.
C
E
B
And
ms
james,
I'm
christina
sames
vice
president
of
operations
for
the
american
gas
association,
my
responsibilities
include
pipeline
safety
and
other
safety
initiatives.
The
aga
best
practices
program,
interaction
with
others,
such
as
other
stakeholders
like
the
common
ground
alliance,
our
regional,
national
and
international
gas
associations,
and
about
anything
else
they
want
to
throw
on
my
plate.
G
Thank
you
good
morning
my
name
is
fraser
farmer.
I'm
the
owner
of
a
small
company
called
pipelink
associates
my
work.
History
has
been
with
transcanada
pipe
for
many
years
in
engineering
activities,
then,
with
a
company
called
pipetronix,
which
was
in
the
ili
space
pipetronix
was
acquired
by
the
pii
company,
which
was
acquired
by
ge.
So
my
background
in
inline
inspection
has
been
utilized.
Since
then,
in
putting
on
workshops
and
web
conferences
in
the
sga
activities
in
inline
inspection
and
integrity
management,
I
hold
a
degree
in
electrical
engineering.
Thank
you,
mr
smith.
I
J
Good
morning,
I'm
alan
mayberry
with
the
office
of
pipeline
safety,
I'm
the
deputy
associate
administrator
for
field
operations
for
about
the
last
year.
In
those
responsibilities,
I
cover
our
national
inspection
programs
through
our
five
regional
offices
and
also
our
emergency
response
and
security
functions.
B
K
Thank
you.
Thank
you
all
for
participating
in
our
panel
today.
I
appreciate
it
I'd
like
to
start
with
mr
mayberry.
As
the
chairman
noted
yesterday,
films
of
regulations
require
pressure.
Testing
for
new
construction
and
pressure.
Testing
is
also
one
of
the
possible
methods
identified
for
pipeline
integrity
management.
J
Are
you
referring
to
a
new
pipeline?
Yes,
a
new
pipeline.
Okay,
a
new
pipeline
would
be
constructed
and
upon
completion
of
the
construction
process.
There's
the
strength
test
requirement
according
to
the
regulations,
what
we
call
subpart
j
test
for
class
3
pipeline
that
would
involve
testing
the
pipeline
at
one
and
a
half
times
the
anticipated
maximum
allowable
operating
pressure.
K
J
K
J
Certainly,
probably
the
main
example
would
be
post
failure.
If
there's
been
a
pipeline
incident,
where
you
have
a
release,
it
may
be
one
of
the
requirements
of
of
a
return
to
service
to
verify
the
integrity
of
the
of
the
pipeline.
It's
one
of
many
tools
mind
you
that
there
are
other
tools
that
I'm
sure
we're
going
to
talk
about.
Like
inline
inspection.
There
are
other
inspection
methods
and
it
depends
on
the
issue,
but
we
have
had
cases
in
corrective
action
orders
which
are
one
of
our
enforcement
actions.
J
When
there
is
an
incident
where
we
deem
a
pipeline
to
have
a
perhaps
an
imminent
hazard
where
to
continue
operation
without
some
sort
of
remedial
action,
we
would
issue,
what's
called
a
corrective
action
order
that
could
include
provisions
for
further
in
line
inspections
or
hydrostatic
testing.
I'll
give
you
an
example
a
couple
of
years
ago
in
2007.
J
Actually,
there
was
a
failure
on
a
natural
gas
pipeline
in
the
midwest
failure
was
attributed
to
selective,
seam
corrosion
type
of
feature
that
is
preferential
to
a
certain
type
of
pipe
coated,
a
certain
way
that
we
have
corrosion
that
occurs
along
the
seam
of
a
pipe.
In
that
situation,
we
required
hydrostatic
testing
because
there
had
been
a
couple
of
failures
on
that
line,
but
then
also
we
we
also
included
in-line
inspection.
J
That's
just
one
example:
okay,
we've
also
done
it
primarily
it's
it's
common
with,
say
liquid
pipelines,
where
we
would
require
it
as
a
follow-up
action
and
also,
I
might
add
too,
that
typically
in
a
corrective
action
order
or
safety
order,
we
may
include
a.
We
would
include
a
requirement
for
a
long-term
integrity
verification
plan,
which
leaves
which
requires
the
operator
to
determine
the
most
appropriate
method
to
assess
the
integrity
of
the
pipeline.
J
K
J
We've
that
is
a
factor
that,
when
you're
considering
pressure
testing
of
vintage
pipelines,
that
that
would
need
to
be
considered
in
in
reviewing
our
incident
history
on
a
phenomenon
known
as
pressure
reversal,
which
is
a
situation
that
happens
when
you
hydrostatically
test
a
pipeline
and
then
a
subsequent
test
is
performed
and
the
pressure
the
pipeline
may
fail
at
a
lower
pressure
than
the
first
hydrostatic
test.
That's
very
simply
put
what
is
referred
to
as
a
pressure
reversal.
J
Those
typically
are
done
where
those
are
experienced.
We
may
not
know
about
those,
however,
I
do
have
in
2008
there
was
a
liquid
pipeline
failure
that
involved
a
pressure
lower
than
a
hydrostatic
test
that
had
been
performed
about
four
years
earlier:
okay,
so
but
but
the-
and
there
is
some
documentation
available
out
there
on
this
phenomenon.
J
L
J
Well,
as
you
know,
with
the
integrity
management
program,
which
represent
a
paradigm
shift
in
in
our
regulations
back
when
they
were
promulgated,
requires
the
operator
to
determine
the
best
assessment
method
that
may
include
hydrostatic
testing.
It
may
also
include
inline
inspection,
but
there
are
operators
who
do
choose
to
do
hydrostatic
testing
as
an
integrity,
verification
method.
K
Okay,
thank
you.
I'd
like
to
switch
gears
a
little
and
address
some
questions
to
mr
johnson,
basically
well.
Fems
and
regulations
also
refer
specifically
to
direct
assessment
methods
as
tools
to
ensure
pipeline
integrity.
Could
you
give
us
an
overview
of
the
direct
assessment
methodology
for
external
corrosion
and
internal
corrosion.
I
All
the
direct
assessment
programs
involve
a
a
four-step
process.
The
first
process
is
a
pre-assessment
step
where
you
gather
in
all
the
available
data,
and
you
come
back
and
look
and
see
what
methodologies
would
be
helpful
and
what
your
threats
are
and
then
also
what
you.
What
what
your
condition
your
line
is
in
and
from
that
you
then
go
out
and
look
with
direct
inspection
steps
which
are
tools
in
external
corrosion,
direct
assessment
that
you
look
for
essentially
places
where
coding
has
been
damaged
and
then
by
choosing
the
areas
with
the
worst
coding
damage.
I
You
go
out
for
the
third
step,
the
direct
examination
and
dig
up
areas
and
look
to
see
if
there
is
actual
corrosion
at
those
areas.
Instead
of
just
coating
laws.
And
finally,
you
bring
it
all
back
into
a
post
assessment
and
re-evaluate
everything.
And
then
the
process
just
keeps
on
rolling
and
rolling
through.
I
For
the
internal
corrosion,
the
the
big
difference
is
that
the
there
are
not
tools
to
look
for
the
in
for
the
for
coating
damage
since
we're
looking
inside.
So
there's
not
a
coating
damage
issue.
So
what
we're
looking
for
instead
is
and
internal
corrosion.
Direct
assessment
can
only
be
used
on
on
lines
that
normally
don't
contain
any
water,
but
occasionally
some
might
get
into
the
system.
I
I
Yes,
the
the
the
methodology
that
has
been
put
in
place
has
a
a
number
of
digs
that
have
to
be
done,
including
one
at
an
area
that
they
you
don't
expect
to
have
anything.
So
you
would
look
there
and
hopefully
not
have
something,
and
if
you
do
then
there's
an
obvious
problem
with
how
you've
done
your
methodology.
K
So
you're
checking
your
process
and
and
checking
your
your
assumptions
and
checking
your
results
in
effect.
Is
there
any
kind
of
a
a
metric
that
might
be
used
to
quantify
the
effectiveness
of
the
direct
assessment?
In
a
sense,
the
you
expect.
A
hydrostatic
test
to
you
know,
identify
100
of
defects
that
would
fail
below
the
test
pressure,
but
not
give
you
any
information
about
sub-critical
defects.
Is
there
any
kind
of
metric
associated
with
the
direct
assessment
methodology.
I
Well,
there
are
a
couple
of
things
one,
and
this
is
one
of
the
advantages
that
direct
assessment
shares
with
ili
tools.
Is
that
they're
they're
data
driven
so
that
you
can
come
back
when
you
do
your
next
one
and
the
data
from
the
first
one
is
still
there,
and
so
you
can
make
a
comparison
to
see
if
things
have
been
changing.
The
other
thing
that
has
been
done.
I
There
are
some
industry
groups
in
particular
that
have
looked
at
areas
where
they've
been
doing
direct
assessment
and
that
they've
done
ili
and
they've
compared
those
to
see
if
how
those
match
up.
If
the
areas
that
you're
finding
the
worst
d,
a
things
you're,
also
finding
the
worst
corrosion
by
ili.
K
I
Certain
coatings
make
make
this
difficult
rocky
areas
where
you
might
have
lots
of
rocks,
make
it
difficult
when
we
put
pipes
in
under
roads.
It
changes
things,
and
these
are
all
these
are.
All
things
have
to
be
looked
at
as
part
of
the
the
steps
in
the
d,
a
process
to
evaluate
that,
and
in
some
areas,
d,
a
is
not,
is
either
very,
very
difficult
to
do
or
might
not
be
an
appropriate
tool.
Because
of
that.
K
M
Good
morning
in
this
session,
I
will
be
asking
several
questions
on
the
capability
of
inline
inspection
tools.
My
first
question
will
be
directed
to
mr
jeff
foreman.
Can
you
give
me
some
examples
of
what
type
of
flaws
you're
looking
for
in
pipelines
when
you're
sending
your
in-line
inspection
tools.
M
D
C
C
A
typical
smart
pig
will
take
samples
of
a
pipe
every
1
8
of
an
inch
along
its
entire
length
and
360
degrees
around
its
circumference
in
one-quarter
inch
intervals
after
the
data
has
been
collected
on
the
tool
and
retrieved
complex
data
interpolation
occurs
to
under
this
understand
this
process.
An
analogy
to
medicine
might
help
similar
to
an
x-ray
as
a
cat
scan
or
mri.
C
The
quality
of
the
data
and
the
definition
of
the
images
supplied
really
depend
on
the
type
of
equipment
that
is
used.
The
ili
vendor,
like
a
radiologist,
uses
this
experienced
proprietary
software
and
seismic
algorithms
to
generate
a
report
that
identifies
the
dimensions
of
cracks,
metal
loss
and
other
physical
features.
C
C
The
ability
of
crack
inspection
to
identify
the
presence
of
cracks
has
been
well
established.
However,
the
industry
has
demanded
that
inline
inspection
vendors
not
only
identify
cracks
but
also
provide
dimensions.
This
requires
very
sophisticated
and
sensitive
high
technology
tools
which
have
been
developed
and
are
continually
being
refined.
C
C
The
most
advanced
ultrasonic
tool
is
the
phased
array
device,
which
I
will
explain
in
much
more
detail
later
for
gas
pipelines,
gas
crack
detection
historically
has
relied
on
the
transverse
field
magnetic
inspection
tools,
the
newest
technology
suitable
for
crack
detection
and
gas
pipelines.
Today
is
the
e-mart
tool
which
I'll
describe
in
more
data
late
in
a
later
slide.
C
This
slide
identifies
the
various
detection
capabilities
in
action
and
accuracy
specifications
each
needs
to
be
considered
in
the
tool
selection
process,
for
example,
if
you
know
that
the
higher
accuracy
of
the
emac
tool
to
for
crack
detection
and
sizing
over
that
of
tfr,
as
we've
discussed,
there's
no
single
ili
tool
that
can
identify
every
type
of
pipeline
threat
to
achieve
the
greatest
degree
of
confidence.
The
use
of
multiple
ili
tools
may
be
the
most
appropriate
approach.
C
Let's
concentrate,
on
the
left
hand,
side
of
the
screen
for
the
liquid
solutions.
