American Oil and Gas Reporter - January 2015 - 101

Unconventional Resource Science

Study Analyzes Microseismic Activity
By Alice Guest,
Estelle Rebel,
Sean Bailly
and Jelena Kostadinovic
CALGARY-In terms of oil and gas
production, pre-existing fractures can act
as conductive zones. However, intersecting
pre-existing fractures during well stimulation can cause fluid loss into the formation and lead to reduced stimulation
effectiveness, lost pressure, unnecessary
completion cost, and potential environmental issues.
To improve the understanding of the
interaction of hydraulic fractures with
pre-existing structures, a study was conducted to analyze microseismic activity
detected during a stimulation job in a
10-stage horizontal well. The work focused on separating microseismicity related to hydraulic fracture propagation
from microseismicity occurring along
pre-existing structures in an unconventional reservoir.
The analysis combined several techniques to help distinguish various types
of seismicity, including dataset separation,
geomechanical, magnitude-frequency, and
well pressure analyses. The results significantly increased the number of hydraulic fractures and fault/natural fracture
zones compared with the original interpretation, which was based on microseismic mapping alone. Isolating microseismicity relevant only to hydraulic fracture propagation better constrained estimates of hydraulic fracture half-lengths
and improved the operator's ability to
accurately determine the stimulated reservoir volume.
Microseismicity was aligned in two
major trends: east-to-west and northeastto-southwest. Only some stages showed
clear development of a hydraulic fracture.
In some stages, microseismic activity increased toward the end of pumping and
continued strongly afterward. The detailed
analysis also strongly suggested that some
hydraulic fractures were aseismic (i.e.,
not detected by a surface array).
Figure 1 shows the two microseismic
activity trends, with the orange line denoting interpreted hydraulic fractures and
the red line denoting pre-existing structures. The circles are colored according

to stage number, and the diamonds show
the perforation shots for the horizontal
well (black line).
One of the central issues related to
the dataset was whether microseismicity
related to two processes (propagating
new hydraulic fractures versus reactivating
pre-existing fractures) could be separated.
Recognizing that a hydraulic fracture
would most likely propagate in a different
direction than the orientation of any preexisting faults/fractures, could separating
the data according to the process that
created each microseismic event help determine the length of hydraulic fractures?
Other key questions included:
* Were the aseismic areas hydraulic
fractures or unstimulated regions?
* Why did each stage have different
microseismic activity? Was this caused
by local conditions in the reservoir?
* Why was microseismicity recorded
mainly toward the end of pressure pumping
operations and after pumping had ended?
Microseismic datasets are often very
complex and difficult to understand. This
is largely the result of reservoir heterogeneity, geomechanical coupling between
injected fluid pressure and fracture permeability, and stress field variations oc-

curring in the reservoir during stimulation
treatment. Conditions can change from
reservoir to reservoir, and even from well
to well, which can make microseismic
datasets incomparable. Sometimes, analysts attempt to interpret a complex microseismic dataset as a single physical
process, or in a statistical manner. However, it is important to understand the
dataset and separate microseismic data
related to different physical processes
prior to interpretation.
Integrated Method
The 10-stage horizontal well study
used a specialized method to integrate
microseismic, engineering and geomechanical data. This approach tracks temporal and spatial variations in microseismic
activity both during and after injection,
analyzes microseismic trends relative to
the stress field, incorporates engineering
curves (e.g., by correlating pressure drops
in a well when a fault zone is intersected
with changes in microseismic activity),
and distinguishes microseismicity based
on the prevailing magnitudes and range
of magnitudes. The data illustrate how
careful analysis of a dataset and combining
all available information helps improve
interpretations of microseismicity.

FIGURE 1
Microseismic Activity Trends

JANUARY 2015 101

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