Extra heavy oil and bitumen reservoirs constitute huge volumes around the world and are attracting attention as alternative energy resources while the light oil reserves diminish. Thermal recovery and steam based methods are the most widely used recovery methods applicable to these highly viscous deposits. Study of steam injection in porous media containing viscous oil requires a good understanding of the physical properties of both reservoir rock and fluid. In particular, there are some bitumen properties that are needed for simulation studies and the most reliable source for these data is laboratory tests. This paper presents experimental study of some PVT properties of Athabasca crude oil to help provide input data for further numerical studies. Viscosity of Athabasca heavy crude was measured using a rotational viscometer up to 300 °C. This viscosity data is a more reliable input for simulation purposes. Athabasca oil was characterized by gas chromatography analysis to C 39+ . No significant amount of components lighter than C 9 was observed. Whole sample molar mass was measured to 534 g/mol by cryoscopy. Density at standard conditions of 1 atm and 60 °F was measured to 1.0129 g/cm 3 by a density measuring cell. Density and molar mass of the C 39+ fraction were also determined. Density measurements were performed in the temperature range 120-195 °C as well where the density was found to vary in the range 0.95-0.90 g/cm 3 . A formula was derived based on experimental density data to predict Athabasca bitumen density in the temperature and pressure range studied. The interfacial tension between oil and steam was measured in the temperature range 120-220 °C by the pendant drop method. The interfacial tension was determined to be between 25 and 18 mN/m with a decreasing trend in the temperature range studied. The results presented here can be used as reference data for studies related to Athabasca bitumen.
Nowadays, the most promising methods for recovery of heavy oil and bitumen are thermal recovery processes and among these processes, steam flooding is one of the most important methods. Naturally fractured reservoirs hold over 20 billion barrels of heavy oil which necessitates improvement in understanding of the physical processes that takes place between matrix and fracture during steam injection.
This paper addresses experimental and numerical simulation of steam injection in fractured rock. The purpose of the work was to investigate the efficiency and feasibility of steam injection in a core sample which is surrounded by fracture. Athabasca heavy crude oil was used in this study and some PVT properties of the oil was measured experimentally at different temperatures up to 200°C prior to simulation studies. Simulation studies were then conducted on a 20cm long cylindrical sandstone core with a permeability of 640mD. The core was saturated with Athabasca heavy crude oil and is radialy surrounded by a fracture.
The results show that steam injection process has great performance and efficiency in fractured systems. However, steam processes are not recommended in very high permeable fractured reservoirs due to high steam oil ratio (SOR).
Sensitivity analyses were performed on permeability of the fracture and injection rate. High fracture permeability is effective when the steam injection rate is low but it may have negative effect at earlier times for high injection rates. The effect of different injection rates on recovery performance of the system was investigated using the numerical model. Faster oil recovery and higher SOR was observed with increasing injection rates, eventhough the same ultimate recovery was obtained.
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