Relative Permeability Hysteresis: Trapping Models and Application to Geological CO2 Sequestration

Abstract

The complex physics of multiphase flow in porous media are usually modeled at the field scale using Darcy-type formulations. The key descriptors of such models are the relative permeabilities to each of the flowing phases. It is well known that, whenever the fluid saturations undergo a cyclic process, relative permeabilities display hysteresis effects. In this paper we investigate hysteresis in the relative permeability of the hydrocarbon phase in a two-phase system. We propose a new model of trapping and waterflood relative permeability, which is applicable for the entire range of rock wettability conditions. The proposed formulation overcomes some of the limitations of existing trapping and relative permeability models. The new model is validated by means of pore-network simulation of primary drainage and waterflooding. We study the dependence of trapped (residual) hydrocarbon saturation and waterflood relative permeability on several fluid/rock properties, most notably the wettability and the initial water saturation. The relevance of relative permeability hysteresis is then evaluated for modeling geological CO 2 sequestration processes. Here we concentrate on CO 2 injection in saline aquifers. In this setting, the CO 2 is the nonwetting phase, and trapping of the CO 2 is an essential mechanism after the injection phase, during the lateral and upward migration of the CO 2 plume. We demonstrate the importance of accounting for CO 2 trapping in the relative permeability model for predicting the distribution and mobility of CO 2 in the formation. We conclude that a proper treatment of the nonwetting phase trapping leads to a higher estimate of the amount of CO 2 that it is safe to inject.

Efficiently engineering pore-scale processes: The role of force dominance and topology during nonwetting phase trapping in porous media

“…For either goal, dry-out conditions should be avoided. Manipulation of initialv NW could potentially be accomplished via use of a water-alternating-gas scheme (as proposed by Spiteri et al [47]), which may have significant water use impacts; or via manipulation of injection patterns to inject to intermediate saturations. For example, one suggestion would be to have a shorter vertical injection interval in the injection well: injection only into the lower portions of the aquifer would allow for vertical migration and might prevent the CO 2 plume from approaching high saturation levels at the injection point.…”

A benchmark study on problems related to CO2 storage in geologic formations

“…The land trapping parameter is chosen to be C = 0.75 (see also [59]). Some simplifying assumptions for this problem are given below.…”

A New Methodology for Simulation and Optimization of CO2Sequestration in a Saline Aquifer Using Artificial Neural Network and Model Predictive Control Approach

“…Some others concluded the relation between viscous to gravity ratio and CO 2 trapping (Mo et al, 2005). Other studies survey CO 2 injection rates and hysteresis on the overall performance (Spiteri et al, 2005;Juanes et al, 2006). The relation between reservoir parameters and changes in injection rates and gravity number (N gv is a ratio of gravity to viscous forces) can be described as follows:…”