I
briefly
mentioned
phased
array
and
want
to
explain
its
vast
capabilities,
unlike
conventional
wall
measurement
and
crack
detection
tools.
The
phased
array
is
a
smart
sensor
that
can
be
programmed
to
focus
arrays
of
sensors
to
determine
both
corrosion
and
crack
in
a
single
room.
C
We
can
also
configure
the
sensor
to
give
us
better
resolution
for
both.
Finally,
we
can
adjust
the
angles
to
refine
crack
sizing
today.
This
tool
can
be
multi-tasked
and
inspect
for
both
corrosion
and
cracking
in
a
single
run.
But,
however,
it
must
be
slowed
down
to
a
very
slow
speed
compared
to
conventional
tools
as
electronics
and
physics
are
advancing.
C
We
are
looking
into
smaller
and
faster
elements
and
increasing
both
the
resolution
and
the
ability
to
multitask
at
higher
speeds.
These
elements,
combined
with
the
mini
computers
required
to
fire
them,
are
at
the
leading
edge
of
technology.
Today,
going
back
to
the
medical
analogy,
this
is
your
ultimate
mri
machine
versus
an
x-ray
on
the
right-hand
side
of
the
screen.
C
C
C
C
C
Think
of
them,
as
as
threats
lurking
around
the
corner
and
the
defect
depicted
in
the
green
hatched
areas,
are
those
that
fall
within
the
ili
tool
specification
and
would
be
reported.
So
this
is
what
I
mean
when
I
talk
about.
Ili,
provides
more
visibility
and
with
hydra
testing.
The
pipeline
must
be
taken
out
of
service
during
the
test,
but
if
the
pipeline
isn't
pickable,
hybrid
test
might
be
an
appropriate
method.
C
A
M
M
M
G
G
The
next
thing
that
is
necessary
to
do
is
to
choose
the
appropriate
ili
technology,
and
here
I'm
not
talking
about
particular
vendors
or
particular
vendor
tools,
but
the
technologies,
whether
it's
ultrasonics
for
metal
loss,
mfl
for
metal
loss
or
emats,
for
instance,
for
crack
detection
in
gas
pipelines.
So
choosing
the
appropriate
technology
is
the
next
step
and
there's
good
guidance
in
api
1163
standard,
nace
sp0102
and
nace
report
35
100..
G
G
And
here
the
vendors
provide
really
good
guidance
in
their
performance
specifications
and
they
lay
out
in
great
detail
the
probability
of
detection
of
a
particular
tool.
Finding
a
particular
defect
and
the
whole
range
of
those
are
expressed
beyond
probability
of
detection.
They
get
into
probability
of
identification.
G
G
The
third
part
of
this
stage
is
sizing
the
defects,
one
can
detect
defects
and,
in
some
cases,
not
be
able
to
size
them
appropriately.
If
you
can't
size
them,
you
can't
assess
their
possible
impact
on
predicted
rupture
pressure,
for
instance,
so
once
you've
done,
that
selection,
you
need
to
then
have
an
operationally
successful
run,
and
that
is
described.
G
The
next
stage
you
get
into
is
the
interpretation
of
the
data
that
is
collected
and
that's
done
in
a
combination
of
ways.
Some
of
the
interpretation
is
done
through
rules-based
software
that
evaluates
the
data
on
computers
and
that's
very
good,
because
it's
predictable
and
it
is
highly
productive
in
carrying
that
out.
A
lot
of
the
defects,
however,
are
complex
and
require
human
interpretation,
so
the
qualification
of
the
people
doing
that
work
becomes
significant.
G
M
G
Thank
you
for
that.
This
is
a
very
good
early
guidance
on
selection
of
the
right
tool
against
the
potential
threats
in
a
pipeline
section.
So
down
the
left-hand
side
where
it
describes
anomaly
are
the
different
kinds
of
defects
that
we
could
anticipate
possibly
occurring
in
a
pipeline
across
the
top,
are
the
different
kinds
of
tools
that
are
available
from
many
vendors
and
if
you
go
down
through
that,
matrix
you're
able
to
see
in
some
cases
where
it
states
that
a
particular
tool
would
not
detect
a
particular
defect.
Obviously
that's
an
inappropriate
choice.
G
M
C
M
My
my
next
question
is
in
regards
to
the
ability.
Well,
it
would
be
a
historical
question
from
the
historical
point
of
view.
How
far
has
inline
inspection
technology
progressed
in
regard
to
the
inspection
of
gas
pipelines,
we're
looking
at
pipes
that
are
1950,
1960
vintage?
Where
does
inline
inspection
tools
come
in?
Is
it
very
recent?
Are
we
making
any
progress,
and
mr
frazier
farmer
is
there?
Would
you
like
to
comment
on
that.
G
Thank
you.
The
origin
of
inline
inspection
goes
back
to
the
mid
to
late
1960s,
and
the
concentration
at
that
time
was
on
mfl
technology
for
detection
of
internal
and
external
corrosion
in
the
1980s.
Those
tools
evolve
to
what
are
sometimes
called
high
resolution
mfl
tools,
and
that
is
really
a
very
mature
technology.
G
They
came
on
the
market
crack
tools.
Initially,
there
was
an
early
british
gas
development
for
detecting
cracks
in
gas
pipelines.
It
used
ultrasonics
in
a
wheel,
configuration
those
tools,
have
pretty
much
been
retired.
Now
that
emat
tools
are
on
the
market,
the
ultrasonic
crack
detection
tools
applicable
in
liquid
systems
in
the
late
90s
gained
great
popularity,
particularly
in
liquid
lines
that
had
stress
corrosion
cracking.
G
M
C
C
If
it
would
depend
on
the
size
of
the
floor,
it
would
also
just
depend
on
the
type
of
technology
that
was
trying
to
define
the
floor
from
a
from
a
corrosion
point
of
view.
It's
very
rare
from
a
crack
point
of
view
to
my
knowledge
and
anything
that
I've
been
involved
in
a
forensics
of
a
failure.
A
crack
tool
has
always
detected
it,
but
but
maybe
not
being
able
to
evaluate
it.
C
So
that
you
know,
as
I
mentioned
in
my
presentation,
I
think
the
more
feedback
we
get
with
real
defects,
the
better
we
are
in
understanding
the
capabilities
of
the
technologies
majority
of
the
tools
are
when
we,
when
we
design
and
build
them
and
test
them,
we
test
them
with
artificial
defects.
We
build
our
expertise
and
our
of
our
size
and
algorithms
based
on
artificial
defects.
C
Therefore,
getting
real
defects
from
a
pipe
in
a
real
pipe
environment
is
invaluable
to
us.
So
that's
one
way
where
we
can
improve
and
the
other
way
is
repeat
inspections.
You
re,
you
increase
your
probability
of
of
confidence.
Sorry
you!
You
improve
your
confidence
every
time
you
run
a
tool
and
the
chances
are
that
if
you've
missed
something
the
first
time,
it
will
be
caught
in
repeat
inspections
and-
and
that's
probably
the
best
way
of
doing
it.
C
The
the
one
and
the
one
anomaly
that
at
the
moment
is
impossible
to
be
detected
is
a
thing
called
pinholes
or
micro,
biology,
biological
corrosion
and
that's
because
of
its
very,
very
small
diameter.
Sometimes
it's
referred
to
as
wormholes,
and
it's
just
because
the
physics
that
are
available
to
us
today
don't
allow
us
to
detect
it.
However,
the
technology
I
did
display
the
the
phased
arrays
for
liquid
operation.
M
C
M
C
That's
a
very
difficult
question
to
answer.
You
know
from
the
inspection
point
of
view,
it's
the
price
of
an
inline
inspection.
I
couldn't
really
comment
on
how
much
an
operator
pays
for
a
hydrostatic
test,
plus
the
inconvenience
of
not
being
able
to
actually
operate
the
pipeline.
So
really
it's
a
question
that
you
should
really
pose
to
an
operator
rather
than
to
a
family
vendor.
M
B
B
N
H
You
should
know
that
our
program
is
there
in
support
of
the
fem's
emission
and
pipeline
safety.
We're
focused
on
near-term
solutions,
that's
one
to
three
years
that
improve
the
safety
and
reliability
and
the
environmental
impact
reduce
the
environmental
impact
from
our
nation's
transportation
system
pipeline
transportation
system.
The
department
has
been
conducting
research
since
1969,
but
at
a
very
limited
level,
paper
studies
and
really
not
addressing
technology
development.
H
Our
program
strives
for
outputs
and
impacts
from
these
three
objective
areas:
developing
technology,
strengthening
consensus
standards
and
generating
and
promoting
new
knowledge
to
decision
makers.
We've
awarded
171
projects
with
62
million
dollars
in
feminism
funds,
as
well
as
79
million
of
industry
and
other
federal
co-funding
worldwide
since
2002..
H
H
The
figure
will
drastically
change
to
illustrate
how
our
investment
addressed
many
of
these
pipeline
challenges.
Currently,
our
drafts
new
programmatic
areas
are
threat,
prevention,
leak,
detection,
anomaly,
detection
and
characterization
anomaly,
remediation
and
repair
design,
materials,
welding
and
joining
and
alternative
fuels,
climate
change
and
other.
H
Next
couple
slides
depict
just
some
of
the
impacts
that
our
program
has
brought
to
bear
on
natural
gas
transmission
pipeline
challenges.
We've
seen
improvements
to
guided
wave
ultrasonics,
a
technology
that
may
be
used
in
difficult
to
inspect
areas
such
as
cased
pipelines
that
go
under
roads
and
railroad
crossings.
H
We've
seen
the
first
ever
tool
that
can
map
entire
pipeline
current
demand
from
inside
the
pipeline
areas
of
higher
current
demand
may
indicate
challenges
with
the
effectiveness
of
a
cathodic
protection
system.
In
a
given
pipeline
segment,
we've
also
seen
deployment
of
an
innovative,
robotic
inspection
tool
for
natural
gas
pipelines
considered
unpickable
by
traditional
inline
inspection
technology.
H
H
The
following
next
couple,
slides
depict
some
of
the
anticipated
technology
impacts
that
we
see
entering
the
market
in
the
next
one
to
three
years
once
again,
addressing
natural
gas
transmission
pipeline
challenges,
working
with
the
same
sponsors
supporting
the
six
to
eight
inch,
robotic
tool.
We've
seen
big
advances
in
technology
to
inspect
larger
diameter,
unpickable
pipelines.
H
The
picture
shows
another
innovative,
robotic
inspection
technology
still
in
the
research
phase,
but
going
under
numerous
technology
demonstrations
to
ensure
that
the
technology
will
reliably
perform
in
the
challenging
environment.
It
needs
to
the
picture
shows
this
tool.
It
has
cameras
once
again
on
both
ends.
It
has
a
mfl
sensor
capable
of
looking
at
metal
loss
corrosion
not
picked
not
depicted
in
the
picture.
H
As
I
mentioned
earlier,
we're
also
focused
on
improving
nationally
recognized
consensus
standards.
We
have
a
memorandum
of
agreement
with
the
standard
pipeline
standard,
developing
organization,
coordinating
council.
This
council
represents
the
pipeline
standard,
developing
organizations
who
have
interest
in
pipeline
safety
standards
and
specification
standards.
We
make
them
aware
of
the
research
targeting
their
standards.
We
invite
them
to
peer
review
our
projects
annually
that
are
relevant.
We
share
the
project
results
with
committees
representing
these
standards
and
we
ask
them
to
report
if
the
project
results
are
used
to
help
revise
these
standards.
H
In
our
initial
data
call,
we
determined
that
three
standards
were
improved
from
our
program's
focus
on
standards,
one
with
api
and
one
with
nays
international.
We
also
determined
that
a
number
of
project
results
were
shared
with
these
committees
for
addressing
whether
or
not
they
would
be
used
to
help
revise
these
standards.
H
H
We
were
also
asked
to
talk
about
direct
assessment
and
how
our
program
is
broadening
applicability,
validating
and
further
standardizing
the
direct
assessment
process.
Let
me
first
say
that
direct
assessment
and
starting
with
external
corrosion
direct
assessment
has
been
improving
since
its
release
in
2004,
both
from
its
usage
and
from
targeted
research.
H
And
finally,
we
really
believe
that
the
the
future
is
bright
and
promising.
