American Oil and Gas Reporter - June 2014 - 84

SpecialReport: Artificial Lift Technology

Production Modeling
The reservoir oil in this region of Elm Coulee has an API gravity of 42 degrees and the gas gravity is 0.95. The estimated oil
in place is 5 million barrels per square mile, with a sectorwide
model covering a four square-mile area. The simulated output of
the sector model provided an oil-in-place value of 19.96 million
barrels.
Figure 2 shows the locations of wells in the model. The six
original single-lateral horizontal production wells (A1-A6) had
produced on primary production for 39 months. Four additional wells (B1-B4) were included in the model to optimize the gas
injection strategy. Since the wells were originally drilled to penFIGURE 2
Two-Dimensional View of Reservoir Grid
With 10 Well Locations

etrate the Middle Bakken, the completion interval is in the sixth
layer of the reservoir grid (the middle of the dolomite).
Figures 3A and 3B show the results for one of the six wells
during primary production. When the original wells were on primary production, the oil rate was constrained to reproduce the
historical production data (Figure 3A). A base case primary production prediction model was then run with the wells pressureconstrained to match the typical decline curve behavior (Figure
3B).
To evaluate the behavior of the reservoir on primary recovery and compare it with the gas injection cases, the model was
run for 20 years after the 39 months of primary phase production. The total sector output for primary recovery was 1.2 million barrels. Note that the declining production trend emphasizes the need for implementing an EOR operation in this tight
oil reservoir.
The first model injected a hydrocarbon gas that was immiscible with the reservoir oil. This was achieved in the model by
turning off the miscibility of the injected gas with oil so that gas
formed a separate gas phase in the reservoir. The second model
evaluated injecting a hydrocarbon gas that was miscible with the
reservoir oil. The properties of the injection gas were set to equal
the produced gas composition.
FIGURE 3A
Well No. A5 Historical and Simulated Production Data
500.00
Rate (stb/d)

drilled in the direction of maximum stress to create longitudinal
fractures.
In the model, the hydraulic fractures were placed along the
path of the horizontal wells in the longitudinal direction, and were
represented as zones of increased permeability in the grid that could
extend tens of feet from the wellbore. Therefore, the permeability of grid blocks with a well was increased to 100 mD.
Another interpretation was to assume a representative grid block
permeability for the hydraulic fracture permeability. In this case,
fractures were represented as zones of increased permeability
around the wellbore. Fractures were assumed to be approximately one-eighth inch wide with a permeability of 1 million mD.
Therefore, a 200 foot-wide grid block would have an average permeability of 100 mD.

400.00
300.00
200.00
100.00
0.00
0

500

1,500

1,000

Time (Days)
Historical

Simulated

FIGURE 3B
Well No. A5 Predicted Production Data
450
400

Rate (stb/d)

350
300
250
200

Historical

150

Simulated 2008

100

Prediction 2028

50
0
0

2,000

4,000

6,000

Time (Days)

84 THE AMERICAN OIL & GAS REPORTER

8,000

10,000

American Oil and Gas Reporter - June 2014

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