American Oil and Gas Reporter - February 2015 - 85

SpecialReport: Improved Oil Recovery
point pressure.
The results in Figure 4 do not take
into account the effect of condensate
blockage, namely the reduction in gas
productivity index caused by condensate
building in the near-wellbore region. The
benefit of large pressure drawdown in
the producing well is that gas inflow performance overwhelms the gas recovery
loss caused by condensate drop-out. That
there is no visible distinction for the
BHPs of 500 and 1,000 psi self-evidently
suggests gas recovery loss is equivalent
to the benefit from pressure drawdown.
Nondarcy Flow
The nondarcy flow effect should be
considered for gas injection in fractured
reservoirs using the Forchheimer equation.
The nondarcy flow Forchheimer correction

FIGURE 3
Unit Fracture Controlled SRV versus Entire Well SRV
90

7,000

6,000

Gas Recovery (%)

70
5,000

4,000

Entire HW

3,000

Unit Fracture

2,000

Entire HW PAVG

Unit Fracture PAVG

Average Reservoir Pressure

Simulated Volumes
Figure 1A shows the simulated relative
volumes in a CCE (constant composition
expansion) experiment at 335 degrees
Fahrenheit for the gas condensate mixture.
Figure 1B shows the simulated liquid
drop-out curve in a CVD (constant volume
depletion) experiment at 335 degrees F
for the gas condensate mixture. In the
liquid drop-out curve, expressed as
Vro=Vo/Vs, relative oil volume is defined
as the volume of oil (Vo) at a given pressure divided by the original saturation
volume.
The relative volume provides a measurement of the average reservoir oil saturation that will develop during depletion
of a gas condensate reservoir (Whitson,
et al). The reservoir oil saturation can be
calculated from Vro with So=(1-Sw)Vro.
Liquid drop-out starts at the dew point
pressure (4,456 psi) and continues to increase until the pressure reduces to 1,500
psi, where a maximum of condensate
liquid is reached.
This study examines the impact of
grid refinement through numerical sensitivity calculations. Figures 2A and 2B
show the reservoir model using 10 x 21
grids produces results similar to far more
refined 22 x 21 grids. Figure 2A illustrates
that using nine grids to represent hydraulic
fractures gets close to the results from
using 21 grid blocks, and is enough to
eliminate the error caused by numerical
dispersion. From these results, we conclude
that a 10 x 21 grid "discretized" around
the fractures is able to properly model
the rapidly varying pressure in and near
the fractures.
In Figures 2A and 2B, the flattening
of the gas recovery "tail" is the result of
a software output issue that does not pre-

cisely reflect the simulation cases. Figure
3 shows that the production performance
from the unit-fracture-controlled SRV
produces similar results as the simulation
for the entire fractured horizontal-wellcontrolled SRV. Initially, the reservoir
operates in natural depletion for 1,800
days. We then inject CO2 for 4,000 days.
The injection well is constrained to inject
at a maximum of 800 cubic feet a day at
a maximum pressure of 7,000 psi.
Figure 4 shows the results for the different flowing bottom-hole pressures on
the gas recovery factor. The BHP used in
the base case simulation is 500 psi and
the dew-point pressure is 4,456. The
largest pressure drops occur near producing
wells and hydraulic fractures. Condensate
liquid saturation will build near a well
because of drawdown below the dew-

1,000
0

0
0

2,000

4,000

6,000

Time (Days)

FIGURE 4
BHP Impact on Gas Recovery
100
Gas Recovery (%)

of multicontact miscibility. The swelling
test was simulated by varying proportions
of injection gas mixed with original reservoir oil. The swelling test provides useful
phase and volumetric data to investigate
how a reservoir fluid reacts with gas injection.
Reservoir fluids remain in a single
gas phase preceding gas injection because
the initial reservoir pressure of 6,425 psi
is higher than saturation pressure. Saturation pressure decreases with increasing
CO2-injection percentage, which forms
the first contact miscible with the equilibrium reservoir fluid gas mixture. The
swelling factor increases with increasing
CO2 solubility.

BHP = 500

BHP = 1,000

BHP = 2,500

40
20
0
0

1,000

2,000

3,000
4,000
Time (Days)

5,000

6,000

7,000

FEBRUARY 2015 85

American Oil and Gas Reporter - February 2015

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