American Oil and Gas Reporter - July 2017 - 63

SpecialReport: Horizontal Wellbore Construction
FIGURE 4
Alignment of Electromagnetic Imaging (Blue and Aqua)
With Microseismic (Colored Dots)

was hindered by the decision to set up
the surface antennae array out to 1,000
feet to the east and west of the wellbore.
A tighter and denser antennae array is
recommended on future EM projects.
Other operational difficulties included errors in antennae and transmitter placement,
high winds, and a lightning strike that destroyed 30 percent of the antennae.

Offset Pressure Monitoring
High-resolution surface pressure transducers monitored the response of offset
wells during stimulation. The project
used Integrated Modeling Approach for
Geometric Evaluation of Fractures (IMAGE Frac®) technology. The technique
relates poromechanically-induced signals
in offset wells to fracture geometry.
Results from the study provided hydraulic
and propped heights, half-lengths and
fracture azimuths. The results corroborated
well with the interference test, fiber data
and tracer data.
Raw pressure signals from an isolated
stage in the heel of Well C were monitored
while stimulating adjacent wells A, B
and D. When the toe stages of the wells
being stimulated were completed, the
poroelastic pressure signals were small,
but as the stages toward the heel were
completed (in closer proximity to the observation stage in Well C), the poroelastic
signals got larger. The poroelastic pressure
signals also were used to evaluate the
geometries of the largest fractures in each
stage.
A measure of uncertainty can be determined by comparing the fracture halflengths in a single well as determined
from two different monitor locations. The
normalized fracture half-length of the
largest fracture in several stages in Well
D as measured from two observation wells
(C and E) showed a variation in fracture
half-length measurements ranging from

1-14 percent with a mean of 7 percent.
The IMAGE Frac technology also was
used to evaluate the effectiveness of diverters at improving fluid distribution
across the stage. The impact of several
hundred diverter drops of various sizes
was examined. In a majority of the drops,
the fluid distribution was not deemed to
have been impacted significantly. However,
for all drop sizes examined, the diverter
improved fluid distribution more than 30
percent of the time. Moreover, in more
than 10 percent of the drops, diverter significantly improved fluid distribution.

Fracture Modeling
A planar 3-D finite difference fracture
model was utilized for simulation. Vertical
open-hole logs from an offset well were
imported to construct the stress profile
and populate the reservoir properties. A
diagnostic fracture injection test was performed in a horizontal well offsetting
the fiber optic well to provide the fracture
gradient, closure gradient and pore pressure
gradient. History matching of multiple

stages from the horizontal completion
provided confidence in the modeled parameters.
A calibrated vertical model using the
properties derived from the open-hole
logs, DFIT and history matching of the
horizontal completion was used to run
sensitivities on fracture geometry based
on actual proppant placed. Figure 5 shows
the conductive geometry variations as a
function of proppant placed in the fracture,
with 100 percent representing even proppant distribution in all fractures. The purpose of modeling various volumes of
proppant placed in a fracture was to allow
a more accurate description of the fracture
geometry based on the fiber optic analysis
results.
Fiber optic monitoring also was used
to evaluate diverter effectiveness. Figure
6 is an example of successful diversion.
The DAS plot (top) shows a shift in the
location of the acoustic response after
the diverter was injected at point B and
again at point C. The signature is validated
through the cool-down of the same clusters
that showed increased acoustic response
at points B and C.
Average cluster efficiency ranged 3375 percent during the treatment of the C
well. Changes ranging from fluid type to
proppant size appeared to be the source
of acoustic signal changes. Diversion
tests were performed in attempt to improve
cluster efficiency using three types of diverters and two completion fluids. One
diverter showed the highest rate of success
in stopping fracture growth, while another
showed no ability to stop fracture growth
but did cause accelerated growth. Two
of the three diverters used in the fiber
optic well commonly showed no impact

FIGURE 5
Conductive Geometries for Range of Proppant Placement Scenarios
300%

200%

150%

100%

50%

25%
JULY 2017 63

American Oil and Gas Reporter - July 2017

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