We
spent
the
early
years
of
our
program
crafting
the
best
results,
driven
process
possible
and
aligning
it
to
the
type
of
research
we
fund
and
the
stakeholders
we
partner
with.
We
feel
our
program
has
the
right
type
of
credentials
and
hallmarks
necessary
for
federal
research
program.
Addressing
these
ever-changing
pipeline
challenges
deploying
technology
via
our
program
is
growing
in
its
success
and
we
believe
it
can
be
accelerated
with
additional
resources.
N
N
It
appears
that
the
from
what
I
understand
the
fisma
research
roadmap,
shall
we
say,
is
it's
managed
by
a
kind
of
a
gla
gap,
closure
process
whereby
you
know
you
have
collective
information
that
you
get
from
industry
and
you
know
regarding
problems
and
issues,
and
then
you
know
you
take
a
look
at
the
the
priority
of
projects.
You
try
to
close
those
gaps.
What
gaps
have
been
closed
so
far?
What
what
are
the
sort
of
the
key
accomplishments?
To
date?
H
I'll
try
to
do
my
best
on
that
answer,
but
I'd
first
like
to
say
that
that
process
that
I
showed
in
the
slide
is
really
the
process
that
works
well
for
our
program
and
our
stakeholders
to
identify
what
the
right
priorities
are.
We
come
together
periodically
to
look
at
all
the
ongoing
research
that
we're
not
duplicating.
H
N
H
Well,
the
program,
like
I
said,
started
in
2002
and
with
the
appropriations
necessary
to
address
some
of
these
technological
challenges.
I
would
have
to
speak
towards
some
of
the
robotic
technology,
the
being
really
the
major
improvement
that
the
program
has
been
able
to
partner
with
mutual
challenges,
to
to
get
solutions
out
there
for
unpickable
systems.
So
these
are.
N
Thank
you.
You
talked
a
little
bit
about
direct
assessment,
but
I
had
a
question
regarding
how
is
there
any
work
you're
doing
on
on
pulling
together
data
as
you're
developing
new
technology,
and
how
effective
is,
is
the
direct
assessment
becoming
is
it?
Is
it
really
increasing
in
effectiveness,
and
do
you
have
any
metrics
or
ways
of
documenting
that.
H
H
J
J
Okay,
if
applied
appropriately,
it
is
effective.
Operators
are
required
to
report
the
results
of
their
integrity
management
program
and,
as
you
as
you
all
know,
that
direct
assessment
is
is
an
assessment
method.
That's
relied
upon
heavily
for
distribution
companies
for
intrastate
transmission
companies
where
they're
not
pickable.
J
Again,
it
has
to
be
used
appropriately
if
you're.
If
you're
looking
for
external
corrosion,
you
have
say
a
seam
threat
that
may
not.
That
would
not
be
the
appropriate
use
of
external
corrosion
direct
assessment,
for
instance,
but
it
is
an
effective
tool
for
finding
external
corrosion,
assuming
that
the
rest
that
the
line
also
meets
the
other
aspects
of
the
regulation
related
to
corrosion
control.
N
H
Yes,
we
are
currently
looking
at
hydrostatic
testing
with
one
active
project
that
is
due
to
complete
this
summer.
That
actually
is
getting
to
some
of
the
discussions
that
we
talked
about
over
the
last
couple
days
on
customizing
hydrotesting.
The
parameters
involved
in
hydrotesting
to
not
grow
some
cracks
but
grow
other
threats
and
be
able
to
look
at
the
stress
corrosion
cracking
threat,
in
particular.
N
H
From
a
research
perspective
and
I'll
probably
pass
some
of
that
question
on,
we
know
that
we
can
effectively
target
research
program
solutions
towards
some
of
these
challenges
that
we're
seeing
out
in
the
field
we're
partnered
very
well
in
the
engineering
program
at
fimsa
and
our
free,
our
field
personnel
and
our
state
partners,
and
as
well
as
coordinating
with
other
federal
agencies
in
the
industry.
To
know
that
we
need
to
be
addressing
these
type
of
challenges
and
develop
those
type
of
tools
to
be
able
to
help
meet
and
exceed
regulatory
requirements.
H
N
H
I
would
believe
that
we
are
addressing
most
of
the,
if
not
all
the
known
threats
that
we
see
out
there.
We
have
like
I
said
that
process
that
really
gets
to
the
heart
of
the
gaps
that
we
see
out
there
and
then
finding
good
research
to
address
that
and
then
getting
those
tools
out
into
the
market
or
or
information
to
standard
developing
organizations.
N
N
H
When
I
had
the
slide
talking
about
how
our
investment
has
broken
into
our
programmatic
areas,
you
might
have
seen
that
there
was
not
much
investment
going
on
in
risk
management,
and
that's
really
because
directly.
That's
because
risk
management
is
something
that
is
involved
with
pretty
much
every
project
that
we're
dealing
with
because
of
integrity
management
and
because
it
reliance
on
on
data
and
risk
management
to
know
what
tools
that
we
should
be
looking
at
in
development
and
what
tools
that
need
to
be
deployed.
N
Okay,
it
just
seems
as
though
you
know
having
to
know
really
the
threats
before
you
start
to
inspect.
Them
is
sort
of
a
sort
of
an
unending
loop.
You
almost
need
to
inspect
your
pipeline
first
so
that
you
can
figure
out
what
threats
to
identify
then
start
to
monitor
those
threats,
and
it
seems
like
this
is
an
area
where
there's
assumptions
made
for
operators-
and
so
I
was
just
wondering,
is
there?
Is
there
more
work
being
done
in
this
area?
J
If
you
look
over
the
last
year
or
so
at
the
incidents
that
have
occurred
in
the
u.s,
you
know
they're
quite
varying
causes
causal
factors
involved.
However,
a
common
thread
that
we
could
pick
out
there,
if
you
will,
is
the
identification
of
threat,
appropriate
identification
of
threat
and,
in
many
cases,
just
using
information,
that's
already
in
the
hand
of
the
operator.
J
So
that's
why
we
felt
a
need
to
have
a
workshop
which
is
coming
up
in
july.
In
addition,
we're
also
issuing
my
colleague
ms
dardy
mentioned
yesterday
as
well
an
advanced
notice
that
proposed
rulemaking
related
to
the
gas
integrity
management
program.
We've
already
done
that
for
liquid
and
the
comment
period
just
closed,
but
we
expect
that
to
be
coming
out
late
spring
to
further
ask
the
public
and
industry
all
the
stakeholders,
where
improvements
need
to
be
made
in
our
integrity
management
regulations.
N
Yes,
in
older
or
legacy
pipeline
systems
have
industry
best
practices
been
developed
to
identify
pipeline
threats
with
the
highest
level
of
confidence.
In
other
words,
is
there?
Is
there
sharing
going
on
in
the
industry
around
the
best
way
to
get
at
the
assumed
threats
for
a
pipeline
system,
and
is
that
being
shared
effectively?.
E
I
believe
so,
as
both
mr
foreman
indicated
and
others
have
indicated
on
the
panel.
The
best
place
to
learn
about
these
industry
best
practices
and
what
other
operators
have
experienced
and
found
is
at
industry
conferences
and
the
american
guest
association
does
have
a
excellent
program
for
local
distribution
companies
who
are
participating
in
their
best
practices.
Program
to
share
information
and
lessons
learned.
N
H
I
think
this
gets
to
the
question
of
how
you
measure
the
impact
of
research
and
sometimes
that's
a
difficult
endeavor.
We
try
to
stop
at
the
idea
that
we're
able
to
bring
new
tools
out
into
the
markets
going
beyond
that
to
look
at
economic
issues.
We
don't
have
economics
in
our
mission
and
I
do
believe,
there's
requirements
about
how
we
maybe
ask
the
industry
to
report
back
since
we
regulate
them.
I
think
there's
a
burden
that
we
may
be
putting
on
industry
to
try
to
go
out
there
and
do
that
from
our
point
of
view.
H
But
we
try
to
get
tools
out.
We
try
to
measure
that
they've
been
commercialized.
We
measure
what
the
net
improvement
of
those
tools
are:
we're
measuring
that
we're
providing
information
to
standards,
developing
organizations
we're
measuring
that
it
was
used
or
not,
and
we're
measuring
from
promoting
general
knowledge.
You
know
how
many
files
are
being
downloaded
website
hits
patents,
a
number
of
other
things
to
try
to
show
that
our
program
is
effective,
at
least
getting
this
information
out
there.
It's
once
again
hard
to
go
beyond
that
step.
I
think
thank.
N
H
Well,
I
think
he
partially
already
answered
some
of
that
with
the
idea
that
we've
had
had
advances
and
tools
and
more
tools
out
there.
Creating
more
data.
We've
been
looking
hard
at
data
over
the
last
few
years
in
our
solicitations
trying
to
make
the
researchers
look
at
the
idea,
what
data
they're
creating
and
what
could
be
done
with
this
data.
We
had
this
as
part
of
a
discussion
on
one
of
our
r
d
forums
a
few
years
back.
N
H
N
B
You
mentioned
excess
flow
valves,
I'll
start
with
it,
so
for
excess
flow
valves.
We
know
what
we
have
seen
is
a
expansion
of
that
technology
over
time
when
they
first
were
developed,
they
had
some
issues
right
now,
they're
pretty
they
work
really
well
for
single-family
homes.
There
are
still
some
challenges
when
you
expand
that
to
small
businesses,
because
excess
flow
valves
are
a
relatively
stupid
device.
B
They
only
look
at
a
loss
of
pressure,
but
if
you
have
an
increase
in
load,
the
device
could
assume
that
that
loss
of
pressure
is
due
to
an
incident,
not
an
increased
load
and
will
shut
down.
That
creates
safety
problems
which
has
been
discussed
throughout
the
hearing.
So
work
is
still
being
developed
to
make
them
a
little.
Smarter
and
industry
is
pilot
testing
these
to
see
where
they
work
and
where
they
don't
for
automatic,
shutoff
valves
and
remote
control
valves,
automatic
shutoff
valves
are
very
similar
to
an
excess
flow
valve.
B
It
just
indicates
if
there
is
a
pressure
loss,
which
means
that
you
have
to
be
pretty
certain
about.
Your
pressure
have
pretty
consistent
pressure
in
order
to
use
that
type
of
device.
A
remote
control
valve
a
little
different
has
a
little
bit
of
intelligence.
I
think
we've
seen
a
progression
of
that
technology.
I
can.
I
believe
that
more
work
needs
to
be
done
to
make
them
just
a
little
smarter,
hopefully,
a
little
cheaper
and
better
utilized.
N
Thank
you
in
your,
I
guess.
In
your
opinion,
I
and
I'll
throw
this
out
to
both
of
you.
Do
you
feel
that
this
is
an
area
that
needs
more
attention
technologically
to
be
able
to
get
it
to
a
point
where
they
might
be
more
commonplace
and
maybe
be
smarter
about
when
they
work
and
don't
work
and
so
forth?.
B
Okay,
I'll
jump
in
first.
Yes,
please,
I
I'm
not
sure
if
it's
more
the
technology,
as
as
more
of
an
understanding
of
where
they
are
where
they
should
be
applied
and
where
they
shouldn't
be
applied,
got,
does
have
regulations
for
operators
to
consider
this.
We
know
that
operators
are
considering
them,
but
there
are
a
number
of
factors
that
have
to
be
taken
into
consideration.
B
So
I
what
I
would
like
to
see,
and
what
one
of
the
things
that
the
american
gas
association
is
currently
working
on
I'll
speak
to
it
a
little
bit
later
is
a
document
that
helps
to
pull
together
where
they
work,
where
they
don't
work
and
things
that
have
to
be
considered.
For
example,
if
you
are
trying
to
install
one
of
these
valves
in
an
urban
environment,
you
may
not
be
able
to
put
it
above
ground.
If
you
put
it
below
ground,
you
need
to
have
the
real
estate
a
vault.
B
B
N
J
The
operator
must
look
at
data
of
his
system
as
operating
data,
to
see
if
automation
of
a
valve
may
be
necessary,
you've
kind
of
covered
a
broad
spectrum
here
I
know
I've
gone
from
excess
flow
valves
on
a
customer
service
line
to
a
automation
of
a
mainline
valve.
