Liquid CO₂ Displacement of Water in a Dual-Permeability Pore Network Micromodel

Abstract

Permeability contrasts exist in multilayer geological formations under consideration for carbon sequestration. To improve our understanding of heterogeneous pore-scale displacements, liquid CO(2) (LCO(2))-water displacement was evaluated in a pore network micromodel with two distinct permeability zones. Due to the low viscosity ratio (logM = -1.1), unstable displacement occurred at all injection rates over 2 orders of magnitude. LCO(2) displaced water only in the high permeability zone at low injection rates with the mechanism shifting from capillary fingering to viscous fingering with increasing flow rate. At high injection rates, LCO(2) displaced water in the low permeability zone with capillary fingering as the dominant mechanism. LCO(2) saturation (S(LCO2)) as a function of injection rate was quantified using fluorescent microscopy. In all experiments, more than 50% of LCO(2) resided in the active flowpaths, and this fraction increased as displacement transitioned from capillary to viscous fingering. A continuum-scale two-phase flow model with independently determined fluid and hydraulic parameters was used to predict S(LCO2) in the dual-permeability field. Agreement with the micromodel experiments was obtained for low injection rates. However, the numerical model does not account for the unstable viscous fingering processes observed experimentally at higher rates and hence overestimated S(LCO2).

Lattice Boltzmann simulation of immiscible fluid displacement in porous media: Homogeneous versus heterogeneous pore network

“…The viscosity ratio is defined as the ratio of the advancing non-wetting fluid viscosity to the defending wetting fluid viscosity (η w ), i.e., M = η n /η w . In addition, recent laboratory studies [41][42][43][44] have shown the strong influence of subcore scale heterogeneities on steady-state migration patterns, spatial distributions, and fluid saturations. To gain a better understanding of pore-scale two-phase displacement mechanisms, a series of numerical simulations are conducted to study the effect of 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.…”

Modelling foam improved oil recovery within a heterogeneous reservoir

“…In Figure 2(a) a spurious loop is clearly evident for t D = 0.2 and even for t D = 0.14 a tiny loop can be seen. Similarly, Figure 2(b) shows results for the same parameters but using equation (4). In this case the loop is formed earlier: already by time t D = 0.1 a very significant loop is in evidence 3 .…”

“…In addition, having more points to describe the foam front ensures a less jagged 4 There is a special rule that is used to subdivide the topmost front segment which arises due to the very high curvatures that can occur on the top boundary: see [11] for details.…”

“…is the angle between the normal to the front and the horizontal. Permeability differences affect the shape of the foam front (causing it to develop concavities and convexities), and are described using equation (3) or (4). A sharp concave corner is considered to have formed when the angle θ through which the front tangent turns at the concavity exceeds a certain critical value.…”

“…However, many studies have focused on homogeneous formations even when in real fields heterogeneous conditions are found [2,3]. A heterogeneous formation has variable permeability [4]. Therefore, the flow of fluids, and in this specific case, of foams is affected by this difference in permeability.…”