American Oil and Gas Reporter - January 2015 - 131

TECH TRENDS
azimuth, prestack seismic fracture and
property attributes; core petrophysical
data; well logs; and production data, correlations emerge that enhance our predictive powers in assessing rates and reserves.
Emerging technology is playing a key
role in this assessment with significant
advances in earth modeling integration
and visualization. For stimulation, this
includes a comprehensive integration of
measured (microseismic) events, production surveillance data, and chemical and
radioactive tracer data in a 3-D setting.
Once these data are assembled, the next
step is to animate this information, allowing the geoscientists and engineers
to search for relevant correlations and
better understand fracture evolution.
To help in this visual correlation and
better model the hydraulic flow inside
the formation as a function of time, new
algorithms have been developed to simulate the flow of water inside the activated
fracture network. The activated fracture
network is constructed from filtered microseismic events and incorporates their
time of appearance. This stimulated fracture path can be guided with secondary
information such as preferred fracture
orientation derived from seismic prestack
information or well measurements (Figure
5). The volume of rock "affected" by
these activated fractures can be better
estimated than with conventional eventwrapping techniques.
Given this stimulated volume "parameterized" with attributes such as "tortuous distance to wellbore," we can update
a simulated fracture network with new
fracture aperture coefficients. These small
fractures can be upscaled into standard
corner point reservoir grids as secondary
permeability information. In parallel, we
can automatically pick small faults issued
from attributes such as fault likelihood,
and include these small faults inside a
reservoir model and generate either a
faulted structured grid or an unstructured
mesh. Flow simulation can be run in this
new reservoir model, which incorporates
all of the information collected from microseismic, well data and seismic data.
This type of analysis greatly enhances
the conventional methods of working
with microseismic events, including distance-based computations of stimulated
rock volume as grid regions, envelopes,
and time-dependent volumes. The method

also is able to take advantage of the rich
set of mechanical modeling techniques
available in modern earth modeling systems.
Interpretation Systems
Pulling together all of the field data
and diversity of the processed information
and deliverables is not a trivial task. Interpretation systems need to be able to
incorporate multiple seismic surveys and
extend project areas as new acreage and
data are acquired. They also must incorporate readily accessible and high-resolution visualization methods to co-render

different attributes and maps. For mature
tight oil fields, they must be able to
support some of the largest well databases
in the world, incorporating tens of thousands of well logs and markers. These
are the minimum requirements that characterize a tight oil interpretation system.
Modern interpretation systems must
be equipped to handle production data,
completions data, prestack seismic data,
well log data, etc., and interpreters must
have access to both basic and advanced
seismic inversion methods. Figure 6 shows
integrated interpretation and modeling
canvases to support tight oil reservoir

FIGURE 4
Barnett Shale Multimineral Model with Quality Control Curves

FIGURE 5
Stimulated Fracture Paths from Microseismic and Other Controlling Data

JANUARY 2015 131

American Oil and Gas Reporter - January 2015

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