American Oil and Gas Reporter - January 2019 - 66

pages 64-69_Layout 1 1/9/2019 10:28 AM Page 66

Unconventional Resource Science
FIGURE 2A

FIGURE 2B
Linear Fracture Growth

Complex Fracture Growth

Stage with Single Pump Cycle

Stage with Two Pump Cycles
828 873

9 360 7,200

882 882

8 320 5,600

736 776

8 320 6,400

784 784

7 280 4,900

644 679

7 280 5,600

686 686

6 240 4,200

552 582

6 240 4,800

588 588

5 200 3,500

460 485

5 200 4,000

490 490

4 160 2,800

368 388

4 160 3,200

392 392

3 120 2,100

276 291

3 120 2,400

294 294

80 1,400

184 194

80 1,600

196 196

700

800

100

xf (ft)

9 360 6,300

Stage Time (min)

equipment failure; however, at times shut
down is unavoidable. This scenario occurred on a select group of stages throughout the completion, leading to a discovery
of the effects these shutdown events were
having on the near-wellbore complexity.
It was observed that shutdown effects
inadvertently inhibited fracture growth,
which allowed the increase in fracture
conductivity in the near-wellbore area.
This inhibition of fracture growth was
not observed for any of the stages where
these shutdown events did not occur. This
led to the investigation of varying pump
rates to capitalize on fracture complexity.
Pressure-based fracture maps identified
this phenomenon of increased near-wellbore complexity, which was not easily
distinguishable using conventional microseismic interpretations.
New Diagnostic Tool
Legacy diagnostic technologies can
be intrusive, expensive and time consuming. Alta Mesa Resources decided to
apply a new oil field diagnostic tool: the
integrated modeling approach for geometric evaluation of fractures that would
overcome many of the challenges of
legacy technology and provide a cost-effective and reliable solution to perform
fracture diagnostics.
The pressure-based fracture map technology is based on the poroelastic pressure
response that occurs during normal hydraulic fracturing of treatment wells. The
pressure response is recorded by a surface
pressure gauge from one or more monitor
stages in wells adjacent to the treatment
well. The monitor and the treatment wells
can be interchangeable. The continuous
pressure data stream from the monitor
66 THE AMERICAN OIL & GAS REPORTER

well does not interfere with normal hydraulic fracturing in the treatment well
and does not require downhole tools or
cause downtime.
After acquiring the pressure data in
the monitor stages, poroelastic pressure
responses must be differentiated from
pressure responses caused by direct fluid
communication or diffusive fluid transport.
Once identified, poroelastic signals can
be used to calculate hydraulic fracture
geometry by matching the observed responses in the monitor stages to a digital
twin. The output, which is the fracture
map, is the fracture dimensions of halflength, height, asymmetry and azimuth,
and how fast those dimensions grew.
The technology maps the largest hydraulic fracture per stage. Impeded growth
of that largest fracture during completions
can be interpreted as improved fluid distribution in that stage. The timing of
when the largest fracture growth is impeded allows the differentiation of whether
the generated fractures are mostly biwing or whether near-wellbore complexity
has been achieved. As in this case of the
four STACK wells, this complexity was
validated with microseismic data.
Creating Complexity
A key goal of the Alta Mesa Resources
project was to evaluate the ability of various treatment designs to prevent bi-wing
fracture growth and generate fracture
complexity. One of the methods explored
in the past looked at reducing the stage
length to promote complex near-wellbore
fracture growth. Completions with shorter
stage lengths become expensive, resulting
in diminishing economic returns. Completing these wells with longer stages is

50
Stage Time (min)

100

xf (ft)

10 400 8,000

10 400 7,000

desirable, but this design requires generating multiple fractures from a given
stage and creating near-wellbore complexity.
Pressure-based fracture maps provide
a unique ability to distinguish linear biwing fracture growth versus multiple
fractures with near-wellbore complexity.
Pressure-based fracture maps quantify
the growth rate of the largest fracture in
a given stage, which provide insight into
the development of near-wellbore complexity.
The fracture dimension of the largest
fracture in the stage, such as fracture
half-length or fracture height, continues
to increase over most (if not all) of the
volume of fluid pumped into the treatment
stage. This results from a single fracture
taking most of the injected fluid, causing
continuous growth of this dominant fracture. On the other hand, when complexity
develops, fluid flow into the largest
fracture is reduced, stopping its growth.
As noted, most of the stages were
completed using a single pump cycle: 98
percent of the stages treated without interrupting the pump cycle showed fracture
dimension of the largest fracture growing
over the entire pumping schedule. This
indicated that many of these stages had
linear bi-wing fracture growth.
Varying the pump rates resulted in
generating near-wellbore complexity. Several stages on this four-well pad were
treated with two cycles with a prolonged
gap between the cycles. Figure 2A shows
a stage treated with a single pump cycle,
while Figure 2B shows another stage
treated in two pump cycles. The red and
the green curves are the computed fracture
growth curves, with the red curve plotting

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