American Oil and Gas Reporter - January 2015 - 128

This underutilization is not driven by
a lack of understanding or desire, but
rather by the fierce pace of drilling, which
compromises our ability to fully understand reservoir conditions and performance. This practice, however, is changing
by economic necessity as operators are
allocating more time to model and analyze
local reservoir conditions and properties
(stress, rock composition/mineralogy,
total organic carbon, etc.) in search of
correlations and analogs that can be used
to better predict reservoir performance
outcomes in new acreage areas. Additionally, technology providers have been
challenged to improve the time to a
quality reservoir model that captures the
totality of exploration and completions
technology and data.
Reservoir Geophysics
The industry's focus on optimizing
the development of low-permeability oil
plays is increasing the relevance of reservoir geophysics. Specifically, tight oil
reservoirs have accelerated the development
of seismic imaging and reservoir characterization methods that greatly enhance
geoscientists' understanding of the geomechanical properties of the subsurface.
Today, seismic imaging procedures
are able to use surface-recorded seismic
data to recover images of fracture intensity,
fracture density, fracture orientations,
stresses, brittleness, facies, and even estimates of total organic carbon. These
images can help geoscientists and engineers define permeability and low-stress
zones, identify preferred drilling directions,
and optimize well spacing.
To recover and characterize fracture
orientations and intensities, geophysicists
must be able to model the geometries of
the fractures described by their amplitude

or velocity behaviors. Fractured reservoirs
or reservoirs under stress exhibit anisotropic velocity behavior described by variations
along the principle axes of symmetry.
Two types of fracture-related anisotropy
that are routinely modeled in tight oil
formations are horizontal transverse
isotropic (HTI) anisotropy and orthorhombic anisotropy. The former describes vertical fractures in homogeneous media,
while the later describes vertical fractures
in layered or compacted media.
To model brittleness, fracture densities,
facies and total organic carbon, geophysicists must recover accurate amplitudes
from prestack time or depth migrations.
These amplitudes are subsequently run
through different inversion or classification
procedures with calibrations and transformations with well log data to generate
the desired property.
While all this sounds routine, results
from traditional seismic imaging and inversion methods often are deemed unsatisfactory or unreliable. Traditional approaches for imaging fractures with the
seismic method often rely on azimuthal
sectoring of seismic data at the acquisition
surface. Unfortunately, this process both
undersamples and averages the data,
masking and compromising the seismic
signatures that are required to accurately
measure fracture and stress orientation
and intensity.
Accurately determining fracture properties from seismic data requires that we
localize the seismic operator in situ,
similar to the way a cross-dipole sonic
tool scans a formation. This is not a
trivial process. In addition to localizing
the seismic operator, data need to be
sampled in all directions with the highest
levels of directional (azimuthal), temporal
and amplitude resolution.

FIGURE 1
Full-Azimuth, 5-D Common Reflection Point Image Prestack Gather

128 THE AMERICAN OIL & GAS REPORTER

New 5-D Procedure
To improve on these traditional processes, a new procedure has been developed
for the seismic imaging and characterization of fractures. This procedure performs a five-dimensional decomposition
and imaging of surface-recorded seismic
data in situ, in depth, and over all azimuths
and angles. Figure 1 shows a full-azimuth,
5-D, common reflection point image,
pre-stack gather used to characterize tight
oil formations.
This remarkable "full-azimuth" imaging and characterization procedure has
been demonstrated to measure fracture
anisotropies with the highest levels of
accuracy (less than 1 percent in the Eagle
Ford), and resolve the intensities and
orientations of stresses and fractures required by reservoir geoscientists and engineers to plan their well programs. It
also has been demonstrated to detect
and image dual-fracture systems in the
Bakken.
Figure 2 displays full-azimuth, common reflection angle image gathers exhibiting (HTI) fracture anisotropy. The
Eagle Ford gather, exhibiting 1 percent
anisotropy, is shown on the left, while a
Bakken gather with dual fractures is in
the middle. A stress orientation and intensity map from the Eagle Ford is on
the right.
Moreover, the robust local angle domain amplitudes recovered in the process
are highly suitable for inversion and classification processes that deliver estimates
of brittleness, total organic carbon, and
facies. When integrated with the fracture
determination outputs, interpreted lowstress areas or zones with low compressional/shear velocities reveal "sweet spots"
that can be qualified and calibrated with
wellbore data Figure 3 shows a full characterization of an Eagle Ford Shale play
using full-azimuth, angle domain image
gathers.
Depthing issues are mitigated or eliminated with this procedure, since incorporating full-azimuth tomography into
the workflow reduces the mathematical
non-uniqueness of the velocity model,
positions the seismic data properly in
depth, and improves the landing and
steering of horizontal wells. A mistie tomography procedure also allows geologic
constraints (well markers) to be incorporated in the velocity updating process as
a "redepthing" (depth-to-depth) procedure.
These highly valued additions are ideal
for tight oil plays, where thousands of
well markers are available. With the
proper technology, seismic data are, indeed, highly relevant to the exploration
and development of tight oil reservoirs.

American Oil and Gas Reporter - January 2015

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