American Oil and Gas Reporter - April 2018 - 36

VISION2020
enough at decision time. If geophysicists
are not comfortable with communicating
an 80 percent answer, then they are not
going to have the opportunity to communicate any answer, because development
will proceed without them.
Geophysicists today are still learning
the new language of unconventional development. Conversations center on well
placement for greater reservoir contact
and potential communication with adjacent
wells. It is commonplace for geologists,
engineers and geophysicists to collaborate,
making it imperative that geophysicists
start thinking more about how to communicate the value of what we do.
It was enlightening for me to teach a
basic geophysics class that included an
engineer. That student in particular was
thrilled to finally understand how attributes
are extracted from seismic data into the
reservoir model, and the importance of
proper acquisition, processing and interpretation. He later forwarded a paper that
had been presented at an Unconventional
Resources Technology Conference describing the value of geophysics to engineering,
proving that a geophysicist and engineer
can learn to speak the same language!
A friend in the seismic industry has
expressed frustration to me because there
are beautiful datasets that are not being
leveraged by operators. It is up to the
geophysicist to effectively communicate
how these datasets can improve drilling
and completion decisions. Otherwise,
even the best data and interpretations

have no value.
One of the best techniques I have used
to convey the value of geophysics is to
think in terms of well cost. For example,
in five square miles of acreage there
could be 80 wells planned. Divide the
cost of geophysical data and the interpretation across those 80 wells and it
likely will be a slight percentage of the
overall cost per well.
Taking A New Approach
Because unconventional plays fundamentally have changed the way operators
approach reservoir development, geophysicists are having to take a new approach as
well. I break this approach into three basic
categories, increasing in complexity and
effort with each subsequent category.
Finding the resource comes first. Often
geologists and geophysicists just know
where and how complex the resource is
in a basin. They can read it from a regional
standpoint with only a few 2-D lines.
These lines are common, leading engineers
to assume that they are always available
and quickly interpreted.
The second category has to do with
optimizing reservoir contact. Here, the
team is focused on better execution of
the drilling program. I worked with an
operator in the Marcellus Shale that managed to hold a large acreage position by
drilling vertical wells. These wells told
the company that the subsurface was
more complex than what had been indicated by vintage shallow wells. The wells

Proper subsurface imaging with 3-D seismic is fundamental to horizontal well placement. This example shows the planned kickoff angle, in-zone well path and lateral length
based on seismic data interpretation for a Marcellus drilling program in southwestern
Pennsylvania.

36 THE AMERICAN OIL & GAS REPORTER

often hit repeats of the basal limestone,
and when the company began drilling
horizontals, it had to figure out which
zone to geosteer into. There was no
seismic available, often causing them to
sidetrack the wells a number of times in
order to locate the one of interest
The operator had enough of these
wells to determine statistically that one
in six wells had to be sidetracked in order
to steer into the right occurrence of the
shale. Each sidetrack cost approximately
$500,000. The company planned to drill
600 wells in the area, which could cost
up to $50 million in sidetracks in the absence of better information.
Sidetracks could be completely eliminated if the area was properly imaged
because the 3-D seismic would show the
angle for kickoff and whether a well bore
would encounter a fault, causing the well
to be out of zone. From a pure costsavings perspective, the operator could
afford to spend $50 million to mitigate
that risk, in effect, saving $50 million in
sidetrack costs. That is how significantly
3-D seismic influences well drilling.
In addition, seismic analysis can increase the effective lateral length, or the
total feet the well bore is actually in the
zone's sweet spot. The value of the well
is based on how many thousands of feet
are in zone, so this is a direct contribution
to well performance. Economists and engineers on the team know the numbers,
and we as a profession need to get better
at communicating in those terms.
Once there is a good tie-in of rock
properties from horizontals and good data
from well logs, important attributes can
be queried and extracted from the seismic-the third category. For example, the
geophysicist can calculate which rock
zone is more fracable than others. This
comes from simultaneous prestack inversion of carefully designed and acquired
3-D seismic data tied into calibrated wells
with core and good log suites, including
crossed dipole sonic logs. These data
allow extraction of compressional-wave
velocity, shear-wave velocity and density
from the 3-D dataset.
All of this information comes from the
very far seismic traces at the very late
arrival times sorted into well sampled azimuths, which not long ago were not acquired or simply discarded. The design
and acquisition must be carefully planned
and executed to eliminate large acquisition



American Oil and Gas Reporter - April 2018

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