American Oil and Gas Reporter - September 2019 - 52

SpecialReport: Horizontal Wellbore Architecture
Data acquired during the course of
the spacing trial project included:
· Microseismic monitoring;
· Microseismic depletion delineation
(MDD);
· Radioactive (RA) tracers;
· Chemical oil and water tracers;
· Image logs;
· Bottom-hole pressure measurements
during completion, flowback and earlytime production; and
· Diagnostic fracture injection tests
(DFITs).

reservoir properties for reservoir simulation, the DSU geomodel included rock
properties, stress and other data obtained
from nearby well logs, core and DFITs
for hydraulic fracture modeling. No microseismic data had been acquired on
the H1 when it was completed in 2011,
so fracture geometries were calibrated
using microseismic data from previous
projects and compared with H1's advanced
MDD to ensure reasonable results.
The H1 has a 22-stage uncemented
ball-drop completion using swell packers
for isolation. Each stage used 1,500 barrels
of cross-linked fluid pumped at 20-25
bbl/minute and 95,000 pounds of proppant
(40/70- and 20/40-mesh sand with a 20/40mesh ceramic tail in). Both planar and
complex hydraulic fracture geometries
were modeled. The complex hydraulic

H1 Parent Well
One of the key early steps in evaluating
the DSU was to model the H1 parent
well's hydraulic fractures, history match
its production and estimate depletion-related 3-D stress changes. In addition to

FIGURE 1
H1 Advanced MDD and Hydraulic Fracture Modeling (Left) and
Pressure Distribution and Geomechanical Modeling (Center and Right)
H1

H12 H5 H6 H7 H8 H9

~4,700 psi

~6,000 psi

~2,500 psi

Pi ~6,000 psi

~8,000 psi

Pore Pressure
52 THE AMERICAN OIL & GAS REPORTER

Shmin

fractures resulted in the best history match,
but uncertainty remained in the degree of
fracture complexity. The description of
the natural fractures in EN DSU were estimated based on image logs and seismic
interpretations and consisted of fractures
oriented at 35 and 75 degrees. The length
and spacing of the natural fractures were
adjusted to achieve the target fracture
geometry and net pressure, with a natural
fracture length of 150 feet and spacing of
75 feet used for all fracture modeling.
Net pressures were 800-900 psi and
fluid efficiencies were 80-90 percent.
Fracture half-lengths ranged from 600 to
750 feet with maximum fracture heights
of 400-500 feet, while average fracture
heights were 150 feet and focused in the
MB interval. The H1 modeling predicted
that the fractures would extend from the
MB into the TF below, consistent with
Bakken microseismic data.
The predicted fracture geometry for
each stage in H1 was in strong agreement
with the bulk behavior of the advanced
MDD (left panel in Figure 1). The advanced MDD events were primarily in
the MB, where most of the hydraulic
fractures were focused. While the advanced
MDD suggested limited TF drainage from
the H1 completion, the fracture modeling
indicated that an initial connection to the
TF was likely.
H1 fracture geometry and proppant
distribution for each stage were represented discretely in the reservoir simulation grid to preserve the fidelity of the
fracture modeling results in the reservoir
simulation. The H1 production data was
history matched to estimate pressure
distribution before offset well completion.
As shown in the center panel in Figure
1, pore pressures of ~2,500 psi near the
H1 compare with original reservoir pressure of ~7,500 psi.
The minimum horizontal stresses
shown in the right-hand panel in Figure
1 were calculated from history match
pressure distribution input into the 3-D
geomechanical model. Stress near the
H1 has decreased to ~4,700 psi with an
original minimum horizontal stress of
~8,000 psi. The geomechanical modeling
results were used as the starting point
for the East Nesson DSU hydraulic fracture modeling.

American Oil and Gas Reporter - September 2019

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