Compositional Simulation of WAG Processes for a Viscous Oil
- Dacun Li (University of Houston) | Kamlesh Kumar (University of Houston) | Kishore K. Mohanty (University of Houston)
- Document ID
- Society of Petroleum Engineers
- SPE Annual Technical Conference and Exhibition, 5-8 October, Denver, Colorado
- Publication Date
- Document Type
- Conference Paper
- 2003. Society of Petroleum Engineers
- 5.4.2 Gas Injection Methods, 2.4.3 Sand/Solids Control, 5.4.6 Thermal Methods, 5.2.2 Fluid Modeling, Equations of State, 5.3.1 Flow in Porous Media, 4.2 Pipelines, Flowlines and Risers, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.4 Enhanced Recovery, 4.3.4 Scale, 5.3.2 Multiphase Flow, 4.6 Natural Gas, 1.2.3 Rock properties, 5.2.1 Phase Behavior and PVT Measurements
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The goal of this work is to develop a compositional model for WAG injection in a medium-viscosity oil, low-temperature reservoir like Schrader Bluff Pool in the Milne Point Unit, Alaska. Compositional simulation of WAG displacement with CO2-NGL and Prudhoe Bay gas-NGL mixtures shows that three-hydrocarbon phases form in situ because of low temperature. A four-phase relative permeability formulation has been developed by considering the mixed-wettability of the formation and the saturation paths. The simulation results are compared with the laboratory experimental results from the literature. The sensitivity of the laboratory-scale oil recovery to relative permeability, pressure and solvent composition is studied. The sensitivity of oil recovery in a 2D quarter five-spot pattern to relative permeability, WAG ratio, slug size is also studied. CO2 - NGL mixture is a very effective solvent for this reservoir. The minimum miscibility enrichment is more sensitive to pressure for Prudhoe Bay gas - NGL mixtures than in the case of CO2 - NGL mixtures. The oil production rate is sensitive to relative permeability formulation. Oil recovery is faster at lower WAG ratio and higher slug size.
There is a large (> 10 billion barrels) deposit of viscous oil at Schrader Bluff Pool in the Milne Point Unit, Alaska1. Due to high oil viscosity and poorly consolidated sand, primary production is low. However, the viscosity of oil is not high enough for application of steam flood. Fortunately, there are plenty of gases (hydrocarbon and CO2) in North Slope in the absence of any gas pipeline. Gas floods have been considered in the past. Experimental study carried out by Khataniar et al.2 showed that combination of 85% CO2-15% natural gas liquids (NGL) or 60% Prudhoe Bay gas (PBG)-40% NGL developed miscibility with the oil. Mohanty et al.3 have conducted slim tube experiments and simulation studies on the injection of solvents of C1-C4 with varied compositions into the crude. They found that three-hydrocarbon phases coexisted in the reservoir (totaling four phases if we include water) and that high oil recovery was possible in the presence of three-hydrocarbon-phases because of lower oil viscosity and miscible displacement of oil by the second liquid phase after some amount of solvent condensed into the crude.
Modeling flow of four fluid phases (water, oil, gas, and the second non-aqueous liquid) is important to the water-alternating-gas (WAG) floods. However, four-phase systems cover a large number of saturation paths. The relation between phase saturation and pressure is also delicate. It is prohibitively expensive if not impossible to experimentally measure relative permeabilities for a four-phase system.
Experimental data are not collected regularly for three-phase systems for a similar reason. Pore-scale mechanistic models4-7 have been developed for three-phase flow, but lack of pore-scale structure and wettability data makes them impractical. Instead, empirical models are often used which estimate three-phase relative permeabilities from experimental two-phase relative permeabilities: water-oil and oil-gas. Two empirical models proposed by Stone8,9 are widely used in the oil industry even though comparisons with experiments10-12 have shown many inconsistencies. Baker10 has proposed a simple three-phase model based on saturation-weighted interpolation of two-phase relative permeabilities. These models are primarily for water-wet media and do not take trapping of non-wetting phases into account. Jerauld13 has developed a three-phase relative permeability model for Prudhoe Bay reservoir, which accounts for mixed-wettability, trapping, capillary number effects, and compositional consistency. Blunt14 has used the saturation-weighting technique10,15 and proposed a new model that accounts for trapping and oil layer flow at low saturations.
Guler et al.16 are the first to suggest a four-phase relative permeabilities based on the Baker model10 for three-phase flow. This model lumps oil and second phase saturations into one pseudo phase, which reduces the four-phase system to a three-phase system. It applies the Baker model to get the lumped relative permeability of the pseudo phase and then distributes it to the oil and the second liquid phase in proportion to their flowing saturations. This model presumes the medium to be water-wet and it does not account for gas phase hysteresis.
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