American Oil and Gas Reporter - June 2014 - 82

SpecialReport: Artificial Lift Technology
A flow simulation model was used to examine the difference
in total recovery, production rate and efficiency. Recovery efficiency was similar for both miscible hydrocarbon gases and carbon dioxide, with recoveries increasing from 6 percent on primary production to around 20 percent with gas injection. While
the increased recovery was encouraging, both methods have some
practical limitations. For instance, the availability of CO2 is limited in many unconventional basins, and while hydrocarbon gases are a byproduct of production in most tight oil fields, their marketable value can preclude using them as injectants for EOR (assuming gas infrastructure is available).
The study demonstrates that injecting gas (both immiscible
and especially miscible) will increase oil recovery appreciably
in very low-permeability reservoirs. Given the size of the resource
base in the Bakken, Eagle Ford, Niobrara and other liquids-rich
plays, a large prize is available to those who find ways to increase
recovery from tight reservoirs.
In the case of injecting produced gas to enhance oil recovery,
the economics certainly can be favorable, even with the recovery in natural gas prices, particularly in the case of associated produced gas with limited local processing or take-away capacity (as
is often the case in the Bakken). To assess the economics, a
cost/benefit analysis was performed to compare selling the gas
with injecting it to increase oil production. Assuming a $10 million investment in compression and facilities for the four-section
Bakken study area, the net present value was $68 million with
a return rate of 83 percent at an average gas cost of $5 an Mcf
and a conservative oil sales price of $80 a barrel.
At present, the United States is producing more than 300,000
barrels a day from gas injection projects. Gas injection tends to
work well in higher-pressure (deeper) reservoirs and those with
higher API gravity oils. Unconventional shale oil reservoirs tend
to have both of these characteristics, in addition to ultralow permeabilities. While gas injection appears favorable for EOR in unconventional oil reservoirs, the ability to inject produced hydro-

FIGURE 1
Map of Elm Coulee Field
With Modeling Sector Highlighted
22N-57E

82 THE AMERICAN OIL & GAS REPORTER

22N-58E

carbon gases as an effective alternative to CO2 will be key to longterm recovery efforts given carbon dioxide's limited availability in plays such as the Bakken Shale.
Reservoir Modeling
The Elm Coulee Field study evaluated the performance of the
three solvents for gas flooding using a numerical reservoir simulator. A section of the field was selected for reservoir modeling
in previous work using a commercial finite difference simulator
to evaluate well placement and injection scenarios (Figure 1). The
structure and dimensions of that model, along with rock and fluid properties, and the optimum well development and injection
strategy, were used for this study.
The modeled sector is two miles long by two miles wide and
located in parts of townships 22N-57E and 22N-58E. It consists
of 10, single-lateral horizontal wells (six of which were historical wells and four of which were added in the previous study for
the optimal gas injection scenario). The reservoir section was divided into 53 grid blocks in the x direction, 53 grid blocks in the
y direction, and eight grid blocks in the z direction. The grid blocks
were 200 feet in length in the x and y directions, and three feet
thick in the z direction, resulting in a 24-foot pay zone.
At this location, it was assumed that the overlying shale layer contributes to oil production, and the pay zone consists of the
upper shale and dolomite regions of the Bakken formation. The
top three layers in the reservoir grid represent the upper shale zone,
and the bottom five layers are the dolomite. The shale occurs at
a subsea level depth of 7,500 feet.
Both the upper shale and middle dolomite members of the formation were modeled with a homogenous porosity of 7.5 percent.
The shale layers contain natural fractures that formed during the
kerogen conversion process, followed by oil generation and expulsion. Log analysis shows that these natural fractures provide
6-8 percent porosity in the shale. The dolomite porosity is in a
similar range.
The results of pressure buildup tests indicated a permeability value of 2.5 mD in the upper shale region. However, the capacity to transmit fluids of the natural fractures present in these
layers depends on pressure. As reservoir pressure drops with production, permeability decreases in the shale layer. The phenomenon of pressure-dependent permeability is incorporated into the
model's upper shale using permeability multipliers. The dolomite
region is 15 feet thick with a permeability value of 0.015 mD.
The permeability in this region is not affected significantly by pressure changes. A vertical-to-horizontal permeability ratio of
0.01 was used for both members of the reservoir.
Because of the very low permeability values, the hydraulic fractures created have very large permeability values. At the time the
wells were drilled, there was still debate about the most effective types of fractures, namely longitudinal (along the wellbore)
versus transverse (perpendicular to the wellbore). These wells were

American Oil and Gas Reporter - June 2014

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