American Oil and Gas Reporter - February 2015 - 86

SpecialReport: Improved Oil Recovery
factor was used in the hydraulic factures
in this model to correct a 0.001-foot wide
fracture to represent the nondarcy flow in
the two-foot pseudo-fracture. The hydraulic
fracture conductivity was assumed to be
83.3 millidarcy-feet. The effective fracture
permeability for the two-foot width of
fracture is 41.65 md to conserve the fracture

conductivity. The value used in the fractures
equates to 903.8=(83,300/41.65)^(21.1045).
Figure 5 compares the gas and condensate recovery results of the darcy flow
model with the nondarcy flow model.
The nondarcy, flow-corrected model in
two-foot wide fracture conduits exhibits

FIGURE 5
Recovery Factor
(Darcy Flow versus Nondarcy Flow)
90

Gas Recovery, Darcy Flow
Gas Recovery, Nondarcy Flow

50
70
Gas Recovery (%)

Liquid Condensate Recovery (%)

Liquid Condensate, Darcy Flow
Liquid Condensate, Nondarcy Flow

60
50
40
30
20

10
10
0

1,000

2,000 3,000 4,000
Time (Days)

5,000

6,000

1,000

2,000 3,000 4,000
Time (Days)

5,000

6,000

FIGURE 6
Impact of Fracture Spacing on Gas and C9 Recovery
60

50
HF Spacing = 150 ft
HF Spacing = 200 ft
HF Spacing = 300 ft

HF Spacing = 150 ft
HF Spacing = 200 ft
HF Spacing = 300 ft

45
40
C9 Recovery (%)

Gas Recovery (%)

50
40

30
20

TAO WAN is a Ph.D. candidate at
Texas Tech University. He holds a B.S.
in petroleum engineering from the China
University of Petroleum and an M.S. in
petroleum engineering from Texas Tech.

35
30
25
20
15
10

5
0

0
0

1,000

2,000 3,000 4,000
Time (Days)

5,000

6,000

1,000

2,000 3,000 4,000
Time (Days)

5,000

6,000

FIGURE 7
Condensate Saturation and Gas Relative Permeability
1.0

0.30

Gas Relative Perm at 1 10 2

0.9

0.25
0.20

Gas Relative Perm

Condensate Saturation

a little bit lower recovery than the darcy
flow model. The nondarcy correction can
be used to accurately model a pseudo
fracture 1,000 times wider than the actual
size for horizontal wells in fractured shale
gas reservoirs.
Figure 6 shows the impact of fracture
spacing on the cumulative gas recovery
factor. As can be seen, reducing fracture
spacing from 200 to 100 feet would result
in a more than twofold increase in cumulative gas recovery factor. The well's production performance is the sum of all
fracture network segments, which depends
strongly on fracture spacing. Increasing
stimulation stages can be used to increase
fracture network size and SRV. Production
in shale reservoirs is related directly to
stimulated reservoir volume, which is in
context with the fracture spacing.
The test indicates global mole fraction
of CO2 and C1 (methane) changes at
time zero, after 1,800 days of primary
depletion, and after 4,000 days of CO2
flooding. The reservoir's initial gas viscosity at 335 degrees F, calculated by
Jossi-Stiel-Thodos correlation, is 0.0373
centipoise. The CO2 viscosity at 335 degrees F and 6,425 psi is 0.052 cp.
When injected CO2 contacts reservoir
fluids, the CO2 effectively pushes the C1

BHP = 500, 1 10 2

0.15

BHP = 500, 2 11 2

0.10
0.05

0.8

Gas Relative Perm at 2 11 2

0.7
0.6
0.5
0.4
0.3

0
0

2,000
4,000
Time (Days

6,000

86 THE AMERICAN OIL & GAS REPORTER

2,000
4,000
Time (Days

6,000

XINGBANG MENG is a Ph.D. candidate at Texas Tech University. He
holds a B.S. in petroleum engineering
from the China University of Petroleum
and an M.S. in petroleum engineering
from Texas Tech.
JAMES J. SHENG is an associate
professor in the Bob L. Herd Department of Petroleum Engineering at
Texas Tech University. He worked for
more than 20 years in the oil industry
before entering academia, holds four
U.S. patents, and is the author of two
books on enhanced oil recovery. Sheng
has received the Society of Petroleum
Engineers' 2013 Regional Technical
Award for formation evaluation, as
well as SPE's Outstanding Technical
Editor and Outstanding Associate Editor awards. He holds a Ph.D. from
the University of Alberta.

American Oil and Gas Reporter - February 2015

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