Certainly
the
technology
is
there
to
automate
mainline
valves
and
we
have,
for
instance,
in
our
alternate
malp
regulation.
We
have
mandated
automated
valves
or
line
break
sensors
at
valve
stations
to
control
operation
or
control
the
flow
of
gas
on
those
types
of
pipelines.
N
K
E
E
This
chart
taken
from
asme
b318
categorizes
the
root
causes
of
threats
to
pipelines
into
three
time
related
defect,
types
of
behavior,
those
that
are
time
dependent,
those
that
are
stable
unless
activated
by
a
change
in
conditions
and
those
that
are
time,
independent
or
random,
based
on
the
type
of
threat
behavior,
either.
Periodic
assessments,
a
one-time
inspection
assessment
or
ongoing
prevention
and
surveillance,
is
required
to
mitigate
these
threats.
E
E
As
stated,
certain
tools
have
better
abilities
for
seams
and
cracks,
but
no
tool
is
100,
fool
proof
and
there
are
limitations
in
order
to
run
in-line
inspection
tools.
The
pipe
the
light
the
pipeline
must
be
pickable
both
physically
and
operationally,
and
what
I
mean
operationally
is
that
pipeline
flow
rates
and
operating
pressures
must
match
the
tool,
speed
requirements.
E
It
has
been
estimated
that
the
cost
to
retrofit
all
interest
state
transmission
pipeline
to
be
pegable
is
approximately
12
billion
dollars.
I
think
a
question
was
asked
earlier
about
the
percentage
of
the
estimated
percentage
of
ldc
transmission
pipe.
That
is
not
piggable
and
that's
shown,
as
the
first
bullet
is
61
percent.
E
E
Hydrostatic
mill
pressure
tests
are
performed
at
the
pipe
manufacturer
at
pressures
now
significantly
higher
than
operational
pressures.
This
chart
taken
from
api
5l
or
excuse
me.
The
inga
2005
report
shows
maximum
test
pressures
for
large
diameter
pipe
increasing
from
50
percent
of
specified
minimum
yield
in
1928
to
90
percent
of
specified
minimum
yield
in
1983.
When
the
api,
5l
and
5lx
specifications
were
combined.
E
E
E
E
Reversal
while
it
makes
sense
to
hydrostatically
pressure
test
new
pipelines
prior
to
their
being
placed
in
service
if
time
dependent
defects
can
be
located
reliably
by
by
an
inline
inspection
tool.
Utilizing
the
inline
inspection
tool
is
usually
preferable
to
the
hydrostatic
pressure
testing
of
an
in-service
pipeline.
E
If
hydrostatic
testing
is
to
be
conducted
to
validate
the
serviceability
of
a
pipeline
that
is
suspected
to
contain
defects
that
are
becoming
larger
with
time,
the
highest
feasible
test
pressure
should
be
used.
The
higher
the
test
pressure,
the
smaller,
will
be
the
defects.
If
any
that
survived
the
test.
E
E
In
summary,
operators
need
the
flexibility
to
use
all
tools
to
address
the
threats
to
pipeline
safety.
There
is
no
single
silver
bullet,
inline
inspection
and
pressure
tests.
Each
have
both
benefits
and
limitations,
and
operators
must
carefully
weigh
the
benefits
and
risks
associated
with
hydrostatic
pressure,
testing
of
in-service
pipe.
E
K
You
thank
you
very
much
for
the
presentation.
I
appreciate
that
is
it
possible.
Can
you
give
us
a
rough
estimate
of
the
costs
of
hydrostatic
testing
versus
inline
inspection
or
direct
assessment
methods?
Is?
Is
there
a
rule
of
thumb
like
a
cost
per
mile,
or
can
you
give
me
an
order
of
magnitude
estimate,
maybe.
E
E
N
E
B
K
J
There
are
methods
to,
and
quite
honestly
we
haven't
seen
a
big
failure,
history
or
or
major
issues
related
to
that
phenomenon.
One
way
to
manage
it
is
we
do
have.
We
do
require
on
existing
lines
from
time
to
time,
what's
called
a
spike
test
which
may
address
suitably
address
the
concern
over
a
pressure
reversal,
and
that
still
involves
an
eight
hour
test.
O
J
It's
a
test
that
we
have
required
of
operators
on
occasion
where
there's
a
concern
over
the
integrity
of
a
line,
in
particular,
to
address
the
potential
defects
or
potential
defects
in
the
seam
it
involves,
like.
I
was
saying
earlier,
applying
pressure
to
the
pipeline
hydrostatic
pressure
with
water
tests
with
water.
The
pressure
is
an
eight
hour.
The
test
is
an
eight
hour
test.
J
It
pressure
is
raised
to
close
to
a
hundred
percent
of
the
specified
minimum
yield
strength
of
the
pipe
of
the
steel
and
just
for
everyone's
benefit.
That's
the
point
at
which
the
the
pipe
goes
from
elastic
deformation
or
the
steel
goes
from
elastic
to
plastic
deformation
and
a
good
example
would
be.
If
you
were
to
take
a
paper
clip
and
bend
it
you
can.
If
you
bend
it
a
little
bit,
it
comes
back
to
its
original
shape.
At
some
point,
you
bend
it
so
far.
J
J
It's
below
that
point,
but
to
address
the
concern
of
in
a
pressure
reversal
involves,
as
I
mentioned
earlier,
a
where
you
have
a
hydrostatic
pressure
test.
For
instance,
at
a
certain
level,
you
test
the
line
at
a
later
date,
or
you
put
it
into
service
at
a
later
date,
and
it
fails
at
a
lower
pressure.
It's
because
of
a
defect,
that's
perhaps
been,
has
grown
to
failure
after
you
took
the
pressure
off
and
then
repressurized
it.
O
B
When
I
look
at
got
statistics
on
incidents,
I
am
not
seeing
that
as
an
issue,
I'm
seeing
the
what
happened
in
san
bruno
as
an
anomaly
and
what
we
in
the
industry
are
hoping
is
that,
through
your
investigation,
you
find
out
why
that
anomaly
occurred.
Why
did
that?
What
we
perceived
to
be
a
stable
defect
become
unstable,
looking
forward
to
your
findings.
D
D
D
J
K
K
B
Thank
you
and
I
do
appreciate
the
opportunity
to
speak
at
this
hearing
about
safety.
I
can
tell
you
that
I
and
my
colleagues
are
pretty
passionate
about
this.
I
also
am
very
happy
that
I
am
the
last
presenter
of
the
last
panel
of
the
last
day
of
a
long
hearing.
So,
let's
see
if
we
can
wrap
this
up,
I
promised
dr
schulte.
I
would
do
this
in
five
minutes
or
less
and
I'm
sure
he
will
pull
in
the
hook.
B
If
I'm
not
just
to
give
you
a
quick
understanding
of
who
the
aga
is
and
who
we
represent
about
200
companies,
energy
companies,
primarily
we
represent
distribution.
Many
of
these
distribution
companies
have
transmission,
so
these
would
be
your
intrastate
transmission
lines.
All
in
all,
our
members
deliver
about
91
percent
of
the
gas
that's
delivered
in
the
u.s,
and
let
me
jump
right
into
our
best
practices
program.
It's
one
of
the
topics
that
has
come
up.
How
does
the
industry
benchmark
itself?
B
The
aga
has
three
areas
that
we
cover
and
three
topics
within
each
of
those
areas.
We
cover
benchmarking
that
allows
companies
to
benchmark
themselves
against
others,
their
peers
and
figure
out
who's
best
in
class.
We
do
round
tables
and
we
also
do
questionnaires
I'll
cover
each
of
those
in
a
little
bit
more
detail.
B
This
is
just
a
little
bit.
Let's,
okay,
so
one
of
the
areas
we
cover
for
benchmarking
is
distribution.
You
can
see
some
of
those
topics
right
there
that
we've
covered
in
the
past.
We
do
change
our
topics
each
year,
there's
not
really
a
need
to
benchmark
each
topic,
I'm
just
going
to
keep
clicking
until
I
get
to
the
end
of
this.
B
There's
not
really
a
need
to
benchmark
every
topic
every
year,
but
what
you
want
to
look
for
are
trends
and
that's
what
the
program
does
so
three
areas:
transmission
distribution
and
supplemental
gas
with
transmission.
That
is
done
in
conjunction
with
the
southern
gas
association.
I
think
I
mentioned
earlier
in
the
inter
in
the
when
I
was
being
introduced,
that
we
do
work
and
partner
with
others.
This
is
just
one
example.
B
B
We
create
data
packets,
collect
the
data
that
data
is
analyzed
by
subject
matter:
experts
within
the
industry
that
moves
on
into
leading
and
identifying
those
top
quartile
companies
and
those
top
performances
that
feeds
into
round
tables.
We
look
to
the
leaders
to
explain
to
others
in
the
industry
how
they
got
to
that
top
quartile.
What
are
the
procedures
that
they're
using?
We
also
look
for
those
unique
instances
that
may
not
have
been
considered
by
other
companies,
because
you
want
to
bring
those
forward.
Also
those
go
into
the
round
table
discussions.
B
B
So
let
me
get
into
the
benchmarking
in
just
a
little
bit
more
detail.
I
mentioned
that
we
collect
statistical
data
for
each
of
the
topics
that
the
topics
change
year
by
year,
depending
on
the
needs
of
the
industry,
I'm
not
going
to
read
through
all
the
bullets
because
they're
available
in
the
exhibit,
but
there
we
go
round
tables.
I
mentioned
that
we
bring
the
procedures
that
were
identified
from
the
top
quartile
companies
into
the
round
tables,
along
with
some
of
the
unique
identifying
characteristics
that
we're
finding.
B
What
we're
looking
at
are
a
few
things.
First,
what
are
the
challenges
for
that
topic,
so
the
topic
may
be
damage
prevention
or
integrity
management
if
it
were
transmission,
integrity
management.
One
of
the
topics
that
may
come
up
as
a
challenge
is:
how
do
you
address
historical
data
in
the
round
table?
B
What
we,
then,
the
participants
at
the
round
table
then
identify
their
company's
leading
practices
from
their
perspective
of
how
they
are
addressing
that
particular
issue
from
that
the
participants
at
the
round
table
identify
out
of
everything.
That's
been
discussed.
What
are
the
best
practices
for
that
particular
operational
challenge?
This
is
all
captured
and
shared
with
the
industry.
B
B
B
That's
just
a
high
level
overview
of
the
best
practices
program.
I'm
sure
you'll
have
questions
later
I'll,
be
glad
to
answer
them.
A
second
area
that
we
are
utilizing
to
improve
the
industry
are
publications.
We
spend
a.
We
have
about
16
technical
committees
just
within
operations
each
focused
on
a
particular
topic
such
as
corrosion
or
engineering.
B
B
This
is
just
an
example,
and
this
is
an
additional
example.
I
did
mention
earlier
that
we,
I
think
I
mentioned
earlier,
that
we
are
working
on
a
paper
on
automatic,
shutoff
valves
and
remote
control
valves.
I
don't
have
that
list,
because
it's
not
final.
Yet
that
is
being
done
through
our
technical
committee,
our
distribution
and
transmission
engineering
committee.
B
B
These
are
events
where
we're
pulling
together
the
industry
to
share
knowledge,
and
when
I
did
a
capture
of
how
many
people
we
pulled
together,
that
was
about
2700.
I
mentioned
that
we
have
16
technical
committees,
you
see
just
a
few
of
those
listed.
We
did
complete
nine
publications
plus
a
variety
of
other
documents.
B
It's
really
short
surveys
when
somebody
within
the
industry
has
an
issue
that
needs
to
be
solved.
We
will
put
out
an
sos
for
that
company
to
say
how
are
you
addressing
this
issue?
How
have
you
combated
this
issue?
What
are
you
finding
that
can
improve
it?
That
can
solve
this,
so
we
did
80
of
those,
and
then
we
have
a
board
safety
committee
that
was
put
into
existence
about
five
years
ago.
B
There
are
a
number
of
priorities.
We
have
a
safety
implementation
plan,
that's
revised
at
every
meeting
and
we
completed
about
90
of
their
priorities.
We
also
told
just
as
an
fyi
and
executive
leadership
safety
summit,
our
fifth
one
will
be
held
this
november
in
d.c
and
I'm
sure
some
of
you
will
be
invited
to
that
with
that.
