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[HSC07-01] Numerical Simulation of Geological Sequestered CO2-Water Two-Phase Flow in Deep Aquifers and Analysis of Influencing Factors.
Keywords:CO2 geological storage, Numerical simulation, Two-phase fluid, Migration pattern, Pore pressure
For the sake of curbing the trend of global warming and climate change, capturing emitted and atmospheric CO2 and storing them geologically (CCS) have become one of the most important emission reduction methods and policies. Currently, the locations and methods of CO2 deep geological isolation storage usually have the following options: abandoned oil and gas fields and coal seams with no commercial exploitation value; CO2-EOR/EGR technology can enhance oil and gas recovery while storing CO2; isolated storage in deep saline aquifer layers onshore or offshore. Wherein, the deep saline aquifer has become one of the most popular and promising seal options due to its large isolation storage space, long closure and isolation time, wide distribution, and easy selection within the vicinity of the emission point. However, CO2 injection and fluid migration would change the initial stress field and pore pressure distribution of the formation during the project. This may lead to a series of geomechanical issues and even small earthquakes, while allowing large amounts of gas to escape if the overburden ruptures. Therefore, exploring the CO2 migration patterns in deep aquifer reservoirs through numerical simulation is one of the important technical support methods for the safe operation evaluation of CCS projects.
Aiming at the characteristics of multi-component and multi-phase seepage of CO2 in saline aquifers, a monolayer CO2-Water two-phase seepage model in ideal homogeneous and isotropic porous medium was constructed using the multi-physics simulation software COMSOL. It was assumed that the model followed the law of conservation of mass and energy and agreed with Darcy's law, the relative permeability of gas phase and wetting phase is calculated according to van Genuchten model (1980) and ignored the long-term chemical mineral precipitation reaction. The simulation process demonstrated the change in gas-liquid saturation and pore pressure distribution within the reservoir during continuous injection for 20 years. With the injection, since the gravity effect and the density difference between CO2 and water were considered, CO2 plume exhibited an obvious upward transport process while being transported horizontally and the forward displacement surface is spatially inclined. The upward floating effect caused the disunity of saturation distribution in the vertical direction in the aquifer, which became obvious with the continuous injection. It was also observed that injection initial period, the pore pressure of the reservoir at the location near the injection well raise sharply, and then decreased slowly. One possible reason for this is that the CO2 replaced water so that made the absorption ability declined. Therefore, it should be considered that the deformation or rupture of the caprock layer may occur at the early stage of the project operation.
Subsequently, the influence factors of displacement process in aquifer were studied by changing the injection rates and some initial geological parameters by the single variable method. The injection rate as an important artificially controllable condition in the project, has a great influence on the reservoir pore pressure, where both the pressure change and the plume migration rate are proportional to the injection rate. Without considering the effect of temperature on the phase state and density of supercritical CO2, the effect of initial reservoir temperature on pore pressure is not as significant as that of initial hydrostatic pressure. Porosity and permeability have a great influence on the pore pressure and CO2 transport. When CO2 flows in a dense reservoir with low porosity and permeability, it generates a large pore pressure due to large medium resistance. As a result, it is significant to evaluate the lithology features and physical properties of the reservoir and caprock formation before starting the CCS project.
Aiming at the characteristics of multi-component and multi-phase seepage of CO2 in saline aquifers, a monolayer CO2-Water two-phase seepage model in ideal homogeneous and isotropic porous medium was constructed using the multi-physics simulation software COMSOL. It was assumed that the model followed the law of conservation of mass and energy and agreed with Darcy's law, the relative permeability of gas phase and wetting phase is calculated according to van Genuchten model (1980) and ignored the long-term chemical mineral precipitation reaction. The simulation process demonstrated the change in gas-liquid saturation and pore pressure distribution within the reservoir during continuous injection for 20 years. With the injection, since the gravity effect and the density difference between CO2 and water were considered, CO2 plume exhibited an obvious upward transport process while being transported horizontally and the forward displacement surface is spatially inclined. The upward floating effect caused the disunity of saturation distribution in the vertical direction in the aquifer, which became obvious with the continuous injection. It was also observed that injection initial period, the pore pressure of the reservoir at the location near the injection well raise sharply, and then decreased slowly. One possible reason for this is that the CO2 replaced water so that made the absorption ability declined. Therefore, it should be considered that the deformation or rupture of the caprock layer may occur at the early stage of the project operation.
Subsequently, the influence factors of displacement process in aquifer were studied by changing the injection rates and some initial geological parameters by the single variable method. The injection rate as an important artificially controllable condition in the project, has a great influence on the reservoir pore pressure, where both the pressure change and the plume migration rate are proportional to the injection rate. Without considering the effect of temperature on the phase state and density of supercritical CO2, the effect of initial reservoir temperature on pore pressure is not as significant as that of initial hydrostatic pressure. Porosity and permeability have a great influence on the pore pressure and CO2 transport. When CO2 flows in a dense reservoir with low porosity and permeability, it generates a large pore pressure due to large medium resistance. As a result, it is significant to evaluate the lithology features and physical properties of the reservoir and caprock formation before starting the CCS project.