The recent advances in 3‐D imaging of porous structures have generated a tremendous interest in the simulation of complex single and two‐phase flows. Lattice‐Boltzmann (LB) schemes present a powerful tool to solve the flow field directly from the binarized 3‐D images. However, as viscosity often plays an important role, the LB scheme should correctly treat viscosity effects. This is the case using a LB scheme with two relaxation times (TRT) unlike the broadly used, the single‐relaxation rate, BGK, where the velocity of the modeled fluid does not vary as the inverse of the viscosity applying the bounce‐back (no‐slip) boundary rule. The aim of this work is to apply the LB‐TRT approach to different types of porous media (straight channels, 2‐D model porous media, sandstone) to solve for the flow field and to evaluate the approach in terms of parameter dependence, error and convergence time on the basis of permeability. We show that the variation of permeability with the free relaxation parameter Λ of the TRT scheme depends on the heterogeneity of the sample and on the numerical resolution. The convergence time depends on the applied viscosity and the parameter standing for the speed of sound, thus the computation time can be reduced by choosing appropriate values of those parameters. Two approaches to calculate permeability (Darcy's law and viscous energy dissipation) are proposed and investigated. We recommend to use Darcy's law, as dependence on Λ is less important. Periodic (in the presence of a driving body force) and pressure boundary conditions are evaluated in terms of the results.

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Simulating flow of a Bingham fluid in porous media still remains a challenging task as the yield stress may significantly alter the numerical stability and precision. We present a Lattice-Boltzmann TRT scheme that allows the resolution of this type of flow in stochastically reconstructed porous media. LB methods have an intrinsic error associated to the boundary conditions. Depending on the schemes this error might be directly linked to the effective viscosity. As for non-Newtonian fluids viscosity varies in space the error becomes inhomogeneous and very important. In contrast to that, the TRT scheme does not present this deficiency and is therefore adequate to be used for simulations of non-Newtonian fluid flow. We simulated Bingham fluid flow in porous media and determined a generalized Darcy equation depending on the yield stress, the effective viscosity, the pressure drop and a characteristic length of the porous medium. By evaluating the flow in the porous structure, we distinguished three different scaling regimes. Regime I corresponds to the situation where fluid is flowing in only one channel. Here, the relation between flow rate and pressure drop is given by the non-Newtonian Poiseuille law. During Regime II an increase in pressure triggers the opening of new paths and the relation between flow rate and the difference in pressure to the critical yield pressure becomes quadratic: [Formula: see text]. Finally, Regime III corresponds to the situation where all the fluid is flowing. In this case, [Formula: see text].

Standard reservoir evaluations are based on Archie's law relating the average water saturation to the average electrical resistivity by R(ind) = S(w)(-2). However, especially in the case of complex heterogeneous carbonates, deviation from Archie's law is observed and generally attributed to factors affecting the percolation or disconnectedness of the different phases (wetting films, microporosity, macropores) assuring electrical conductance. Pore-network models (PNM's) in combination with high-resolution computed microtomography (μ-CT) constitute a very effective tool to investigate the influence of the geometry and topology of the porous media on the spatial distribution of the conductive phase, and therefore on the shape of the resistivity index curve. An extended version of the classical PNM applicable to dual-porosity systems is presented. It combines the classical pore-network modeling applied on the macroporous space with the macroscopic properties of the microporous phase, supposing that the two pore systems act in parallel. Three-dimensional images provide information on the connectedness of the microporous phase, which is then included in the simulations. Electrical behavior of sandstone and two carbonates presenting distinct resistivity index curves were simulated and compared to measurements. Both Archie and "non-Archie" behavior were correctly reproduced, and the curve shape was explained considering percolation of the different phases.

The NMR propagator technique allows the measurements of the variance σ(2)=<(ξ-<ξ>)(2)> of the displacements as a function of time t when flowing in a porous media. The time dependence of σ is a very sensitive test of Gaussian behavior compared to the analysis of the shape of the propagators. Superdispersion occurs when σ(2)[proportionality]t(α) with the exponent α larger than 1. In a homogeneous 30-μm grain pack and 10 < Pe < 35, we observed weak superdispersion in saturated conditions (α = 1.17) and gradually strong superdispersion as the water saturation decreases (up to α = 1.5) during steady-state oil-water two-phase flow. In saturated conditions, the corresponding longitudinal propagators and breakthrough curves are Gaussian or nearly Gaussian, whereas in two-phase conditions, the longitudinal propagators are nonsymmetric and the breakthrough curves show a tail at long times.