American Oil and Gas Reporter - September 2024 - 42

SpecialReport: Hydraulic Frac Tech
FIGURE 2
Example Fracture Lengths and Conductivities for the Simple Model
we modeled four spacings: 440 feet, 660
feet, 880 feet and 1,100 feet.
For the uniformity index, a measure
Perfect UI Case
Fracture conductivity (md-ft)
0.0
2.5
5.0
7.5
10.0
Baseline UI Case
Fracture conductivity (md-ft)
0.0
2.5
5.0
7.5
10.0
Low UI Case
Fracture conductivity (md-ft)
0.0
2.5
fully coupled model simulated three
stages with 12 clusters in each stage.
Treatment designs were held constant at
1,000 barrels of fluid and 40,000 pounds
5.0
7.5
10.0
of proppant for each cluster using a
50/50 mixture of 100-mesh and 40/70
sand. To evaluate the impact of well
spacing on the perfect frac stage's value,
of how evenly fluid is distributed across
the clusters in a stage, we looked at three
scenarios. The base case had a UI around
0.75, the average reported by Hess' distributed
acoustic sensing. A standard deviation
of 0.09 was applied to ensure
variations in the model UI matched the
DAS measurements.
To quantify the impact of very poor
uniformity, we also modeled a low-case
UI around 0.25. Because variations are
likely to be more extreme as uniformity
falls, we set the standard deviation for
this scenario to 0.22. This case highlights
the cost of poor performance resulting
from problems, such as plug failures,
crossflow outside the casing stemming
from poor cement, insufficient limited
entry, etc.
Finally, we get to the star of the show.
To model a near-perfect frac stage, we
assumed a UI of 0.95 or higher and a
standard deviation of 0.04 or lower. This
UI reflects the reality that even the best
completion is unlikely to achieve truly
even distribution.
To generate scenarios with different
uniformity indices, we changed: (a) the
random variance in initial perforation
diameter, and (b) constants that affect
the magnitude of perforation erosion.
The near-perfect UI scenario assumed a
uniform initial perforation diameter and
zero erosion.
The modeling assumed that proppant
placed in each cluster is proportional to
the cluster-level fluid volume. Recent
studies suggest that cluster-level proppant
distribution may differ significantly from
fluid distribution because of nuances in
how proppant transport occurs within the
wellbore. Those nuances have not yet
been studied enough for their impact to
be considered here.
Model Predictions
Figure 1 shows examples of the fracture
geometries (upper graphics) and drainage
42 THE AMERICAN OIL & GAS REPORTER

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American Oil and Gas Reporter - September 2024

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American Oil and Gas Reporter - September 2024 - Intro
American Oil and Gas Reporter - September 2024 - Cover1
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