Effect of Solvent on Steam Recovery of Heavy Oil
- W.R. Shu (Mobil R and D Corp.) | K.J. Hartman (Mobil R and D Corp.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- May 1988
- Document Type
- Journal Paper
- 457 - 465
- 1988. Society of Petroleum Engineers
- 2.4.3 Sand/Solids Control, 5.7.2 Recovery Factors, 4.2 Pipelines, Flowlines and Risers, 2 Well Completion, 5.2.1 Phase Behavior and PVT Measurements, 4.1.2 Separation and Treating, 5.3.2 Multiphase Flow, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.8.5 Oil Sand, Oil Shale, Bitumen, 5.4.6 Thermal Methods, 5.5 Reservoir Simulation, 4.6 Natural Gas, 1.2.3 Rock properties, 1.6.9 Coring, Fishing, 4.1.5 Processing Equipment
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Summary. Solvents and light ends of crudes are frequently used as diluents to facilitate pumping and pipeline transportation of heavy crudes. The use of solvent alone for in-situ recovery of heavy oil tends to be limited because of its high cost; however, the use of solvent as an additive to steam processes has been tested both in the laboratory and in the field. The results of these tests are mixed. In this study, we use numerical experiments to delineate the recovery mechanism of a steam-slug process when solvents are present. A good understanding of the mechanism win help provide an interpretation of the conditions under which solvents can provide an interpretation of the conditions under which solvents can improve steam oil recovery. The study focuses on the use of small quantities of solvent-i.e., no more than 10% of the steam volume.
Steam injection is widely used for heavy-oil recovery. Using small amounts of solvent (less than 10% of steam volume) with steam has potential to increase oil recovery. While solvent is known to benefit oil recovery by reducing oil viscosity, the use of small amounts is insufficient to affect a significant volume of oil. In this simulation study, we found that a small amount of solvent can improve sweep by creating a mobility transition zone. When coinjected with steam, the vaporized solvent travels with steam and condenses in the cooler regions of the reservoir. It then mixes with oil, creating a transition zone of lower-viscosity fluid between the steam and the heavy oil. The mobility ratio of the displacing and displaced fluids is improved, thus suppressing viscous fingering and improving sweep.
The placement of the solvent in the reservoir is crucial to the process performance because it determines the location of the process performance because it determines the location of the transition zone. The solvent placement is controlled by the injection procedure and the solvent volatility. For example, when solvent procedure and the solvent volatility. For example, when solvent is injected before steam, or a heavy solvent with low volatility is coinjected with steam, incremental recovery is poor because of inadequate transition-zone generation in the reservoir.
Although definition of solvent volatility depends on reservoir pressure and temperature, light solvents generally include CO2, pressure and temperature, light solvents generally include CO2, ethane, propane, and other gases, while heavy solvents generally include hydrocarbon liquids in the C16 to C20 range. Naphtha will be considered a medium solvent. Light solvents give earlier recovery and greater recovery efficiency in terms of less solvent loss. Medium solvents give the most improvement in total oil production at somewhat higher solvent loss. Heavy solvents do not improve recovery.
Previous Work Previous Work The use of various solvents in conjunction with steam has been reported in the literature. Earlier, Farouq Ali and Snyder studied naphtha injection before steam injection in a two-dimensional (2D) vertical model filled with tar sand. Naphtha was found to be highly effective in opening a steam flow path in a homogeneous sandpack but broke through quickly in a pack with a highly permeable channel Alikhan and Farouq Ali further studied the steamdrive solvent-slug process in a line-ar cell model packed with glass beads. It was found that the light hydrocarbon slug injected before the steam slug improved oil recovery through improvement in the mobility ratio, which enhanced displacement efficiency. Recent work of Ziritt and Burgers essentially confirmed this finding. Coinjection of steam and solvent was studied by Farouq Ali and Abad in two nonscaled sandpacks. The bitumen recovery depended on the solvent type, the slug size, and the solvent placement. Smaller solvent slugs placed in the producers were found to be more effective. Other studies that involve the coinjection of gaseous solvents with steam have been reported. In general, the addition of gases to steam resulted in a slight improvement in overall oil recovery but a marked improvement in the rate of oil production. In another study, Doscher et al. concluded that solvent did not provide an economic advantage in steam-soak operations where steam/oil ratios were already economical.
More recently, Redford and McKayio presented results of a physical model experiment. A range of hydrocarbons-methane, physical model experiment. A range of hydrocarbons-methane, ethane, propane, butane, pentane, natural gasoline, naphtha, and syncrude were coinjected with steam in displacement and drawdown modes. It was demonstrated that for a given set of conditions of pressure and temperature, and the proper choice of solvent, the use of hydrocarbon additives with steam can markedly increase recovery. The use of higher-molecular-weight hydrocarbon blends led to improved recovery, provided that enough light ends were present to provide drive energy. This higher recovery, however, was offset by increased losses of hydrocarbon additives to the formation.
Redford extended the study to the coinjection of multicomponent solvents With Steam using the same nonscaled physical model. The experiments were conducted in a two-well huff 'n' puff mode. Redford found an improvement in recovery for a two-component solvent coinjected with steam over the results of the individual solvents. A synergistic effect was noticed in which a medium solvent (naphtha) improved recovery by reducing the oil-phase viscosity during the injection phase and a light solvent (CO2 or ethane) improved recovery by providing a solution-gas drive during the pressure-drawdown phase. Briggs et al. attempted to delineate the pressure-drawdown phase. Briggs et al. attempted to delineate the recovery mechanism of steam/additive processes using a one-dimensional core-size physical model. Their results essentially provided support to the findings of Redford and McKay and provided support to the findings of Redford and McKay and Redford.
It is evident that more remains to be learned about the recovery mechanism of the steam/solvent process. In this paper, a reservoir simulation study is presented for delineating the mechanism. Within its limitations, numerical simulation may offer the best means for this type of research because it allows the tracing of the distributions of solvent, oil, and steam in a reservoir model.
A compositional thermal simulator was used in this study. A brief background of the simulator input data is given below. No attempt was made to simulate a specific reservoir. Rather, we tried to establish a reasonable model in which numerical experiments could be conducted.
Reservoir Geometry. We used the same heavy-oil reservoir model as in the previous study of a steam-visbreaking process. reservoir geometry consisted of a 2D vertical model as shown in Fig. 1.
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