American Oil and Gas Reporter - January 2015 - 110

JANUARY 2015
One of the primary problems with the shale "factory"
(process business) approach is that low prices often force operators to do exactly the opposite of what is required to survive a
low price environment. Instead of integrating technology to increase production while lowering the extraction cost per barrel
and optimizing reservoir management, operators often abandon
the extraction process approach and revert to drilling individual
wells to hold acreage as a delaying tactic.
This may seem like a good idea in the short term, but in the
long term can result in significantly higher cost per flowing barrel and lower cash flow that ultimately will fail, if prices stay low
for a prolonged period.
The key to optimizing shale performance is to achieve intimacy with the 3-D geomechanics of the target shale and then use
this knowledge to design and implement an extraction process
that maximizes the estimated ultimate recovery per volume of shale
at the lowest possible extraction cost.
Achieving this goal requires full integration of true 3-D seismic, well, drilling and stimulation data to optimize the earth model in highly anisotropic rocks. This requires that the traditional
sources of 3-D information, including modern wide-azimuth 3D data (P-wave and multicomponent where practical), well log
data and geomechanical core measurements be integrated to provide the realistic modeling of the reservoir that will drive reservoir predictions and stimulation management of complex fractured reservoirs (Figure 1).
It is essential that the operator use the full acoustic wave field to
predict reservoir behavior, including full anisotropic properties for
P and S wave fields, and to scale those dynamic measurements to
FIGURE 1

Brittleness variations in the Barnett Shale affect the performance of each well. This slice through a highly brittle zone (A)
shows the lateral variations within the layer while the cross section (B) shows the changes within a vertical section of the shale.
Note the ductile zones near collapse features (yellow arrows)
that should be avoided.

110 THE AMERICAN OIL & GAS REPORTER

their static equivalents, which are essential for frac design and management. To be fully effective, this process of gaining intimacy with
the reservoir must start at the log and core scale to build detailed,
3-D geomechanical models that can be upscaled for use in earth modeling while preserving the fully-anisotropic character of the rocks.
Microseismic
Once intimacy with the reservoir is achieved from the available 3-D predrill information, the next step is to use RTO methods during drilling, stimulation and production to optimize the
extraction process and update the geomechanical earth model in
real time. One area of technology that has expanded rapidly is
using microseismic data collection and processing to help understand fracture propagation during stimulation.
There is a wide range of offerings from various microseismic
vendors that include surface geophone arrays versus downhole
sensors, earthquake location methods versus seismic migration
location methods, and use of P waves versus P and S waves. While
the efficacy of these different methods is beyond the scope of this
article, it is safe to say the industry still is not using microseismic data to their full value because of several factors. These include questions about:
* Detecting events with surface versus downhole sensors;
* The accuracy of event locations in the subsurface;
* Timeliness of the delivery of event locations;
* Lack of integration of realistic earth models into the microseismic analysis process;
* Failure to use robust presurvey earth models for designing
microseismic surveys; and
* Failure to properly integrate microseismic data into the actual stimulation process in real time.
There also is a fundamental lack of understanding about the
relationship between the apparent microseismically stimulated
reservoir volume (MSRV) defined by the microseismic event envelope, the effectively propped volume (EPV) created by the frac
job, and the effectively propped volume of reservoir with sufficient permeability to allow hydrocarbons to flow into the well (the
effective flow volume or EFV).
The most likely scenario is that the MSRV is much larger than
the EPV, and the EPV is somewhat larger than the EFV. Knowing the answer to this question is absolutely essential to optimizing well placements and stimulation processes, and thus to the
success of the reservoir optimization process.
Acquisition And Processing
To get the most out of the microseismic data acquisition during RTO, operators must consider several key factors. First, microseismic acquisition and processing in the field must be done
intimately with the stimulation process. This means that the mi-
American Oil and Gas Reporter - January 2015

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