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Seawater injection is an efficient enhanced oil recovery (EOR) method that capitalizes on the chemical composition differences between the injecting seawater and in-situ formation water, which leads to physicochemical interactions between the rock and fluids. These rock and fluid interactions result in changes of rock wettability and subsequent improved microscopic sweep efficiency. However, the ion imbalance resulting from seawater injection and its incompatibility with the in-situ formation water may interfere with the rock and fluids equilibrium state, causing scale precipitation and subsequent deposition which can negatively impact rock quality, well productivity and reservoir performance. In this study, an accurate, robust, and general approach is presented by coupling a geochemical module with a compositional two-phase fluid flow model to handle reactive transport in porous media. The proposed coupled model, so-called ad-scale model, is capable of simulating carbonate rock dissolution and sulfate scale formation/deposition for evaluating reservoir performance under incompatible water injection. The model predictions were validated using experimental data. This model was also utilized to predict water injection rate into a carbonate formation. It was obtained that both the reacting and non-reacting component profiles were accurately predicted using the proposed coupled model. The water injection rate prediction was also validated and showed high accuracy with absolute error and coefficient of determination values of 9.02% and 0.99, respectively. In addition, a sensitivity analysis was performed on water composition, which showed a strong dependence of reservoir and well performance on water composition. This diagram elucidates what exactly happens during incompatible water injection in the mixing zones near the injection well (right half of the figure) or production well (left half of the figure) where most of the geochemical phenomena occur. [ABSTRACT FROM AUTHOR]

CO injection is considered as one of the proven EOR methods and is being widely used nowadays in many EOR projects all over the globe. The process of in situ displacement of oil with CO gas is implemented in both miscible and immiscible modes of operation. In some oil reservoirs, CO miscibility will not be attained due to fluid composition characteristics as well as in situ pressure and temperature conditions. Laboratory determination of gas-oil relative permeability curves is usually performed with air, nitrogen, or helium gases, and the results are then implemented for both natural depletion processes (especially in reservoirs with 'solution gas' or 'gas cap' drive mechanisms) and gas injection processes. For the gas injection processes, it is therefore necessary to find out how selection of the gas phase would affect the relative permeability curves when the intention of developing the curves is to use them for immiscible CO displacement. In this study, a reservoir simulator was first used to quantitatively analyze the effect of variation in relative permeability data (due to the use of different gas phases) on production performance of a reservoir. Then, computational analysis was performed on changes in relative permeability curves upon using different gas phases with the aid of pore-scale modeling using statistical methods. To predict gas-oil relative permeability curves, a Shan-Chen-type multi-component multiphase Lattice Boltzmann pore-scale model for two-phase flow in a 2D porous medium was developed. Fully periodic and 'full-way' bounce-back boundary conditions were applied in the model to get infinite domain of fluid with nonslip solid nodes. Incorporation of an external body force was performed by Guo scheme, and the influence of pore structure and capillary number on relative permeability curves was also studied for CO-oil as well as N-oil fluid pairs. The modeled relative permeability curves were then compared with experimental results for both these fluid pairs. [ABSTRACT FROM AUTHOR]

The impact of fractional wettability on the production characteristics of a VAPEX process at the macroscale was investigated. Conventional VAPEX experiments were conducted in a 220 Darcy random packing of glass beads in a rectangular physical model and n-pentane was used to recover the Cold Lake bitumen from the oil-saturated model in the absence of connate water. The composition of oil-wet beads in the packed bed was altered from completely water-wet beads to completely oil-wet beads at different proportions of oil-wet beads mixed with water-wet beads. A substantial increase (about 40%) in the production rate of live oil was observed during the VAPEX process when the wettability of the porous packing was entirely oil-wet beads. A critical oil-wet fraction of 0.66 was found for the heterogeneous packing of water-wet and oil-wet beads of similar size distribution. Above this critical composition, the live oil production rate was not affected by further increase in the proportion of the oil-wet beads. It is believed that above this critical composition of the oil-wet beads, the crevice flow process is dominated by the continuity of higher conductivity live oil films between particles through the oil-wet regions. Below this critical composition, the live oil production rate increased linearly with the fraction of the oil-wet beads in the packing. The oil-wet regions favor the live oil drainage compared to that of the water-wet regions as they enhance the rate of imbibition of the live oil from the oil-filled pores to the vacated pores near the nominal VAPEX interface. These two factors enhance the live oil production rate during the VAPEX process. The solvent content of the live oil, the solvent-to-oil ratio (SOR), and the residual oil saturation did not correlate strongly with the proportion of the oil-wet beads in the packing. The average solvent content of the live oil and the residual oil saturation were measured to be 48% by weight and 7% by volume respectively. [ABSTRACT FROM AUTHOR]