The Effect of Oil Composition and Asphaltene Content on CO2 Displacement
- E.T.S. Huang (Unocal Corp.)
- Document ID
- Society of Petroleum Engineers
- SPE/DOE Enhanced Oil Recovery Symposium, 22-24 April, Tulsa, Oklahoma
- Publication Date
- Document Type
- Conference Paper
- 1992. Society of Petroleum Engineers
- 5.4 Enhanced Recovery, 5.2.1 Phase Behavior and PVT Measurements, 5.7.2 Recovery Factors, 1.6.9 Coring, Fishing, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 1.8 Formation Damage, 5.4.2 Gas Injection Methods, 5.4.9 Miscible Methods, 5.4.1 Waterflooding, 4.3.3 Aspaltenes, 4.1.2 Separation and Treating, 4.1.9 Tanks and storage systems
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A west Texas crude oil containing 5% asphaltenes had a slim tube MMP measured to be 2150 psig at 120 degrees 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 degrees 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.
During an evaluation, of a west Texas oil (Oil A) for application of a miscible CO2 tertiary oil recovery process, the minimum pressure for CO2 to be miscible with the oil at 120 degrees F was determined by a slim tube equipment to be 2150 psig (Fig. 1). The oil has an API gravity of 24.7 degree and an asphaltene content of about 5 weight percent. In a subsequent test, when a coreflood experiment was conducted with CO2 at 2500 psig to recover waterflooded residual oil from a 4 foot long Berea core, only about half of the residual oil was recovered. This recovery number implied that the displacement at 2500 psig and 120 degrees F was immiscible. This conclusion was based on our experience with miscible Berea coreflood tests that a tertiary oil recovery of over 70% of the residual oil is to be expected (Fig. 1). This anomaly prompted the initiation of this research investigation.
It has been a common practice in the oil Industry to use a minimum miscibility pressure (MMP) to help design a miscible gas flooding project. A slim tube, which is a 50 foot long tube with a small internal diameter packed with glass beads or crushed sands, is usually used in the MMP measurements. The tube is filled with oil and displacement of the oil with CO2 at different pressures is performed to generate an oil recovery vs. pressure plot from which the MMP is defined. The validity of MMP as a criterion to determine an optimum operating pressure for a field miscible project has been questioned. A recent study addressing this issue is in Reference 2. The MMP measurements only address the fluid phase behavior aspect of the CO2-oil mixtures. To remove oil from the reservoir with a miscible gas, another important factor is the rock-fluid interaction, and this is not accounted for in a slim tube experiment. A porous medium needs to be used in the evaluation process.
The goal of implementing a tertiary gas injection project is to recover a significant amount of tertiary oil at a reasonable accelerated rate. This implies that rock-fluid interaction should be an integral part of the evaluation. Therefore an adequate procedure to design a tertiary miscible flood process should be to define a minimum pressure at which the injection gas can mobilize the residual oil with a high efficiency. Whether the displacement occurring in the porous media is "truly" miscible or not would seem to be a secondary question.
The objectives of this investigation were to understand the factors that reduce the recovery of Oil A from a Berea core, and to suggest a better method to evaluate a CO2 flood process. It would not be practical to use different reservoir rock for the present investigation. Instead, Berea cores were chosen, and a series of coreflood experiments were conducted under same reservoir conditions (120 degrees F and 2500 psig) using two west Texas stock tank oils.
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