Abstract
Injection of anthropogenic carbon dioxide (CO2) into geological formations is a promising approach to reduce greenhouse gas emissions into the atmosphere. Predicting the amount of CO2 that can be captured and its long-term storage stability in subsurface requires a fundamental understanding of multiphase displacement phenomena at the pore scale. In this paper, the lattice Boltzmann method is employed to simulate the immiscible displacement of a wetting fluid by a non-wetting one in two microfluidic flow cells, one with a homogeneous pore network and the other with a randomly heterogeneous pore network. We have identified three different displacement patterns, namely, stable displacement, capillary fingering, and viscous fingering, all of which are strongly dependent upon the capillary number (Ca), viscosity ratio (M), and the media heterogeneity. The non-wetting fluid saturation (Snw) is found to increase nearly linearly with logCa for each constant M. Increasing M (viscosity ratio of non-wetting fluid to wetting fluid) or decreasing the media heterogeneity can enhance the stability of the displacement process, resulting in an increase in Snw. In either pore networks, the specific interfacial length is linearly proportional to Snw during drainage with equal proportionality constant for all cases excluding those revealing considerable viscous fingering. Our numerical results confirm the previous experimental finding that the steady state specific interfacial length exhibits a linear dependence on Snw for either favorable (M ≥ 1) or unfavorable (M < 1) displacement, and the slope is slightly higher for the unfavorable displacement.
Highlights
Carbon capture and storage (CCS) is a method of reducing anthropogenic emission of greenhouse gases into the atmosphere thereby mitigating global climate change
To gain a better understanding of pore-scale two-phase displacement mechanisms, a series of numerical simulations are conducted to study the effect of capillary number (Ca) and M on displacement stability and fluid saturation in a homogeneous and a heterogeneous pore networks, and the obtained results are compared to indicate the effect of media heterogeneity
As observed in the homogeneous pore network, saturation of the non-wetting fluid (Snw) exhibits an approximately linear dependence on log Ca in the heterogeneous pore network for each M and Snw is higher for a larger value of M at a fixed Ca
Summary
Reservoir in terms of storage capacity, security, and ultimate fate of the injected CO2. It is challenging to independently manipulate porosity, pore size, connectivity, and wetting properties for natural porous media These limitations can be overcome by micromodels, which are two-dimensional (2D) pore network patterns etched into materials such as silicon, glass, polyester resin, and most recently, polydimethylsiloxane (PDMS).[5] Micromodels allow for visualization of fluid distribution using cameras with or without fluorescent microscopy, and subsequent quantification of fluid saturation and interfacial area may provide mechanistic insight about physical displacement process at the microscopic level. Lenormand et al.[6] performed a series of classic displacement experiments for several fluid pairs in an oil-wet micromodel constructed of a polymer resin, and established a phase diagram delineating parameter domains for stable displacement, capillary, and viscous fingering. We quantify the fluid saturations and interfacial areas, and compare the simulation results with the experimental results of Zhang et al.,[7] who conducted a series of displacement experiments in a homogeneous pore network micromodel with precisely microfabricated pore structures
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