Thank
you
and
I'm
open
for
any
questions.
A
A
D
K
K
M
I
I
E
Yeah,
I
I
might
just
I
might
just
add,
from
an
operator's
perspective,
that
when
inline
inspection
reports
are
received,
of
course,
there
are
digs
and
validation
digs
associated
with
those
reports
and,
as
mr
foreman
indicated,
that
information
is
very
the
in-line
inspection
tool.
Vendor
is
very
interested
in
the
results
of
that
and
we're
also
very
interested
in
it
as
well,
because
we
have
predicted
anomalies
and
then
we
have
as
found.
So
we
do
make
those
comparisons.
M
M
J
Okay,
yes,
we
do
call
out
low
frequency,
rw
pipes
specifically
related
to
the
integrity
management
program,
and
when
you
need
to
assess
for
that,
there's
a
large
population
of
of
that
type
of
pipe
still
present
in
use
most
of
it's
safely
operating.
There
are
techniques
you
that
are
available
to
assess
the
integrity
of
the
seam
and
to
look
for
the
defects
in
those
types
of
seams.
M
J
J
I
and
then,
of
course
the
other
method
would
be
hydrostatic
testing,
but
it's
still
evolving,
but
I
think
there's
much
improvement
that's
been
gained.
I
don't
see
data
that
warrants
as
far
as
an
incident
history
or
prevalent
incident
history.
Currently
that
would
warrant
or
specifically
targeting
it
for
say,
some
sort
of
replacement,
wholesale
replacement.
J
J
Girth
welds
there
are
detection
techniques
for
girth
welds
related
to
within
line
inspection.
That's
a
technology!
That's
improved!
Recently.
We've
seen
some
success
in
being
able
to
identify
anomalies
or
issues
with
girth
welds.
We've
also
seen
some
pipeline
failures
related
to
girth
wells
in
particular,
with
vintage
pipe.
Is
it
a
significant
incident
history?
I
would
say
not
it
tends
to
be.
J
O
C
O
C
G
C
I'll
take
a
question.
The
the
probability
of
detection
and
probability
of
impedance
is
really
aimed
at
the
lower
end
of
the
specification.
That's
what
drives
the
that
number.
So,
what
I'm
saying
really
is
large
defects
are
much
easier
to
detect
and
discriminate
than
small
ones.
So
it's
the
smaller
end
of
the
capability
of
the
tool
that
drives
that
probability.
O
J
So
yes,
if,
if
it's
performed
at
a
high
high
level
at
90
to
100
percent
of
specified
minimum
yield
strength,
it
would
not,
and
perhaps
where
you're
going
with
this
it,
it
does
not
tell
you
any
remaining
flaws
or
characterize
any
remaining
issue
with
the
pipe.
It's
it's
a
test
that
demonstrates
the
integrity
and
the
leak
tightness.
If
you
owe
the
pipeline
at
that
moment
and
for
the
the
for
for
the
until
the
next
assessment
interval.
O
My
last
question
you
mentioned
that
maybe
a
area
of
tools
may
be
necessary
depending
upon
the
flaws
that
the
operator
may
identify
as
a
threat
and
considering
that
ili
tools,
there
will
be
many
you
need
to
identify
depending
upon
stress,
collision,
cracking
or
corrosion
damage
does
does.
Hydrotest
has
a
place
in
those,
since
hydro
can
detect
the
flaws
that
are
critical
now,
whereas
ili
can
detect
all
the
possible
flaws.
J
Hydrostatic
testing
is,
is
one
tool
in
the
toolbox.
Inline
inspection
is
another.
There
are
other
inspection
techniques,
for
instance,
if
you're
dealing
with
case
pipe,
you
may
use
guided
wave
ultrasonic
testing,
there's
no
perfect
test
generally,
the
the
standard
detection
I
normally
think
of
or
ability
for
inline
inspection
is
sort
of
the
least
common
denominator,
which
is
about
a
eighty
percent
probability
of
detecting
within
plus
or
minus
ten
percent.
J
Sometimes,
we've
had,
depending
on
the
line.
Again,
it's
it's
driven
by
the
threats
and
what
we
observe
say
post-incident.
It
might
be
warranted
to
do
a
combination
of
both
both
tests
say
both
speaking
in
terms
of
in-line
inspection
and
hydrostatic
testing.
We
may
also
add
other
appropriate
tools,
such
as
indirect
inspection
methods,
to
look
for
corrosion
issues,
active
corrosion
issues,
perhaps
or
coding
issues.
J
It
also
would
create
issues
with
freezing,
perhaps
say
in
a
distribution
system.
Perhaps
there
could
be
freeze
if
residual
water
has
caused
freeze
ups
at
say,
service
regulators
at
the
house.
It's
also
caused
blockages
in
low
pressure
systems
as
well.
Most
recently,
we
had
a
failure
in
the
salt
lake
city
area.
This
is
on
the
liquid
pipeline
that
was
caused
by
residual
hydrostatic
test
water
that
was
remaining
in
the
line
and
wasn't
suitably
removed.
J
D
G
The
the
technology
for
that
particular
defect,
that's
a
crack
that
has
opened
up,
so
it
has
some
volume
so
magnetic
flux.
Leakage
will
work
in
that
case,
but
it's
not
the
standard
magnetic
flux
leakage
which
magnetizes
in
the
axial
direction.
So
to
detect
that
flaw,
the
magnetization
would
have
to
be
circumferentially
oriented
and
there
are
several
companies
that
supply
that
technology.
D
Thank
you,
and,
and
mr
mayberry,
I'm
going
to
start
with
you,
but
others
on
the
panel
might
want
to
chime
in
on
this
as
well,
and
I
I
want
to
focus
in
on
pipe:
that's
pre-1970,
so
grandfathered
pipe,
that's,
never
been
hydro
tested
and
that
and
that
may
have
an
unstable
defect
or
about
which
we
have
concerns
that
there
may
be
an
unstable
defect.
Just
let's
just
assume
those
three
things
without
saying
anything,
more
specific
about
that.
J
D
J
Not
necessarily
I
mean
if,
if
you
were
to
do
nothing,
perhaps
hydrous
testing
would
be
the
option
and
obviously
that
would
require
cutting
in
test
sections
and
hydrating
a
a
line.
That's
currently
not
pickable.
The
other
option
is
the
megapixel
the
other
option
is
to,
and
this
is
again
assuming
that
you've
gone
through
the
proper
scenario
of
identifying
the
threats
which,
as
we've
discussed,
is
an
area
that
we're
discussing
with
ourselves
and
industry.
A
D
C
D
C
F
Yes,
thank
you,
madam
chair.
I
have
a
short
question
for
miss
sames.
The
one
of
your
slides
indicated
that
you
have
a
publication
or
a
program
related
to
alarm
management
for
control
room
operations.
I'm
just
curious
whether
that
is
a
if
you
could
just
give
us
a
brief
comment
about
whether
that
is
on
up
related
to
operating
procedures
or
to.
B
F
Great
we'll
take
a
look
at
it.
Thank
you.
This
is
a
question
for
mr
mayberry
and
depot
mr
depot.
First
in
your
presentation,
you,
one
of
your
bullet
points,
stated
that
the
operator
and
regulator
need
to
decide
whether
to
place
pipe
under
the
high
stress
of
a
pressure
test
or
to
maintain
the
stability
of
a
historically
low
operating
pressure.
E
Yes,
I
I
think
it
was
briefly
touched
on
earlier
the
potential
for
a
pressure
reversal
in
a
existing
pipeline,
that
is
being
pressure
tested
with
or
hydrostatically
pressure
tested,
because
you
don't
know
what
may
exist
in
that
line
in
terms
of
sub-critical
defects.
That
may
not
necessarily
fail
the
pressure
test.
E
They
can
be
exposed
or
grown
during
the
pressure
test
process
such
that
sometime,
subsequent
to
the
pressure
testing
and
after
the
pipeline's
back
in
service.
The
potential
exists
for
these
defects
to
then
turn
critical.
So
that
has
to
be
recognized
on
the
front
end
and
I
think
the
point
of
the
operator
and
the
regulator
must
know
that
there
are
decisions
that
have
to
be
made
here.
As
as
you
progress
through
this
process
of
integrity,
management
and.
C
E
You
can
only
go
with
the
you
have
to
be
driven
by
the
characteristics
and
the
specifics
in
terms
of
what
it
is.
You
think
you're
looking
for
and
go
look
for
it
and
then
determine
whether
or
not
again
it's
a
continuous
improvement
process.
So
one
assessment
is,
is
not
the
is
not
the
way
to
complete
a
complete
integrity
program.
J
F
Thank
you.
This
is
a
question
for
the
entire
panel.
Anybody
who's
able
to
comment
on
this.
We
we've
heard
today
about
exciting
new
technologies
and
their
potential
for
operators
to
detect
and
resolve
defects
were
certainly
anxious
and
looking
forward
to
their
widespread
deployment
within
the
industry.
F
I'm
confident
that
the
citizens
of
san
bruno
would
find
this
very
difficult
position
or
conclusion
to
accept,
if
only
because
it
could
diminish
the
urgency
with
which
the
various
issues
under
discussion.
These
last
three
days
are
fully
addressed
with
that
said,
an
understanding
that
many
areas
of
our
older
infrastructure
for
gas
for
natural
gas
transmission,
based
on
the
statistics
you
cited
today,
may
actually
be
currently
unpickable.
F
J
Our
agency
is
deeply
saddened
by
the
event
that
occurred
in
san
bruno.
We
take
incidents
like
this
seriously
and
we
learn
from
them,
and
I
can
assure
you
that
we
will
apply
learnings
of
this
incident
to
our
program
into
the
national
program
and
whatever,
whatever
we
learn
from
it,
it
will
be
applied
to
our
program.
J
We
don't
accept.
Accidents
are
unacceptable,
they
do
happen.
Unfortunately.
Fortunately,
it's
a
there's,
a
low
probability
of
of
their
happening,
but
when
they
do
happen,
there
is
a
high
consequence.
We
look
for
the
issues
that
happen
or
that
contribute
to
the
cause,
and
we
do
take
action
based
on
that.
B
I
think
at
the.
What
needs
to
be
done
is
an
analysis
on
these
various
pipelines.
Looking
at
what
can?
How
can
we
identify
the
risk
to
these
lines?
How
can
we
make
sure
that
they're
safe,
that
they
continue
to
be
maintained
safely,
that
we
are
looking
at
the
issues
that
may
exist
within
these
lines
and
it's
decision
tree
replacement
may
be
part
of
that
decision.
Tree.
B
Reducing
pressure
may
be
part
of
the
decision
tree
making
the
line
pickable
may
be
part
of
that
decision,
tree
hydrostatically
testing,
but
with
each
of
these
other
things
have
to
be
considered,
including
the
impact
to
replace
the
unpickable
lines,
and
I
would
like
to
make
one
clarification
I
mentioned.
I
was
asked
earlier
about
the
percent
of
liquid
lines
that
are
pickable
and
it's
the
vast
majority.
B
I
mentioned
that
about
a
third
of
the
transmission
lines
were
unpickable
that
were
only
I'm
sorry
about
a
third
were
currently
pickable,
that
is
intra-state
transmission
for,
inter
state
it's
about
two-thirds,
maybe
a
little
higher.
I
would
defer
to
my
associates.
I
didn't
go
for
that,
but
what
we
are
seeing
is
more
of
these
lines
becoming
pickable
for
a
variety
of
reasons.
A
D
D
C
It
was
mentioned
before
really
depends
on
the
tool.
The
technology
that's
been
adopted
and
it's
not
easily
translated
to
a
daily
fee,
because
the
actual
running
of
the
pig
might
take
a
few
hours
or
a
couple
of
days,
but
then
there's
several
months
of
interpretation
and
analysis
that
goes
on
with
the
data
following
that,
but
I
can't
furnish
you
with
some
ideas
of
prices
of
of
inspection.
D
C
From
the
functionality
point
of
view,
I
think
freiza
touched
on
it
and
I
I
mentioned
you
know
the
preparation
of
the
pipelines,
making
sure
the
pipeline's
clean.
