The Role of Counter-Current Flow in the Modeling and Simulation of Multi-Phase Flow in Porous Media

Carbon Capture and Storage (CCS) is the capture of carbon dioxide (CO2) from large source points, such as power plants, and storing it in geological formation. It is a potential means of reducing CO 2 concentration in the atmosphere to mitigate global warming and ocean acidification. Geological formations are considered to be the most promising storage sites for carbon dioxide. Deep saline aquifers have the most storage capacity compared to other geological sites.;After CO2 is injected into an aquifer, a fraction of it, that can be large, is immobilized in the form of residual phase. Residual entrapment is an important component in successful storage of CO2 in saline aquifers. Trapped CO2 is eventually dissolved into the brine. Estimation of the fraction of the injected CO2 that is trapped depends on CO2 saturation profiles and saturation history. In the simulation of CO2 injection into saline aquifers, conventional relative permeabilities functions are commonly used and it is assumed that viscous coupling is negligible. We show that the vertical migration of CO2 in saline aquifers is often dominated by counter-current flow. Experimental and simulation studies of two- and three-phase flow in porous media show that the counter-current relative permeability is less than co-current relative permeability, that are commonly used (current industry standard) in the simulation of multiphase flow.;This study focuses on including a velocity- -dependent relative permeability model in the simulation of multiphase flow in porous media to account for the flow dynamics (co- vs. counter-current flow) on relative permeability and fluid mobility. We use both co-current and counter-current relative permeability in the simulation of CO2 injection from a well into an aquifer and show that the plume saturation profile is influenced by the dynamic relative permeability changes (transitions between co-current and counter-current flow). The fraction of the injected CO2 that is trapped and the time-scale of vertical migration of CO2 both increase when the transitions from co- to counter-current relative permeability are included. We conclude that using one set of relative permeabilities is not sufficient in the simulation of CO2 injection into saline aquifers. We also demonstrate that a velocity-dependent mobility does not introduce numerical instability and that the simulation time does not change significantly.;We have applied the velocity-dependent relative permeability in the simulation of gas (CO2) injection into an oil reservoir in the context of enhanced oil recovery with three mobile phases. Cumulative oil and gas production increases just slightly in the new model, but water production decreases quite significantly. That is due to a better sweep efficiency when counter-current relative permeability is included in the calculation of phases' mobilities.;Counter-current relative permeability can be measured directly using a controlled experimental design to eliminate the effect of boundaries on saturation distribution. It can also be estimated by pore-scale simulations, e.g. Lattice Boltzman simulations. Both methods have been used in the literature and both show a reduction in the relative permeability in counter-current settings. We have tested an indirect procedure to conclude a reduction of relative permeability in counter-current flows.;The numerical simulations are done using IMPES and fully-implicit methods. No numerical instabilities were observed in any of the two methods by including counter-current relative permeability either in a discrete scheme or by using a velocity-dependent scheme. We conclude that the new model can predict CO 2 saturation profile more accurately than the conventional standard model.