American Oil and Gas Reporter - May 2015 - 82

SpecialReport: Study In Geophysics
positional uncertainty in geology and
well paths," Dorn says. "This provides
the engineers with the information they
need to optimize the drilling positional
survey program, thereby minimizing the
cost of drilling while maximizing the
chance of hitting the target."
Boundary Detection
Dorn says innovations in interpretation
algorithms and workflows continue unabated. He cites advances in geologic
boundary imaging and interpretation for
faults and fractures, salt, canyons and
channels.
Imaging and interpreting salt boundaries in seismic volumes can be very
time-consuming, Dorn allows, explaining
that an initial salt interpretation is made,
then is updated in a number of iterations
to improve imaging of sediments below
the salt. Each iteration involves modifying
the salt mesh and reprocessing the seismic
data using the new salt body.
Dorn says, "Seismic processing has
improved to the degree that interpreting
and editing the salt body consumes more
time than remigrating the seismic volume."
Today, he says, "Interpreters can edit
the salt boundaries as a connected surface

in 3-D, substantially reducing the amount
of time spent by the interpreter and reducing the time to produce the final salt
model."
This new approach can improve model
updates by an order of magnitude, he
says.
Canyon boundary detection is another
significant innovation, Dorn continues,
that both saves time and improves accuracy. Canyons typically represent a major
event cutting through underlying rock.
Over time, he explains, the canyon fills
with deposits that may become hydrocarbon-bearing formations.
"Interpreting canyons can be tricky
because the steeper sides are imaged as
discontinuities, while the base of the
canyon typically is imaged as a seismic
reflection," Dorn describes.
He says auto-extracting the canyon
boundary substantially reduces the time
required for interpretation, and supports
more detailed analysis of depositional
systems by allowing independent removal
of structures outside and inside the canyon.
Better coherent noise management has
improved fault and fracture detection,
Dorn goes on. Noise is a fact of life in
seismic data, and often makes its way
into the final volume. It is incumbent on

Phase 52 Snipe 2-D Seismic Survey

Ogo FAN 3-D Seismic Survey

Nessie FAN 3-D Seismic Survey
TGS 3-D Seismic Surveys

TGS expects to begin collecting data on its Phase 52 Snipe 2-D survey in Mexican waters
by midyear. Last year, the company partnered with FairfieldNodal on two projects in U.S.
Gulf waters. The Nessie FAN 3-D project near the Mississippi Delta is complete, while
the Ogo FAN 3-D survey in the Eugene Island protraction area will be completed later
this year. Both projects feature long-offset, full-azimuth nodal data complemented by
historical production data.

82 THE AMERICAN OIL & GAS REPORTER

interpreters to understand how noise appears
in seismic data. Dorn says once noise is
out of the way, attributes are much cleaner.
He calls noise processing a complex endeavor that sometimes requires removing
acquisition footprints in in-line, cross-line,
and oblique orientations.
He says a new approach makes multiple
passes through the data; each pass eliminating a specific linear orientation and
wavelength. This approach should be the
first step in any interpretation workflow,
Dorn advises. He adds that the risk of
any noise reduction is the loss of actual
signal. This risk is minimized by orienting
the process to local structure everywhere
in the seismic volume. The reward is
clearer definition of faults, fractures, and
other subsurface features.

Mapping The Gulf
Mexico opening its waters to outside
industry has generated tremendous excitement, observes Robert Hobbs, chief
executive officer of TGS. "There is every
reason to believe the geology in the southern Gulf of Mexico is fantastic," he enthuses.
There also is a great need for seismic
data acquired with new technology to
support the great interest from oil companies, which Hobbs calls a perfect recipe
for multiclient surveys. "Everyone wins
when they can gain quick access to subsurface insight at shared cost," he declares.
He reports TGS expects to receive a
permit by midyear for its first survey in
Mexican waters. "We plan to acquire a
very broad and complete grid of 2-D
seismic data," Hobbs says, adding that
TGS will do its own interpretation, which
will guide the next 2-D or multiclient 3D acquisition project.
Already the company is acquiring a
narrow-azimuth 3-D survey called Panfilo
in the Lund protraction area close to the
Mexican border, Hobbs reveals. Even
closer to Mexican waters is a survey
called Phase 52 Snipe. "This 2-D survey
is designed to link with our first Mexican
waters survey," he announces. "We will
extend Phase 52 lines across the Mexican
border, once we receive the permit."
He says TGS expects to have one
boat in Mexican waters acquiring data in
the first half of this year, and as many as
four by year end. Assuming the permitting
process stays on schedule, Hobbs says
fast-track interpretations should be available toward the end of 2015.
American Oil and Gas Reporter - May 2015

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