The
correct
pressure
and
floors
is
an
essential
part
of
making
sure
that
you
get
a
good
inspection
and
then
from
that
making
sure
that
we
get
good
interpretation
of
the
data
to
make
sure
that
the
the
accuracy
of
the
report.
C
G
G
C
I
agree
with
that.
They,
the
the
record-keeping
on
some
of
these
older
pipelines,
especially
the
young
pickup
pipelines,
are
essential
at
the
end
of
my
presentation.
I
said
an
expert
engineering
assessment
needs
to
be
taken
on
each
and
every
unpickable
pipeline,
because
there
are
some
engineering
solutions
that
you
can
actually
apply.
If
it's
just
you
can't
put
a
pig
in
because
it's
got
a
pig
drop.
C
You
can't
you
can't
apply
some
techniques.
We
said
success
in
new
york,
where
we
we
used
a
45
degree
hot
tub,
to
put
a
a
24
inch
to
26
inch
tool
and
and
went
across
the
river
in
manhattan
with
it.
But
we
knew
what
was
in
the
pipeline
some
of
the
fittings
that
we
show
like
that
intrude
into
the
pipeline.
C
C
G
One
last
parting
comment:
jeff
referred
to
the
fact
that
the
speed
has
to
be
within
a
certain
range
in
order
to
gather
good
data.
One
of
the
recent
innovations,
let's
say
last
five
to
ten
years,
has
been
speed,
control
on
some
of
these
tools,
so
they
actually
have
a
bypass
that
controls
the
speed
to
less
than
the
flow
speed
and.
D
C
Yes,
there
has,
I
think,
ravi
asked
the
question
that
there
has
been.
Unfortunately,
some
failures
after
after
pigs
have
been
run
through
pipelines
in
the
in
the
occasion.
I
think
that
our
answer
to
the
last
time
was
that
the
crack
tool,
we'll
see
defects
and
to
my
knowledge
on
all
of
the
forensics
following
the
failure,
the
point
of
origin
was
clearly
identified,
except
for
one
and
in
all
those
cases
the
tool
did
detect
something.
J
I
might
add
from
a
femsa
approach:
we've
seen
some
failures,
post,
inline
inspection
run
and,
and
that
is
part
of
the
basis
for
why
we're
going
to
have
a
workshop
is
in
usually
the
case
is
that
wrong
pig
perhaps
was
run
looking
for
the
wrong
issue
using
the
wrong
tool.
The
other
might
be
say,
an
incorrect
corrosion
growth
rate
assumption
those
types
of
things,
but
that
will
be
the
subject
of
our
workshop.
C
C
G
M
G
Q
Q
I
think
mr
smith
raised
a
very
good
point
said
the
challenges
were
set
in
the
early
2000s
with
the
integrity
management
rules.
They
were
pretty
aggressive
challenges,
but
technology
has
played
a
key
role
in
helping
operators
meet
those
challenges.
I'd
like
to
know
really
like
to
get
at
the
level
of
r
d
funding
and
is
adequate.
So
I'm
just
curious,
if
any
of
you
maybe
start
with
miss
ames
could
talk
to
us
about
any
publicly
available
studies
that
would
talk
about
funding
levels
and
research
and
development
for
pipeline
safety.
Only.
B
Thank
you
for
that
question.
The
american
gas
foundation
and
the
inga
foundation
concluded
his
study
2005
2006.,
it's
available
on.
I
believe
both
websites
that
looks
at
funding
levels
for
research
for
pipeline
safety
and,
if
you
look
at
it
from
a
very
high
level,
the
it
shows
that
compared
to
other
industries
like
the
computer
industry
or
the
medical
industry,
there
is
less
funding
that
is
done
by
this
industry.
B
H
H
We
have
a
requirement
for
a
50
50
cost
share
with
other
federal
agencies
and
private
research
and
trade
organizations,
we're
funding
a
lot
with
agencies
in
the
department
of
interior.
We
funded
work
with
the
department
of
energy
department
of
commerce,
so
many
industry
organizations,
pipeline
resource
council,
international,
northeast
gas
association.
I
search
operations,
technology
development
and
even
the
american
water
works
association
trying
to
cross-breed
across
different
industries
and
learn
from
what's
working
there
and
also
share
with
them.
What's
working
well
in
the
oil
and
gas
industry.
Q
Okay,
thank
you
very
much.
I
was
really
just
trying
to
get
a
question.
I
think
that
one
of
the
technical
panel
members
had
asked
about
road
mapping,
so
both
of
those
are
very
helpful.
The
point
of
it
is
only
short
short
to
midterm.
Research
is
done
all
of
the
long
term.
Research
has
dried
up
and
gone.
Q
My
numbers
will
probably
be
wrong
here,
but
I
believe
that
it
was
closer
to
50
million
at
one
point
in
time
we
might
be
under
10
collectively
at
about
this
point
in
time.
Okay,
second
question
really
maybe
go
to
fraser.
I
thought
did
an
excellent
job
describing
the
overall
process
of
inline
inspection
and
jeff
as
well.
Q
G
There
is
the
asnt
standard,
ili
pq,
which
means
personnel
qualification
and
that
talks
to
the
qualification
of
the
field
staff
from
the
vendor
going
into
the
field,
and
it
talks
to
the
qualification
of
the
data
analysts
who
review
and
make
calls
on
the
data
that
standard
talks
to
the
minimum
levels
of
training.
In
terms
of
how
many
months
of
of
training-
and
it's
then
left
up
to
the
individual
vendors,
to
implement
that
training
and
to
implement
training.
That's
consistent
with
their
technology,
and
maybe
jeff
you'd
like
to
comment
on
what
ge
does.
C
Yeah,
we've
always
had
a
training
policy
of
various
and
it's
it's
a
career
structure.
So
it's
it's
time
orientated
each
technology.
We
have
every
technology,
so
we
have
a
broad
base
of
of
analysts
and
we've
have.
We
have
some
of
the
most
experienced
in
the
industry
so
yeah
we
have
annual
tests.
An
analyst,
for
instance,
can't
progress
to
the
next
level
until
they
pass
a
written
and
a
blind
test
on
data,
any
instances
that
that
come
from
learnings
in
the
industry.
C
A
D
Thank
you,
ms
sames,
you
talked
about
some
of
the
the
best
practices
that
aga
does
in
my
preparation
for
this
hearing,
my
research
listening
and
talking
to
people.
One
thing
that
I'm
hearing
is
is
that
the
industry
as
a
whole
could
do
a
better
job,
with
sharing
information,
sharing,
best
practices,
sharing
information
about
accidents,
incidents
and
near-misses.
B
I'll.
Give
you
a
few
examples,
but
I
will
preface
everything
to
say
with
everything
we've
discussed.
Communication
is
the
key
to
learning
so
the
more
we
can
communicate,
the
more
that
we
can
share
the
better
off
we're
going
to
be.
But
to
give
you
a
few
examples
within
the
american
gas
association,
I
mentioned
the
technical
committees
within
the
technical
committees
there's
round
tables
at
each
meeting.
B
We
also
have
a
round
table
which
allows
companies
to
share
incidents,
accident
information
problems
that
they
are
encountering
when
I
take
it
up
another
level
at
the
board,
we
have
an
executive
leadership
safety
summit
that
we
hold
every
year.
We
also
have
round
tables
within
the
board
safety
committee
dedicated
time
on
every
agenda
and
the
board
safety
committee
meets
three
times
a
year
where
we
specifically
ask
for
issues
that
the
industry
is
encountering
with
a
roundtable
following
of
how
those
are
being
addressed
elsewhere.
B
On
the
aga
website,
we
have
an
information,
resource
safety,
information
resource
website.
This
is
for
just
members
only
it's
not
available
to
the
public,
because
we
want
to
get
pretty
solid
information
without
the
issue
of
having
to
mask
some
of
the
data.
But
what
we
have
there
is
a
sharing
of
particular
incidents.
What
occurred,
what
exactly
happened?
What
were
the
lessons
found
I'll
go
back,
can
more
be
done
absolutely,
and
I'm
hoping
that
this
leads.
This
discussion
leads
to
other
ways
that
we
can
improve.
That.
D
Well,
in
fact,
I
thank
you
for
for
that
answer
and
for
your
candor
and
and
that
just
sets
me
up
for
the
next
ques
next
question.
We
are
here
to
determine
facts
and
to
learn.
This
is
a
fact-finding
hearing,
so
so,
given
that
you've
said
that
there
are
ways
that
that
there
there's
room
for
improvement,
how
can
the
industry
at
large
better
share
information.
B
I
think
continuing
on
the
path
that
we've
set.
I,
I
don't
think
the
some
of
the
communication
paths
are
broken.
I
think
they
can
be
enhanced,
so
continuing
and
I'm
just
speaking
for
the
american
gas
association
continuing
the
interactive
discussions
that
we
are
holding
within
the
industry.
Those
candid
discussions
is
absolutely
critical.
B
We
I
can
guarantee
that
we
will
be
taking
the
findings
from
the
ntsb
the
discussions
from
this
hearing
into
our
next
meeting,
which
is
in
may,
we
will
be
discussing
what
we've
learned
I've
already
been
sending
out
to
the
aga
members
tidbits
from
this
hearing.
To
give
them
here
are
some
of
the
things
that
you
should
be
thinking
of
the
more
we
can
communicate
the
more
we
can
share
information.
B
B
Active
dialogue
with
the
industry,
we
will
be
sending
an
invitation
to
the
ntsb
to
participate
in
our
executive
leadership
safety
summit.
We
would
love
for
you
all
to
to
join
us
to
talk
about
what
you
can,
if
the,
if
this
case
isn't
closed,
talk
about
how
you
are
learning
from
these
incidents
and
how
we
can
work
together.
Really.
I
I've
said
for
years
that
pipeline
safety
is
a
shared
responsibility.
D
J
J
Okay,
I
believe
that
was
related
to
the
leak
rupture
boundary
lines
operating
above
30
percent
of
the
specified
minimum
yield.
Strength
tend
to
exhibit
a
behavior
where
they
rupture,
as
opposed
to
leak
lines
below
that
level
have
been
demonstrated
shown
over
time
that
it,
if
there
is
a
through-wall
breach
of
the
steel,
the
metal
that
they
would
tend
to
leak
as
opposed
to
rupture
rupture
in
terms
of
having
a
rapid
decompression
and
a
opening
of
a
of
a
same.
Perhaps
an
ejection
of
the
segment
such
as
occurred
at
san
bruno.
J
In
doing
so,
and
and
then
approaching
the
smys
of
the
steel,
you
would
detect
any
or
it
would
rupture
any
defects
that
were
in
the
line.
I
must
say
that
that
doesn't
happen
with
modern
construction.
You
rarely
see
that
happening.
You
don't
see
it
all
that,
often
with
existing
either.
It's
just
an
issue
that
you
have
to
address
and
have
to
be
mindful
of
when
you
develop
a
program
to
assess
the
integrity
of
an
existing
line
because
of
the
vintage
pipelines
and
variability.
D
J
Well,
if
you
have
a
bad
weld
in
in
this
sense,
we're
talking
about
the
world
that
that
the
longitudinal
world,
as
opposed
to
the
girth
world,
the
test
is
designed
to
detect
issues
with
that.
Well,
inline
inspection
tools
are
able
to
find
issues
with
that
weld
as
well,
but
it's
critical
to
find
issues
with
the
longitudinal
scene
to
ensure
that
you
don't
have
an
in-service
failure.
D
C
H
H
D
H
That's
correct,
like
I
also
mentioned
we'd,
be
interested
in
partnering
with
industry
to
try
to
get
additional
sensors
on
these
type
of
robotic
devices
more
time
in
these
unpickable
systems
may
identify
some
of
the
things
that
we've
been
talking
about
over
the
last
couple
days,
so
we
want
to
get
as
many
tools
or
sensors
on
these
robotic
platforms
now
that
we
have
these
platforms
to
integrate
centers
on
all
right.
Thank
you,
mr
smith.
P
We've
already
acknowledged
how
clear
and
cogent
mr
farmer's
description
was
of
the
process
to
inspect
and
test,
and
and
I'm
you
cited
some
standards.
There
were
questions
about
the
training
as
well.
I'm
curious
is
that
the
model
you
know
if
we
were
to
go
out
to
any
property
around
the
country.
