American Oil and Gas Reporter - July 2015 - 103

SpecialReport: Seismic Acquisition & Reservoir Modeling

Technology Predicts Frac Performance

time window of interest is imaged by
"streaming" the passive signal through
the depth-imaging algorithm that sequentially focuses every smaller time window
of the total time of investigation into
every depth voxel being investigated.
The streaming method focuses all the
seismic signals that come from each voxel
into multiple depth volumes, and the signals for each voxel of the volume are integrated over all of the time windows.
The result is a single depth volume that
is used to extract volumetric fracture images for the depth volume. This single
final depth volume contains the fracture
surfaces that are extracted to compute
the volumetric fracture images.
Data Examples
Figure 1 illustrates the imaging of
each voxel for each time window. The
trace data were created using a waveequation modeling program. The four
trace data panels are the same traces and
are sorted exactly the same for each
panel. An impulse was generated at reservoir depth and the response was recorded
at each receiver at the surface. The traces
are focused on four x, y locations in the
depth volume of investigation (indicated
by red circles in the image slice, with the
arrows pointing to the trace panels focused

FIGURE 1
Example Trace Data Focused on Four Locations at Reservoir Depth
* All Displays Show the Same Traces in the Same Sort
Order
* Each Panel Has Been Focused for a Different x, y, z
* Image Volume Integrated over Entire Time Window

X (5,000 ft.)

No Signal at Focused Location

Y (5,000 ft.)

MISSOURI CITY, TX.-Using passive
microseismic data recordings from a
buried grid to compute fracture image
volumes before and during hydraulic
fracturing treatments, as well as during
production operations, gives operators a
new approach for managing unconventional reservoirs.
The fracture imaging method uses
depth imaging applied to total trace
energy, including long-duration signals
(LDS), to focus the recorded signal to
the location of origin in the rocks. This
"focused signal" is integrated to produce
the depth volume for computing a detailed
frac image volume. Applying the technology to the time interval before pumping
a frac job allows pretreatment frac performance predictions, while applying it
during a frac treatment and while producing a well provides good measures of
the treatment-activated fracture volume
in near-real time, and enables accurate
mapping of the post-treatment active frac
volume as production proceeds.
Computing the producing volume at
regular intervals over time provides valuable insights to enable improved decision
making with respect to optimizing frac
treatment designs in future wells and determining where and how to drill infill
wells. Installing shallow buried grids over
the reservoir permits efficient and costeffective data recording for monitoring
frac treatments and computing producing
volumes for multiple wells. A byproduct
of the fracture imaging method is the
ability to store the first instance of activation for each segment of each fracture,
which allows detailed analyses of the
time sequence in which rocks are broken
during hydraulic fracturing.
Fracture imaging technology can be
described best as a one-way travel-time
prestack depth migration of microseismic
data. The signals travel one way from
the reservoir to the receiver. For conventional surface reflection seismic data, the
signal travels a two-way path from the
source on the surface to the reservoir
and then back to the receiver on the surface. Passive seismic and reflection seismic
require the same velocity and statics models. However, the difference between

them is very large. Passive seismic has
one-way travel time through the earth,
and the signals are direct arrivals without
depending on the reflections at impedance
boundaries.
In addition, passive signals suffer attenuation only from one transmission
through the subsurface. The attenuation
of reflected seismic signals is double that
of passive seismic signals, and the energy
reflected from the impedance boundaries
is small compared with the source energy.
The initial velocity model is constructed
using data such as sonic logs, vertical
seismic profiles, and/or stacking velocities
from reflection seismic data. The velocity
model can be fully 3-D or anisotropic.
The velocity and statics models for
passive data must be refined using calibration shots such as perforation shots or
string shots, and cannot easily be estimated
directly from the data. When these types
of calibration shots are not available, the
initial models can be taken from a surface
3-D reflection seismic volume covering
the area.
For passive seismic signals, the key
spatial parameters (x, y, z and time) are
all unknown. In order to image the passive
signals, the time of investigation and the
spatial volume for investigation must be
chosen. The depth volume for the entire

Time

By Charles Sicking,
Jan Vermilye
and Alfred Lacazette

One Hypocenter at Focused Location

* Imaged Volume
Depth Slice
* Amplitude in Image
Varies by the
Amount of Signal
10 Hypocenters at Focused Location

3 Hypocenters at Focused Location

JULY 2015 103



American Oil and Gas Reporter - July 2015

Table of Contents for the Digital Edition of American Oil and Gas Reporter - July 2015

Contents
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American Oil and Gas Reporter - July 2015 - Contents
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