American Oil and Gas Reporter - July 2018 - 66

SpecialReport: Horizontal Wellbore Construction
FIGURE 5
3-D Fracture Geometry Output from Calibrated Model
View along the transverse fracture face

Coming In August
As the industry moves to full-field
development of resource plays, part
two of AOGR's Horizontal Wellbore
Construction series features the inside story of how Bakken operators
are placing new child-well laterals
with pinpoint precision within 10-20
feet of existing legacy and horizontal
wellbores at a depth of 8,000 feet.
Guest authors also present a case
study of an innovative approach to
stage isolation that helped a Permian
operator effectively refrac a 26-stage
lateral in a single trip in the Delaware
Basin.
66 THE AMERICAN OIL & GAS REPORTER

justments throughout the treatments, and
it was possible for the model to match
each perforation cluster's volume to within
1 percent of the measured value.
The stress-shadowing ability of the 3D fracture model generated an asymmetry
in each stage's fracture dimensions. These
fracture dimensions then were compared
to the asymmetry observed from the surface microdeformation analysis. This additional step provided validation for the
model or identified the need for additional
refinements.
Some of the stages contained both
surface pressure and bottom-hole pressure
with downhole pressure gauges. It was
possible to obtain a good general pressure
trend match during the treatment and
also good instantaneous shut-in pressure
and leakoff pressure matches in both the
surface pressure and downhole pressure.
The microseismic events measured
during the treatment were used to adjust
the generated fracture heights and lengths,
in general. Heights also were calibrated
by the microdeformation results. Ensuring
the modeled fracture dimensions are
constrained by the measured data and a

Key Takeaways
Key takeaways from the stimulation
phase of the project include:
* The operator learned the optimal
well completions order to enhance recovery and minimize the longitudinal
effect observed resulting from stress interactions. This was applied to subsequent
completions in the field.
* The operator was able to compare
interwell interference information with
production interference testing performed
during a later phase of the project. This
led to improved well spacing.
* Constraining the fracture models
and obtaining an excellent match to measured microdeformation data provided
confidence in the approach. This information can be used to generate constrained
and calibrated fracture models for the
entire well pad and help make key decisions concerning well spacing, completions
size, number of stages and completion
order.
* Many factors comprise such proj-

FIGURE 6
Hydraulic Determination Index
(Predicted and Measured Fracture Asymmetry)
-1,000

1,000

2,000

Northing (ft)
3,000
4,000

5,000

6,000

7,000

8,000

-2,000
Easting (ft)

stress) from the log-derived rock properties, as well as obtaining an accurate
value for pore pressure, process zone
stress, critical fissure opening pressure,
and pressure-dependent leakoff. All of
these parameters influence fracture growth
and only can be measured from the pressure decline analysis of an injection test.
The DFIT also was able to provide an
upper limit on reservoir permeability.
The objective was to perform a postjob pressure history match for each stage
that not only would honor the information
from the microseismic data, but also incorporate the volumetric information from
the DTS analysis. Typically, it is possible
that a net pressure history match can
result in multiple fracture geometries satisfying the match. In such a case, the
model needs to be constrained by additional physical measurements.
The 3-D fracture model used for postjob pressure history matching is able to
adjust the perforation information and
match the volume of fluid that passes.
This capability was used to perform ad-

Map view

pressure history match establishes a calibrated model.
Figure 5 shows the 3-D fracture geometry output from the calibrated model
showing the relationship to microseismic
data, while Figure 6 shows an overlay of
the predicted fracture asymmetry to measured asymmetry from surface microdeformation.
Performing this calibrated and constrained fracture modeling provided high
confidence in the obtained fracture geometry given the excellent match with measured microdeformation data. These constrained models helped decision making
on a well-pad level and combined all diagnostics information to allow design
changes.

-1,000
0
1,000

0.0

0.1

0.2

0.3
0.4
0.5
0.6
0.7
Hydraulic Determination Index (HDI)

0.8

0.9

1.0

American Oil and Gas Reporter - July 2018

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