Would
we
see
you
know
that's
kind
of
the
certification,
the
approved
model,
or
is
there
variance
around
that
and
how
people
actually
apply?
What
you
described.
P
Would
you
describe
the
standard
if
I
go
to
any
property,
am
I
going
to
see
what
you
just
described
being
used
or
are
you
like?
You
know,
you're
in
the
a
category
and
there's
a
whole
bunch
of
b's
and
c's
or
you're
in
the
middle
and
there's
some
people
that
have
a
totally
different
process
is
what
you
describe
the
model
or
is
it.
G
F
G
Api
1163
standard
for
by
example,
is
something
that
all
of
the
vendors
ge
and
all
the
other
vendors
are
totally
familiar
with.
So
if,
if
I
was
an
operator-
and
I
was
specifying
my
project
totally
differently
from
that-
it's
going
to
be
strange
so
because
it's
a
standard
and
it's
accepted
by
the
all
the
vendors
and
it's
now
accepted
by
many
of
the
operators-
that's
what
they
write
into
their
specifications.
G
P
P
Okay,
mr
smith,
one
of
the
questions
we
often
ask
is:
wouldn't
it
be
nice
if
there
was
research
going
on
to
actually
look
at
some
of
these
issues
and
look
to
the
future
and
how
nice
to
be
able
to
talk
about
a
program
that
has
been
in
place
for
a
while,
highly
structured,
and
you
did
describe
a
bit
some
industry
input
with
your
stakeholders,
so
you
have
a
sense
of
what's
relevant.
Can
you
talk
a
little
bit
more
about
your
transfer
process
and
how
you
take
your
findings
and
technology
into
practice?
P
H
Thanks,
it's
a
great
question,
a
great
opportunity
to
follow
up.
We
will
talk
about
long-term
research.
You
know
that
pretty
much
starts
at
the
university
and
academic
level
and
there
has
been
a
lot
of
partnering
with
the
gas
industry
in
the
industry
as
a
whole,
with
academics
to
bring
forth
new
sensors.
You
know
our
program
gets
more
involved
once
we're
past
a
proof
of
concept.
That's
how
we've
been
directed
by
congress
to
be
more
short-term
one
of
the
ways
that
we
can
accelerate
these
tools
out
into
the
market
are
through
technology
demonstrations.
H
We
stage
these
throughout
the
the
research
project
timeline.
We
integrate
our
regional
offices,
our
state
partners,
the
industry
co-funding
it
the
vendors
that
may
offer
the
service
that
we
invite
them
to
these
demonstrations
they're
part
of
demonstrations.
They
see
that
the
technology
is
performing
the
way
it
was
designed
at
these
r
d
forms
or
other
events
that
we've
said.
P
H
So
if
we're
able
to
have
additional
technology
demonstrations,
maybe
at
a
higher
frequency
and
intensity,
it
would
aid
in
bringing
these
tools
to
market,
and
that
was
the
point
I
made
about
additional
resources.
It's
kind
of
a
linear
relationship,
if
you're
having
more
demonstrations
you're
having
more
people
in
front
of
them.
Everybody
is
aware,
and
we
were
able
to
get
that
out.
There.
E
No,
I
would,
I
would
agree
with
robert
that,
as
these
technologies
are
developed,
I
mean
we've
been
running
in-line
inspection
for
well,
since
the
pipeline
integrity
regulations
came
into
place
and
we've
even
seen,
you
know,
developments
and
progression
in
the
tools
and
the
sensitivity
and
their
abilities
to
locate
anomalies,
defects
whatever
it
might
be
within
the
particular
pipeline
segment.
So
we're
very
interested
in
knowing
the
capabilities
of
the
tools,
the
limitations
of
the
tools.
P
I
have
a
couple
quick
ones:
I'm
going
to
try
and
wrap
it
up
in
this.
Okay,
there's
a
lot
of
focus
on
the
technologies,
I'm
curious
what
industry
or
research
efforts
are
going
on
on
the
modeling
side,
I'm
there's
a
lot
of
data
coming
in
now
etc,
and
there's
a
lot
of
sort
of
folks
that
are
working
on.
You
know,
failure,
analysis
and
prediction
kinds
of
things.
That's
another
side
of
this
to
get
those
numbers
sort
of
moving
a
little
bit.
C
Maybe
take
take
that
one.
From
our
point
of
view,
these
tools
are
generating
a
lot
of
information
and
and,
as
we
mentioned,
not
only
for
defects
in
the
pipeline,
but
also
the
position
of
the
pipeline
strain
and
movement
in
the
pipeline
and
also
that
the
history,
the
records
of
everything
that's
on
the
pipeline.
So
one
of
the
things
that
we're
looking
at
at
the
moment
is
software
solutions
that
you
can
actually
overlay.
Multiple
inspection
sets.
C
H
Just
a
quick
comment
to
that
illustration
about
other
than
just
detection:
we
have
a
lot
of
work
going
on
looking
at
the
codes
that
are
out
there
that
use
the
data
that
comes
from
inline
inspection
or
other
assessment
methods
to
understand.
If
the
defect
is
severe,
it
needs
to
be
replaced.
What's
the
remaining
integrity
of
the
system,
what's
remaining
pressure,
a
lot
of
work
going
on
and
materials
to
try
to
understand
that
blowing
up
pipe
destructive
testing
and
working
with
the
right
type
of
team
environment
in
our
research
projects
to
bring
that
to
fruition.
P
P
No
one
said:
let's
go
out
and
replace
the
whole
system
so
clearly,
if
you're
going
to
focus
on
an
aging
system
and
identifying
where
that's
even
a
consideration,
I'm
curious
if
anyone's
done
analysis,
to
understand
where
the
economic
justification
point
is.
When
you
look
at
the
amount
of
operating
at
a
lower
pressure
cost
of
testing,
do
people
have
models
for
sort
of
for
where
that
aging
pipe
is
better
replaced,
giving
its
life
cycle
as
opposed
to
just
keeping
it
there
and
the
testing
process
going
on.
E
Well,
I
can.
I
can
speak
to
that
from
an
operator's
perspective
and
again
for
us
it
would
be
done
on
a
case-by-case
basis,
so
there
is
considerable
cost
to
replacing,
obviously
a
line
segment
in
its
entirety,
but
you
know:
there's
there's
a
point
there
where
making
the
line
pickable
and
then
running
the
inline
assessment.
E
Inspection
with
that
is
going
to
be
perhaps
a
more
economical
solution
to
address
the
threats
to
that
line
at
in
some
cases,
depending
on
what
it
is.
You
know
about
that
particular
pipe.
The
specifications,
the
the
inherent
threats
that
are
with
it.
It
may
not
make
sense
to
do
all
of
the
retrofitting
for
the
smart
pegging
and
then
to
run
the
assessment
just
to
find
out
you
needed
to
replace
it
anyway.
L
L
Okay
and
then
then,
going
to
your
excellent
presentation
about
sharing
best
practices
in
various
areas.
Do
you
also
share
best
practices
in
employee
information
programs
and
what
works
and
what
doesn't
work
and
how
to
get
the
most
information
and
get
you
know
the
employees
to
be
responsive
and
to
trust
that
this
information
won't
be
used
against
them
and
all
those
kinds
of
issues
that
are
addressed
with
those
programs.
B
What
you
expect
is
that
the
company
brings
that
to
aeg's
corrosion
committee
or
one
of
the
other
corrosion
committees
that
exist
in
one
of
the
other
organizations
in
a
secure
round
table
behind
doors
without
with
only
members
of
the
industry,
because
you
want
an
honest
discussion
to
occur.
So
those
elements
that
you
were
that
you
brought
up
on
the
employee
programs.
That's
brought
to
the
technical
committees,
the
managing
committee,
the
board,
at
least
with
an
aga.
L
B
I
would
say
every
sos
is
success,
can't
say
it
fast.
I
would
say
that
every
sos
is
a
success
story,
but
let
me
explain
why,
when
an
sos
comes
in
it's
a
problem
that
a
particular
company
is
encountering
that
sos
that
problem
is
sent
out
to
every
technical
committee
within
aaga
that
could
respond
in
a
valid
fashion.
B
B
L
L
After
all,
this
is
actually
more
prevalent
than
I
thought,
or
else
with
time
it's
becoming
a
trend,
we're
seeing
that
where,
as
technology
is
changing
new
things
happen,
and
somebody
saw
it
first,
so
then
it's
anomaly,
but
then
when
they
start
spreading,
the
word
and
other
people
see
it.
I'm
just
wondering
was
this
event
now
that
the
ntsb
has
put
this
out
on
the
in
the
public
docket
about
what
happened
here
was.
Was
this
distributed
through
your
sos
system
as
a
as
an
anomaly
and
asking
other
people?
Are
they
seeing?
B
L
If
you
do
get
some
feedback
on
that,
I
think
I
don't
want
to
interfere
with
the
investigative
process,
but
I
would
think
any
information
you
get
to
that
effect.
That
tells
how
how
prevalent
this
problem
is
out
there
in
the
rest
of
the
world
could
certainly
be
useful
to
our
investigators.
I
hope
you
would
share
that.
B
A
B
D
B
B
With
integrity
management,
we
know
that
it's
a
challenge
to
gather
information
into
one
place,
to
do
an
analysis
on
it.
We've
had
a
number
of
discussions
about
how
gu,
as
an
industry
as
a
company,
look
at
your
records,
pull
together
the
best
information
you
possibly
can
on
each
segment
of
line
to
determine.
A
B
A
B
The
solutions
that
have
come
up
are
looking
at
each
data.
Looking
at
the
data
from
a
variety
of
ways,
for
example,
if
you're
missing
information
on
a
particular
line,
it's
do
you
have
manufacturing
records
that
can
help
with
filling
in
the
blanks.
Is
there
information
out
there
from
other
sources
that
you
can
utilize?
B
A
Okay,
there
were
questions
asked
earlier
from
the
tech
panel
and
I
kind
of
want
to
go
back
to
them.
If
you
all
can't
provide
answers
today,
then,
if
you
could
provide
them
for
the
record,
I
think
it's
very
important
for
us
to
understand
the
cost
factor
associated
with
many
of
the
different
safety
devices
that
we're
talking
about
valves.
A
Is
there
a
difference
between
remote,
shut
off
valves
and
automatic
shut
off
valves
as
far
as
cost
for
installation
valves
and
other
mitigation
actions,
and
then
I
think
when
it
comes
to
preventative
needing
to
understand
the
factor
of
costs
between
ili
hydrostatic
testing
and
a
replacement
of
the
line,
not
not
specific
dollars,
because
we
understand
each
line,
each
segment
is
going
to
be
very
different,
but
factors
cost
factors.
Can
anybody
speak
to
that
now?.
J
We
don't
have
cost
factors
on
related
to
those,
as
you
acknowledge.
There
are
differences
of
getting
a
magnitude
or
order
of
magnitude.
Difference
between
or
the
difference
ratio
wise
between.
The
two
is
something
we
would
have
to
look
into
when
you're
speaking
of
valves,
you
know
valves
can
be
retrofitted
with
autumn
with
devices.
Some
valves
aren't
suitable
for
that.
So
that
would
be
a
variable
there,
but
that'd
be
something.
We'd
have
to
look
into
okay,.
A
And
it
would
be
great
if
people
want
to
get
back
to
us
for
the
record
if
they
have
some
information
about
costs,
I
think
it's
very
difficult.
How
can
we
expect
a
regulation
to
be
promulgated
or
how
can
we
expect
a
business
to
make
a
decision?
If
we
don't
understand
what
the
costs
are?
It
seems
unreasonable
for
me
that
the
industry
doesn't
have
a
sense
of
of
these
costs.
B
A
B
A
If
I
could
ask
just
to
follow
up
because
there
was
a
question
earlier
and
I'm
not
sure
I
quite
got
it
got
it
down
in
my
head.
How
much
does
the
industry
spend
annually
on
safety
efforts,
and
I
don't
know
if
you're
differentiating
between
safety
and
r
d,
that
might
be
two
different
pots
for
you
or
a
subset
of
you
know
one's
a
subset
of
the
other.
