Optimal Application Conditions of Solvent Injection Into Oil Sands To Minimize the Effect of Asphaltene Deposition: An Experimental Investigation
- Laura Moreno-Arciniegas (University of Alberta) | Tayfun Babadagli (University of Alberta)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- November 2014
- Document Type
- Journal Paper
- 530 - 546
- 2014.Society of Petroleum Engineers
- 5.4.10 Microbial Methods, 1.8 Formation Damage, 4.1.9 Heavy Oil Upgrading, 5.2.1 Phase Behavior and PVT Measurements, 5.3.4 Reduction of Residual Oil Saturation, 5.7.2 Recovery Factors, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 4.3.3 Aspaltenes, 2.4.3 Sand/Solids Control, 5.8.5 Oil Sand, Oil Shale, Bitumen
- temperature-pressure conditions, heavy-oil recovery, asphaltene precipitation, pore plugging, n-alkane as solvent
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- 434 since 2007
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Solvent injection into heavy-oil reservoirs is quite complex because of the asphaltene destabilization that occurs because of the changes in temperature, pressure, and solvent type dissolved in oil. As a result of this destabilization, the asphaltene flocculates, agglomerates, and eventually plugs the pores in the reservoir because of the formation of asphaltene clusters. In solvent applications, light-molecular- weight hydrocarbon solvents are preferred because of their high diffusion coefficient; however, as the carbon number of nalkane solvents decreases, asphaltene precipitation increases. Therefore, the selection of the solvent and application condition is highly critical in cold and thermally aided solvent applications. In this research, low-carbon-number n-alkane (propane, n-hexane, and n-decane) and a distillate-hydrocarbon (obtained from a heavy-oil-upgrading facility) injection into glass-bead-pack systems saturated with heavy oil (87,651 and 20,918 cp at 25°C) were evaluated at different pressure conditions that are applicable to typical Canadian oil-sand reservoirs (698–2068 kPa) and temperatures (25–120°C). First, the asphaltene behavior of different solvents at different pressures and temperatures was studied through deasphalting work in a pressure/volume/temperature (PVT) cell in previous work [Moreno and Babadagli (2013)]. By use of quantitative (amount of asphaltene precipitated) and qualitative (microscopic images of asphaltene clusters) observations, asphaltenes were classified in terms of their shape, size, and quantity for different oil/solvent types, pressure, and temperature. Continually, the same n-alkane, distillate-hydrocarbon solvents, and heavy oil were used in gravity-stable-displacement glass-beadpack experiments. 3-D (cylindrical) glass-bead-pack experiments were carried out at the same temperature and pressure conditions used for the PVT experiments. The operational conditions, oil composition, and solvent type showed significant effects on oil-recovery factor. Asphaltene deposition and residual oil saturation (ROS) in the glass-bead pack and the amount of asphaltene in the produced oil were measured, and the standard saturate, aromatic, resin, and asphaltene (SARA) analysis was applied to determine the optimal operating conditions yielding the highest recoveries with minimal pore plugging. Moreover, the pore-plugging process was analyzed through a visual scanning electron microscope (SEM) and optical microscope to find the different organic deposition formation and agglomeration. Oil production was evaluated by use of microscope visualization, viscosity reduction, and refractive-index values. Eventually, optimal application conditions for solvent and thermally aided solvent injection were listed for a wide range of heavy-oil and solvent types.
|File Size||3 MB||Number of Pages||17|
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