A west Texas crude oil containing 5% asphaltenes had a slim tube MMP measured to be 2150 psig at 120°F. When a CO2 coreflood test was performed for this oil at 2500 psig under a tertiary mode, only about half of the waterflooded residual oil was recovered, which implied the displacement process to be immiscible. A series of tertiary CO2 coreflood tests have been conducted at 120°F and 2500 psig to attempt to understand this anomaly. These displacement tests were conducted using 4 foot Berea cores and two west Texas crude oils having different asphaltene contents. The results indicate that oil recovery efficiency decreases if the C5 to C19 fraction in the oil decreases- or the asphaltene content increases.

For the oil containing more than 5% asphaltenes, using the slim tube MMP as a criterion for evaluating a tertiary miscible CO2 flood process could be misleading. An alternate displacement evaluation method is suggested. The guidelines to determine the process applicability are (1) a strong oil bank followed by a plateau on the oil recovery curve, and (2) little change in the produced oil compositions during the first two thirds of the oil production period.

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