B
A
A
A
J
The
two
products
are
different,
so
they're
are
different
risks
associated
with
each
with,
as
was
pointed
out
with
liquid
lines,
there
are
options
for
using
ultrasonics
that
you
don't
have
with
gas
lines,
but
the
the
the
goal
is
the
same.
To
address
the
risk
and
the
the
techniques
to
assess
risk
are
similar.
It's
just
the
risks
and
the
the
relative
value
for
for
one
versus
the
other
may
be
different.
Depending
on
what
you're
dealing
with.
J
Well,
those
would
be
a
concern
in
either
case,
usually
with
a
with
a
line.
That's
already
accepts
that
already
accepts
pig,
pig,
pigging
or
inline
inspection.
It
is
more
conducive
for
water,
removal
than
say
an
interconnected
and
trust
state
pipeline
just
from
a
practical
point
of
view,
but
the
concern
over
leaving
water
there's
equal
concern
over
removing
the
water
to
address
potential
internal
corrosion
issues,
for
instance,.
Q
Hey
it's
our
life.
You
know
this.
This
is
what
we
do
so.
Thank
you
very
much
for
your
patience.
I
just
I
just
have
one
and
I
there
we
have
tons
of
questions
which
we've
offered
to
talk
with
your
technical
panel
about
offline,
but
I'm
just
interested
in
one
concept
that
really
for
the
panel.
Anyone
feel
free
to
comment
on
this.
Clearly,
this
is
private
infrastructure.
Q
Q
What
are
the
constraints
financial
constraints
here
I
mean
no
operator
that
I've
ever
met
wants
to
have
a
pipeline
failure
with
the
tragic
consequences
like
you've
seen
in
san
bruno
clearly
so
you're
constrained
in
some
way,
and
I
assume
that
somewhere
in
there
is
the
rate
setting
environment,
so
I
would
just
I
would
welcome
comments
and
if
you
can
give
a
concrete
example,
I'd
welcome
it
where
operators
go
in
for
replacement
and
then
what
happens
after
that.
So
thank
you.
E
E
B
Looking
at
it
from
a
national
perspective-
and
I
this
was
brought
up
by
mr
metro
yesterday-
there
is
a
balance
within
the
state
of
keeping
rates
low
for
the
customers
and
ensuring
pipeline
safety.
What
we
see
in
some
states
is
rate
mechanisms
that
allow
for
quicker
replacement
of
pipe
other
states.
It's
a
bit
more
of
a
challenge,
so
it
really
does
vary
from
state
to
state.
J
Well,
the
interstate
systems
are
for
natural
gas
anywhere
subject
to
ferc
jurisdiction
and
there's
a
rate
factor
there
involved
with
obtaining
approval
to
replace
lines.
Certainly
they
have
the
ability
to
maintain
them,
but
when
it
comes
to
replacement,
there
is
there's
that
added
economic
justification
balanced
with
the
safety
concern
to
seek
and
obtain
approval
to
replace
pipelines.
D
H
D
A
E
So
to
that
end,
we
are
working
with
our
regulator,
who
has
requested
of
us
that
they
would
like
to
see
all
of
our
transmission
mileage
be
assessed
within
new
jersey,
and
they
would
like
to
see
that
done
on
an
accelerated
schedule
prior
to
the
end
of
2013,
and
we
are
working
to
try
to
meet
that
goal.
Presently.
A
E
But
referencing
those
state
pipeline
safety
regulations
again
after
that
terrible
incident
in
edison,
the
regulations
have
changed
over
the
years
and
we
are
required
to
perform
as
local
distribution
company
operators
within
the
state.
We
are
required
to
perform
annual
drills
and
an
annual
valve
assessment
of
our
transmission
system,
such
that
we
have
to
revisit
all
of
our
valves
and
based
on
the
drill
and
the
an
audit
of
that
drill.
E
The
success
of
how
that
emergency
drill
was
responded
to
then
go
back
through
the
system
and
look
at
all
of
our
valving
and
determine
whether
or
not
those
valves
would
be
suitable
for
being
ranked
as
either
a
low,
medium
or
high
priority
for
retrofitting,
either
into
automatic
or
remote.
To
that
end.
Today
we
don't
have
any
remote
or
automated
block
valves
in
our
system.
We
do
have
remotely
controlled
valves
at
system
take
points,
but
we
are
currently
looking
into
potentially
adding
valves
in
certain
sections
of
our
system.
E
A
Okay,
if
you
wouldn't
mind
once
that's
completed
and
submitted,
if
you
would
share
that
with
our
investigative
team,
yes,
thank
you-
and
you
mentioned
earlier
that
that
the
estimate
for
pigging
the
entire
interest
state
system
was
approximately
12
billion
dollars.
Did
that
include
distribution
as
well
as
transmission
lines,
or
is
it
just
transmission.
A
J
I
can
provide
that
for
the
record.
I
do
have
some
some
current
information
related
to
post
integrity
management
about
140,
000
miles
of
gas
transmission
pipelines
have
been
inspected
using
one
or
more
assessment
methods
that
are
specified
in
the
im
rules,
and
this
includes
mileage
outside
of
hca.
It's
about
six
and
a
half
percent
of
all
pipeline
transmission
pipelines
are
considered
nhcas.
A
I
I
have
not
heard
of
any
on
a
on
an
ongoing
basis.
There
are
some
tools
where
there
might
only
be
one
or
two
in
a
certain
size,
so
if
they
get
are
in
use
in
some
place,
ge
and
the
other
companies
will
send
these
tools,
sometimes
all
over
the
world.
So
sometimes
someone
else
might
be
using
them,
so
you
might
not
be
able
to
get
them
next
week
or
the
week
after,
but
I
have
not
heard
of
someone
having
a
problem
getting
one
eventually.
You
know
within
the
the
time
frames
of
the
rule.
B
J
J
I
think
the
that's
still
under
investigation
is
is
what
it
appears
to
be
from
our
standpoint:
it's
not
conclusive,
that
that
was
actually
a
joiner
situation
versus
a
situation
where
it
was
perhaps
a
pup
welded
to
the
end
of
another
pipe
separately
from
the
pipe
manufacturing
process.
I
think
there's
some
theories
related
to
that,
but
it's
not
conclusive.
A
A
A
A
We
have
no
other
witnesses
to
testify,
so
this
portion
of
the
ntsb's
investigation
into
the
pipeline
accident
in
san
bruno
is
concluded.
The
record
will
remain
open
for
additional
materials
requested
during
the
hearing
on
behalf
of
my
fellow
board
members
and
the
ntsb
staff.
We
extend
our
appreciation
to
all
of
the
participants
in
this
hearing.
A
We
look
forward
to
completing
our
investigation
and
sharing
our
final
report
with
you
in
the
coming
months,
I'd
like
to
acknowledge
our
staff
from
the
pipeline
division
and
the
office
of
research
and
engineering
from
the
on-scene
investigation
to
all
of
the
lab
work
that
was
done
and
the
urgent
safety
recommendations
that
were
crafted
over
the
december
holidays.
You
have
worked
tirelessly
to
document
the
evidence
and
develop
the
facts
so
that
they
are
known
and
that
preventative
actions
can
be
taken.
A
We
actually
poached
some
staff
from
other
other
offices
in
the
agency.
Our
hearing
officer,
lorenda
ward,
is
one
of
our
most
experienced
aviation
investigators
in
charge
and
she
has
lent
her
services
to
the
division
and
specifically
provided
a
great
deal
of
help
to
this
hearing.
So
we
thank
you
and
I'd
like
to
acknowledge
that
we've
put
a
real
challenge
out
for
our
staff,
not
only
to
complete
a
public
hearing
on
this
accident
investigation,
but
also
to
complete
a
final
report
and
bring
that
to
the
board
in
less
than
a
year.
A
Obviously
that
will
depend
on
many
things
as
far
as
technical
information
to
be
developed
and
potential
government
shutdowns
that
might
be
looming
and
other
things,
but
I
have
every
confidence
in
our
staff
that
they
will
continue
to
work
as
hard
as
they
can
to
meet
that
goal,
and
I'm
very
much
appreciative
to
the
managing
director's
office
for
putting
on
loan
a
great
attorney
and
one
of
the
best
writers
that
we
have
at
this
agency.
Karen
bury-
and
I
know
if
anybody
can
help
to
write
this
report
quickly
and
do
it
thoroughly.
It's
karen.
A
The
past
three
days
have
shined
an
additional
light
on
the
facts
and
circumstances
of
the
september
9th
accident
and
they
afforded
the
public
and
the
pipeline
industry
a
window
into
this
investigation,
and
I
think
everyone
in
the
audience
for
lasting
with
us.
This
has
been
quite
a
marathon
and
I'd
like
to
recognize
congresswoman
speer,
who
has
been
with
us
throughout
three
days,
and
we
very
much
appreciate
her
interest
and
support
in
our
investigation.
A
We've
talked
about
safety
policies
and
procedures
and
how
operators
evaluate
evaluate
the
integrity
of
their
pipelines
and
mitigate
the
risk.
We've
discussed
emergency
response
plans
and
how
to
evaluate
public's
awareness
so
that
communities
are
better
informed
and
better
prepared
when
there
is
an
emergency.
A
A
A
Following
the
technical
review,
you
will
have
the
opportunity
to
submit
written
submissions
regarding
your
conclusions
and
recommendations
about
this
accident.
I
invite
and
encourage
you
to
do
that.
It's
beneficial
to
the
board
in
our
analysis,
to
have
that
perspective
and
it
offers
the
parties
an
opportunity
to
share
their
views
for
the
record.
A
A
The
information
developed
during
this
hearing
will
result
in
some
of
the
attendees
taking
actions
in
advance
of
the
completion
of
our
report,
and
that's
as
it
should
be.
The
lessons
learned
from
this
hearing
in
the
san
bruno
rupture
can
prevent
another
community
from
having
to
experience
a
similar
tragedy.
A
A
A
Ted
has
spent
37
years
working
for
the
federal
government
and
we
have
been
so
privileged
that
24
of
those
have
been
at
the
national
transportation
safety
board.
What
does
24
years
at
the
ntsb
mean
well
for
ted?
It's
meant
54
major,
go
team
launches
and
about
a
hundred
hearings
like
these.
If
you
can
imagine
sitting
through
a
hundred
hearings
like
this
and
and
watching
the
board
complete
about
500
major
accident
investigation
reports.
A
A
A
A
I
want
to
tell
you
that
ted
emulated
a
quote
that
was
made
famous
by
edward
r
murrow
to
be
persuasive.
We
must
be
believable
to
be
believable.
We
must
be
credible
and,
to
be
credible,
we
must
be
truthful.
Those
were
always
ted's,
guiding
light
guiding
principles
for
the
work
that
we
did.
Let
me
tell
you
a
little
bit
about
this,
this
man.
A
And
I
have
to
say,
though,
that
ted
showed
his
kindness
when,
in
april
of
2007,
there
was
a
massacre
at
virginia
tech
that
killed
33
students,
ted
came
by
my
office
and
he
brought
me
a
uva
alumni
magazine
and
said.
We
are
all
hokies
when
he
retires.
His
plans
are
to
spend
time
with
his
wife,
his
dog
and
his
grandchildren,
and
he
said
in
that
order,
and
let
me
tell
you
that
his
wife,
droocy
and
ted
possess
a
very,
very
special
love.
A
If
everyone
had
a
relationship
like
ted
and
drucy,
I'm
afraid
we'd
have
a
lot
more
retirements
at
the
ntsb
ted
sent
a
farewell
to
the
employees
and
in
closing
I'd
like
to
share
with
you,
he
mentioned
that
when
he
worked
in
communications,
they
used
to
have
to
listen
to
the
clickety-clack
of
the
ap
and
the
upi
international
wire
machines
all
day
and
things
sure
have
changed.
He
said
from
wire
machines
to
the
internet,
from
fax
machines
being
invented
and
then
junked
from
carbon
paper
to
photocopiers
to
laser
printers
from
wall
size,
computers
to
iphones.
A
All
of
this
during
the
course
of
one
career,
I
can't
imagine
what
somebody
starting
a
career
today
will
see
before
reaching
his
or
her
retirement
ted.
I
know
that
we're
going
to
see
a
lot
of
new
and
innovative
things
in
the
future,
but
regardless
of
what
machines
do
and
how
they
change
the
way
that
we
work.