| Emissions of carbon dioxide (CO2) sourced from anthropogenic activities are regarded as an important reason for causing global warning which has already threatened the survival of human beings and influenced the sustainability of the society development. CO2 sequestration in deep saline aquifers is widely recognized to be one of the most promising technologies to reduce the atmospheric CO2 emissions. It is subject to the influences of several factors, such as pore configuration, fluid properties and petro-physical parameters and, hence, is a complex hydro-geological process. Core-scale researches on CO2/brine multiphase flow in porous media can be helpful to improve our understanding of local trapping mechanisms, thus providing theoretical basis for reliable assessment of storage capacity and safety of CO2 saline aquifer sequestration projects.Based on experimental measurements of CO2-brine displacement processes in a sandstone core, this paper numerically simulates migration and trapping of CO2 plume in heterogeneous porous media. First, in terms of the measurement data of porosity and permeability, a fractal model is constructed to quantitatively describe the permeability heterogeneity. Then, the heterogeneity in the capillary pressure is also quantified by combining the J function with the fractal model. By introducing these heterogeneities into a CO2-brine two-phase flow model, we numerically analyze the local trapping behavior of CO2 plume in the heterogeneous natural core. Numerical simulation results indicate:1) The capillary heterogeneity can cause the CO2 local accumulation and anomalous spatial distribution of CO2 saturation; 2) Comparably, permeability heterogeneity can’t obviously influence the local accumulation and can only somewhat lower the CO2 displacement efficiency by changing the local flow path of CO2 plume; 3) CT images show the obvious heterogeneous structure at a few local locations, which influences the local petro-physical properties. The significant changes in CO2 saturation at these locations, especially the dramatic increase of CO2 saturation near the compact region of the core, are mainly caused by the variation of relative permeability.In addition, the effectiveness of the CO2 local capillary trapping is also evaluated under different reservoir conditions including different temperatures, pressures and brine salinities. Our results indicate that:1) The chemical reactions between CO2 and brine is an important influencing factor for the trapping effectiveness. The precipitation of solid salt caused by equilibrium phase partitioning between water and CO2 can block pore space of the regions with high capillary entry pressure, consequently decreasing their permeability and increasing their capillary pressure, which generally enhances the effectiveness of the local capillary trapping; 2) With the increase of fluid salinity, the CO2 storage capacity is significantly increased when the salinity increase to 0.1 (i.e.10000 ppm). In this case, the CO2 storage capacity is 1.84 times as much as that for the pure-water case. However, above this value, the CO2 storage capacity will not be significantly increased with the increased salinity; 3) Under the real reservoir conditions, the temperature and pressure can have a significant influence on the local capillary trapping. At high pressure or low temperature (typically≥12.67MPa or <35℃), the role of the equilibrium phase partitioning becomes weak, which leads to the reduction of salt precipitates. |
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