American Oil and Gas Reporter - December 2015 - 60

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SpecialReport: Well Stimulation & Completion Technology
FIGURE 7A

FIGURE 7B
345H Stage 5 Treatment

ward into deeper portions of the formation.
The bulk of the event density was clustered
within the lower-stress zones of the Wolfcamp B that correspond to lower-stress
zones located beneath the wellbore, as opposed to above the wellbore as in stage 5.
The time-dependent difference in the
propagation of the microseismic distribution potentially could indicate changes in
formation properties that are essentially
driving the distribution, and potentially,
fracture growth.

Integrating The Data
In an attempt to understand fracture
geometry and its characterization from microseismic activity and extracted dimen-

sions, a 3-D fracturing simulation workflow was performed. For consistency purposes, there were no step-rate tests prior
to stimulation or post-frac production
logs to help determine the number of clusters taking fluid. All clusters were, therefore, assumed to be active. The simulation
used identical pumping schedules for all
stages, since the actual executed pump
schedule did not deviate significantly
from the initial design.
Simulation frac heights were relatively consistent for the majority of the stages.
They also appeared to be more confined
than the microseismic results. Toe-ward
stages 1, 2, 3 and possibly 4 (none of which
were aligned with stages from the shallow-

FIGURE 8
Well 345H Microseismic Data with P-Impedance Cross-Sections

60 THE AMERICAN OIL & GAS REPORTER

345H Stage 10 Treatment

er 346AH), tended to show greater similarities between simulated and microseismic heights. The Wolfcamp A lateral
appeared to have impacted the upward
height growth. However, that observation
did not apply to all the stages aligned
across the 346AH and 345H laterals.
Although there was no clear correlation
between the simulated fracture and microseismic heights, fracture heights were
smaller and more confined than microseismic growth. To better understand this variability in geometry and unlock the potential of integrated data analysis, 3-D surface
seismic measurements were integrated
with the microseismic results and geomechanical properties.
Figures 8 and 9 show microseismic data
with arbitrary p-impedance seismic crosssections lengthwise along the 345H well's
lateral trajectory. When combining the formation properties obtained from the inverted p-impedance, delineating lateral
changes along the wellbore at different
depths is essential to correlating variations
in microseismic response and subsequent
changes in the developed hydraulic fracture geometry. The parameters extrapolated from seismic can be used on a stage-bystage basis.
Twofold criteria can be used when interpreting mineralogical and geomechanical data from surface seismic integrated
with observed fracture propagation behavior from microseismic events. Incidentally, this also could be used as a means to
high grade acreage for development.
The first criterion is delineating an ideal mechanical bench for landing that has
higher impedance, and is characteristic of
a high calcite volume and high Young's
modulus for enhanced brittleness. This
would result in efficient hydraulic fracture
initiation of wide fracture networks nearest the wellbore to allow pumping optimal
slurry rates, and embedding proppant

American Oil and Gas Reporter - December 2015

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