Page 125 - Fundamentals of Enhanced Oil and Gas Recovery

Miscible Gas Injection Processes 113

temperatures are above the critical temperature. The proximity to its critical tempera-
ture gives CO 2 more liquid-like properties than the lighter solvents [4,42].
Two charts of compressibility factor for air and carbon dioxide is reported in the
work of Lake [4]. So, the fluid density ρ can be calculated as follows:
g
PMW
ρ 5 (4.21)
g
zRT
where pressure, molecular weight, compressibility factor, temperature, and global gas
constants are shown with P,MW, z, T, and R. The gas formation volume factor (B g )
at any temperature and pressure is given as follows:

P s T
B g 5 z (4.22)
P T s
where T s and P s are the standard temperature and pressure, respectively. All fluids
become more liquid-like, at a fixed temperature and pressure, as the MW increases.
The anomalous behavior of CO 2 is again manifested by comparing its density and for-
mation volume factor to that of air.

4.3.4 CO 2 Field Case Study

Some field case studies are considered here which have lessons in gas injection EOR.
As discussed before, the recovery in oilfield depends on both volumetric and displace-
ment sweep efficiencies. Summary of gas floods performed can be found in the works
of Manrique et al. [43] and Christensen et al. [44]. The followings are some examples
of miscible gas injections.

4.3.4.1 Slaughter Estate Unit CO 2 Flood
The miscible flood in the West Texas San Andres dolomite is an example of a gas
flood with very good oil recovery. The average permeability is low around 4 mD at a
depth of about 5000 ft. A waterflood in the early 1970s prior to gas flooding led to a
good recovery. A volume of 72 mol% CO 2 and 28 mol% H 2 S were mixed for injec-
tion. The MMP of approximately 1000 psia with this gas and moderate API oil
(32 API) is substantially less than the average reservoir pressure of 2000 psia.

Therefore, this flood is multicontact miscible (MCM).
Water was injected alternately with the acid gas with a water-alternating-gas
(WAG) injection ratio of about 1.0. A 25% hydrocarbon pore volume (HCPV) slug
of acid gas was injected. The chase gas was also alternated with water, and eventually,
the gas water ratio was reduced to 0.7 to improve vertical sweep. The cycles are
shown in figure.
Incremental tertiary recovery was 19.6% OOIP, which is largely the result of good
WAG management and the use of H 2 S in the gas [45].H 2 S, although very dangerous,