American Oil and Gas Reporter - July 2017 - 82

SpecialReport: Seismic & Geophysics
dients resulting from variable elastic properties, natural fractures and pressure depletion encountered not only along the
wellbore, but also all around the stimulated
wells.
The frac design model governs the
initiation and propagation of hydraulic
fractures interacting with the geologic
heterogeneity by calculating the net pressure at the fracture tip. The effect of
lateral stress gradients and the viscous
gradient along the fracture length are incorporated into the fundamental pressure
balance equation at the fracture tip to determine fracture growth. Mass balance,
fluid momentum, and pressure-width relations applied with appropriate initial
and boundary conditions result in a realistic
and fast frac design model.
The leak-off coefficient can be finetuned to account for asymmetry observed
in geomechanical modeling. Once the
optimum reservoir parameters are computed, other design parameters such as
injection rate, fluid viscosity, and proppant
concentration and type can be optimized
to achieve more consistent proppant distribution. With the help of additional
constraints, the model is able to estimate
the fracture conductivity and proppant
concentration.
Figure 3 shows the asymmetric variability of the proppant concentration/distribution in three stages in the Wolfcamp
validation well. At left is the top view of
the microseismic data with its various
characteristic responses. At right are the
respective variable proppant concentrations
along stages 13, 7 and 2 (from top to
bottom). Additional validations of the
frac design can be carried out using treatment data to ensure the modeling effort
reflects actual results. Without continuous
validations with field data, it will be difficult to trust any frac design tool to
avoid frac hits. Operators can use this
workflow to optimize completions and
asset development strategies.

Frac Hit Challenge
In the Wolfcamp project, an existing
producing well posed a frac hit challenge
for fracturing a proposed new horizontal
well. The geometric design of the new
well was modeled for all 40 stages. The
initial treatment plan called for 250-foot
stage spacing with 320,000 pounds of a
100-mesh and 40/70-mesh sand mixture
a stage pumped with slickwater at a rate
of 105 barrels/minute.
The total stage length and frac design
82 THE AMERICAN OIL & GAS REPORTER

volume for the new well was designed
based on the differential stress values
along the wellbore. In areas of low stress
anisotropy, it is relatively easier to achieve
fracture complexity with sufficient proppant placement using a slickwater treatment. Accordingly, in stages with very
low differential stress values, relatively
more clusters should readily accept fluid
as the stage is designed to place clusters
in areas of similar frac gradient. Conversely, in areas with high differential
stress, there will be fewer, but longer

planar fractures. Higher-viscosity fluid
might be required to effectively place
proppant in these stages.
Figure 4 (left) shows an equivalent
fracture model derived from positive curvature seismic data and used as input in
the geomechanical simulator. A strain
map derived after putting pressure in 40
frac stages is shown at right. The red
colors represent high strain values indicating successful stimulation, while the
pink lines represent the estimated geomechanical half-lengths based on the es-

FIGURE 2
Microseismic Data and Estimated Strain at Wolfcamp Validation Well

Heel

Toe

FIGURE 3
Microseismic Data along Three Stages of Wolfcamp Validation Well

American Oil and Gas Reporter - July 2017

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