The reservoir heterogeneity is the major cause of poor volumetric sweep efficiency in sandstone and carbonate reservoirs. Displacing fluids (water, chemical solution, gas, and supercritical CO 2 (sc-CO 2 )) flow toward the high permeable zone. A significant fraction of oil remains in the low permeable zone due to the permeability contrast. This study used in situ sc-CO 2 emulsion as a conformance control agent to plug the high permeable zone and improve the low permeable zone's volumetric sweep efficiency in carbonate formation. We investigated the effect of two types of conformance control patterns and the size of sc-CO 2 emulsion on tertiary oil recovery performance by sc-CO 2 miscible injection for carbonate reservoirs at reservoir conditions. The conformance control patterns are achieved using two different approaches. In the first approach, the low permeable zone was isolated, and the diverting gel system, a 0.4 pore volume slug, was injected into a high permeable zone. In the second approach, the simultaneous injection of the diverting gel system, a 0.2 pore volume slug, was done on both the low and high permeable zones. The first sc-CO 2 injection was conducted as a tertiary oil recovery mode to recover the remaining oil after water flooding. The diverting gel system was injected after the first sc-CO 2 flood for the conformance control. The second or post sc-CO 2 injection was conducted after the diverting gel system injection. The diverting gel system used in this study consisted of a polymer and a surfactant. An in situ emulsion was generated when the injected diverting gel system interacts with the sc-CO 2 in the core plug. Results obtained from dual-core core flooding experiments suggested that the in situ sc-CO 2 emulsion was generated successfully in the formation based on the different pressure increases and observation of the dual-core core flooding experiments. The volumetric sweep efficiency and oil recovery in both conformance control patterns were improved. The production performances were also compared for both conformance control models before and after the diverting gel system injection. The conformance control model 2 (simultaneous injection of the diverting gel system into low and high permeability cores) has a better choice to be applied in field application due to high recovery with a small sc-CO2 emulsion easy operation in the field.
Relative permeability characteristic and wetting behavior of reservoir rocks are crucial for oil recovery. Supercritical CO 2 (sc-CO 2 ) miscible flooding as an enhanced oil recovery (EOR) method has been successfully used in both sandstone and carbonate reservoirs. The sc-CO 2 is miscible with the remaining oil left after water flooding at injection pressures above MMP, and then higher recovery can be achieved. To describe the flow characteristics and performance of sc-CO 2 displacing remaining oil and water, characteristic parameters such as the water (K rw ) and miscible phase (K rm ) relative permeability curves and wetting behavior are required, which applies to reservoir numerical simulation for predicting production performance of sc-CO 2 miscible injection. Surprisingly, publications of experimental data including water and miscible phases are relatively rare due to the lack of proper experimental methods in laboratory. In this paper, we proposed a modified method based on the Corey model to calculate water and miscible phase relative permeability using endpoint values of oil/water system and water/miscible phase (sc-CO 2 dissolving into oil) system. In addition, relative permeability reduction and the change of wetting behavior of core plug after sc-CO 2 miscible injection were evaluated. Four core flooding experiments were carried out on carbonate composite cores using live oil at reservoir conditions. The experiments included seawater injection and sc-CO 2 injection for each core plug to obtain the endpoint values from both injections. The Corey model was used directly to calculate oil/water relative permeability of the carbonate composite cores. A modified Corey model proposed in this paper was used to calculate water and miscible phase relative permeability and obtain the relationship of relative permeability vs miscible phase saturation. The co-flow characteristics in water and miscible phase system were described using these endpoints and relative permeability curves. As a result, relative permeability to water and miscible phases can be calculated using the modified Corey model based on endpoint values during co-flow of water and miscible phases in core plug. The evaluation of relative permeability reduction of core plugs was made by comparing endpoint relative permeability of sc-CO 2 at residual state of water/ phase phase system with that of water at residual oil saturation of oil/water system. The values of endpoint relative permeability to sc-CO 2 are extremely low, which are in the range of 1.57−5% after sc-CO 2 injection. The wetting behavior had slightly changed by observing photographs of water droplets and oil droplets on the surface of core plugs before and after sc-CO 2 injection. The relationship between relative permeability to water and miscible phases vs miscible saturation has been developed when the water saturation is decreasing during sc-CO 2 miscible injection process. There is an obvious influence of water and miscible phase relative permeability when the Corey exponents, N w ...
Field application of supercritical CO2 (sc- CO2) miscible flooding continues to grow. Optimization of sc- CO2 injection during miscible flooding modes represents one of the dominant factors affecting its performance in carbonate oil reservoirs. The main objective of this study was to investigate the impact of different modes of sc- CO2 miscible injection on oil recovery and injectivity in carbonate rocks. Several modes of sc- CO2 injection modes were investigated including continuous CO2 miscible flooding, water-alternating-gas (WAG), and tapered WAG injection. Five coreflooding experiments were conducted to evaluate oil recovery for different modes of CO2 injection under reservoir conditions. Composite cores of 25 cm length from a specific, producing carbonate reservoir were used in the study. Both horizontal and vertical coreflooding experiments of continuous CO2 injection mode were carried out to compare oil recovery and injectivity during CO2 flooding. Horizontal core flooding experiments under WAG mode was performed at pore pressures of 3,200 psi and 3,800 psi. The experimental results indicate that tertiary oil recovery was influenced significantly by different CO2 injection modes and the direction of displacement. 18.4% and 26.74% of original oil in cores were recovered for horizontal and vertical experiments of continuous CO2 injection modes, respectively. In horizontal WAG experiments with different pore pressures, higher oil recovery was observed at a pore pressure of 3,800 psi compared to 3,200 psi. The marginal increase in incremental oil recovery indicates that pressure increase beyond 3,200 psi will not have a significant impact. The injectivity of different CO2 injection modes is reported in this paper.
Summary Field application of supercritical carbon dioxide (sc-CO2) miscible flooding continues to grow. Optimization of sc-CO2 injection during miscible-flooding modes represents one of the dominant factors affecting its performance in carbonate oil reservoirs. The main objective of this study was to investigate the effect of different modes of sc-CO2 miscible injection on oil recovery and injectivity in carbonate rocks. Several modes of sc-CO2 injection were investigated, including continuous CO2 miscible flooding, water-alternating-gas (WAG), and tapered-WAG injection. Five coreflooding experiments were conducted to evaluate oil recovery for different modes of sc-CO2 injection under reservoir conditions. Composite cores of 25-cm length from a specific, producing carbonate reservoir were used in the study. Both horizontal- and vertical-coreflooding experiments of continuous-sc-CO2-injection mode were performed to compare oil recovery and injectivity during sc-CO2 flooding. Horizontal-coreflooding experiments under WAG mode were performed at pore pressures of 3,200 and 3,800 psi. The experimental results indicate that tertiary oil recovery was influenced significantly by different sc-CO2-injection modes and the direction of displacement. Original oil in cores was recovered at 18.4 and 26.74% for horizontal and vertical experiments of continuous-sc-CO2-injection modes, respectively. In horizontal-WAG experiments with different pore pressures, higher oil recovery was observed at a pore pressure of 3,800 psi compared with 3,200 psi. The marginal increase in incremental oil recovery indicates that pressure increase beyond 3,200 psi will not have a significant effect. The injectivity of different sc-CO2-injection modes is reported in this paper.
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