The Roles of Fluid Properties, Half‐Cycle Slug Size, and Timing of Cyclic Injection on Water Alternating Gas Injection Performance in Near‐Miscible and Miscible CO2 Flooding Hertanto Adidharma Department of Chemical and Petroleum Engineering University of Wyoming Laramie WY 82071 Hertanto Adidharma, Department of Chemical and Petroleum Engineering, University of Wyoming, Laramie, WY 82071 The overall goal is to experimentally study the effects of fluid properties (brine salinity and gas composition), CO2 and water half‐cycle slug size (HCSS), and timing of cyclic injection on the performance of Water Alternating Gas (WAG) injection in near‐ miscible and miscible conditions. The effects of CO2 and water HCSS and miscibilityy conditions on WAG p performance in tertiaryy CO2 floodingg have been investigated. A crude oil from Cottonwood Creek field in Wyoming is used. The core flooding experiments in Berea sandstone core are conducted at 60oC. Alternate cycles of CO2 and brine with a WAG ratio of 1:1 are injected with HCSS ranging from 0.05 to 0.75 pore volumes (PV). In the study of the effect of HCSS, the experiments are performed at miscible condition. It is found that there is an optimum HCSS, by which the CO2 utilization factor reaches a minimum value. It means that WAG with an optimum HCSS requires the least amount of CO2 to produce one barrel of oil. At this optimum HCSS, the tertiary oil recovery also l reaches h a maximum value. l In the h study d off the h effect ff off miscibility b l conditions, d two more miscibility b l conditions d are investigated. The HCSS study is repeated for near miscible condition and immiscible conditions. Immiscible flooding does not perform as well as near miscible and miscible flooding, but near miscible and miscible flooding perform comparably in water wet system, which demonstrates that requiring miscible condition could be overdesign. A consistent optimum HCSS is also observed. Tertiary Oil Recovery Under Different Miscibility Conditions
CO2 Utilization Factor (miscible condition)
42
8
Miscible
40
Te ertiary Oil Recovery [% % OOIP]
CO2 Utilization Fac ctor
38
7
6
36
Near Miscible
34 32 30
Immiscible
28 26 24 22 20 18
0.0
0.1
0.2
0.3
0.4
HCSS [PV]
0.5
0.6
0.7
0.8
0.0
0.1
0.2
0.3
0.4
HCSS [PV]
0.5
0.6
0.7
0.8
