American Oil and Gas Reporter - February 2015 - 69

SpecialReport: Unconventional Resource Science

Method Improves Microseismic Results
By Peter M. Duncan
and Carl W. Neuhaus
HOUSTON-Microseismic monitoring
of hydraulic fracture stimulation in shale
oil and gas development is gaining acceptance around the world as an important
tool for understanding how the reservoir
responds to treatment. These data can
provide important information in real
time that allows the completion engineer
to reduce costs and improve production
by optimizing frac parameters, stage spacing and well spacing.
Legacy methods of microseismic monitoring necessitated deploying a string of
geophones down an observation well
close to reservoir depth. Surface microseismic arrays then were developed to
improve on downhole methods. More recently, a new method using downhole
geometry with surface microseismic imaging principles has been developed to
combine the benefits of lower-cost downhole monitoring with higher-accuracy
surface monitoring.
The traditional method of downhole
microseismic processing is referred to as
"P&S picking." This processing methodology was borrowed from earthquake
seismology and utilizes the arrivals of
faster compressional (P waves) and slower
shear (S waves), which are emitted when
fractures open in the earth during stimulation. The goal of P&S picking is to determine the event locations (where a fracture occurred) and origin times (when a
fracture occurred) associated with the
stimulation.
The geophones used in the downhole
array typically have one vertical and two
orthogonal horizontal component sensors
to allow the geophone to detect the motion
of the earth in all three dimensions as the
waves travel past the array. The array
itself consists of between six and as many
as 100 three-component geophones, typically deployed at 25-foot intervals. Since
the S waves travel more slowly than the P
waves, the difference between the arrival
times of the two wave types will increase
as the distance between the fracture location
and the geophone location increases.
If the difference between the arrival
times of each wave type is known, and
the velocity of the waves in the earth is
known, the distance from the geophone
to the fracture location can be determined.

Figure 1 shows 3-C recordings for a microseismic event illustrating the P- and
S-wave arrivals (left), and a representation
of an event next to the downhole array
with the seismic wave paths (right). The
slope of the arrivals across the array is
an indication of the wave's velocity.
The 3-C geophone also allows the direction in which the wave is traveling to
be estimated, thus a single 3-C geophone
may be sufficient to estimate fracture location. Multiple geophones in one string,
or even better, in two or three strings located in different observation wells, provide additional data points to allow for
more accurate event locations.

in the subsurface.
The successful imaging of fracture
events requires a large enough array to
provide the required resolution and a sufficient number of geophones to delineate
between noise and true fractures. A good
rule of thumb is that the aperture (size of
the array) must be twice the depth of the
target reservoir, and the number of geophones should yield a signal-to-noise
ratio after stack that is greater than 3.0.
An added benefit of this type of surface
array is that it allows for an estimate of
the focal mechanism of the seismic event,
or a measurement of how the rock broke.
It should be noted that most of the Swave field is absorbed before it reaches a
surface array. Fortunately, the size of the
array and the number of geophones are
sufficient to locate and characterize the
event with P-wave data only.
More recently, full-waveform imaging
technology has been adapted for use with
downhole arrays. The motivation for this
was the labor intensity of the P&S picking
process, as well as the inherent bias,
based on results being "picker-dependent."
There have been attempts to correct
these biases by developing auto-pickers.
However, real world situations and noise
make auto-pickers unstable. Therefore,
the industry has continued to rely on experienced interpreters to pick through the
noise and estimate the arrival times.
When there are thousands of events
to pick on tens or hundreds of traces, the

Full-Waveform Imaging
The full-waveform imaging technique
for determining microseismic event locations using a surface array was introduced in 2003. The development was
driven by a desire to monitor hydraulic
fracturing without the limitations of deploying phones at depth in a monitor
well.
In this methodology, the recorded seismic traces (data collected as the waveforms
pass the geophones) are time-shifted relative to one another in proportion to the
travel time differences. The time-shifted
traces are stacked (summed) and the resulting stacked trace is analyzed to determine whether it represents a fracture
event. This stack-and-search process is
repeated for every possible event location
FIGURE 1

3-C Microseismic P- and S-Wave Arrivals (Left)
And Seismic Wave Paths (Right)

Recorded 3-C Data

t
P

Event

FEBRUARY 2015 69

American Oil and Gas Reporter - February 2015

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