Relative permeability of homogenous-wet and mixed-wet porous media as determined by pore-scale lattice Boltzmann modeling

Landry, Christopher J.; Karpyn, Zuleima T.; Ayala, Orlando

doi:10.1002/2013wr015148

Cited by 94 publications

(67 citation statements)

References 58 publications

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“…Under mixed-wet conditions, that characterize the majority of natural porous media (e.g. rocks, soils), both fluids may contact the solid surfaces, the steady-state two-phase flow regimes are expected to become more complicated and the steady-state oil and water relative permeability are expected to change drastically (Landry et al, 2014). Therefore, any results obtained with experiments conducted on homogeneous-wet porous media cannot be extrapolated explicitly to mixed-wet porous media.…”

Section: Introductionmentioning

confidence: 99%

Steady-state two-phase relative permeability functions of porous media: A revisit

Tsakiroglou

Aggelopoulos

Terzi

et al. 2015

International Journal of Multiphase Flow

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Section: Introductionmentioning

confidence: 99%

Steady-state two-phase relative permeability functions of porous media: A revisit

Tsakiroglou

Aggelopoulos

Terzi

et al. 2015

International Journal of Multiphase Flow

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“…Small pores and corners of the pore space remain water‐wet due to the high capillary pressure required for the water displacement, leading to mixed‐wet conditions. Although fluid flow in mixed‐wet systems has been extensively modeled for estimation of capillary pressure and relative permeabilities (Bradford & Leij, ; Bultreys, Stappen, et al, ; Landry et al, ; Ryazanov et al, ; Valvatne & Blunt, ; van Dijke et al, ), limited studies investigated experimentally multiphase flow in mixed‐wet synthetic rocks (Al‐Raoush, ; Mirzaei et al, ) and real rocks (Habibi et al, ; M. Kumar et al, ; Schmatz et al, ; K Singh et al, ). Different methods have been implemented to prepare a mixed‐wet system including (1) mixing the oil‐wet sands treated with octadecyltrichlorosilane solutions and water‐wet sands at different ratios (Al‐Raoush, ; Mirzaei et al, ), (2) freezing the initial water followed by flushing with a stable chemical group to make the pore surface hydrophobic (M. Kumar et al, ), and (3) doping the oil with fatty acids and aging the cores overnight to make them mixed‐wet (K. Singh et al, ).…”

Section: Introductionmentioning

confidence: 99%

Wetting Behavior of Tight Rocks: From Core Scale to Pore Scale

Habibi

Dehghanpour

2018

Water Resources Research

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Previous measurements show mixed‐wet behavior of tight siltstone core plugs, initially saturated with air. However, the same plugs show water‐wet behavior when saturated with oil or water. This study aims at explaining these observations by investigating the effects of mineral heterogeneity and intermolecular forces acting on solid/liquid and liquid/liquid interfaces. First, we conduct pore‐scale visualizations to characterize the minerals surrounding the pores of the tight rock samples. Thin‐section and scanning electron microscopy/energy dispersive X‐ray spectroscopy analyses show the existence of multimineral pores, which can be responsible for the mixed‐wet behavior. Next, we apply the DLVO theory to investigate the intermolecular forces acting on solid/liquid and liquid/liquid interfaces. We use disjoining pressure‐distance profiles and contact angles calculated for different minerals to evaluate the stability of the thin film covering the rock grains and to explain the wettability of the core plugs during spontaneous imbibition tests. The disjoining pressure values calculated for the dry core plugs suggest similar wetting affinities toward oil and water. However, the contact angles calculated for the water‐saturated core plugs suggest the water‐wet behavior, which agrees with the countercurrent imbibition results. Finally, we measure the adhesion forces between the tip of a cantilever and (1) pure quartz slide, (2) pure calcite crystal, and (3) the rock thin section using an atomic force microscope. The values of adhesion forces measured for the thin section composed of multimineral pores are between those measured for pure quartz slide and pure calcite crystal.

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“…Computational methods include network modeling (Al-Dhahli et al, 2012;Øren et al, 1998;Piri and Blunt, 2005) and more recently explored techniques that perform calculations directly on segmented 3D rock images, such as lattice-Boltzmann methods (Landry et al, 2014;Ramstad et al, 2010), maximal-inscribed-spheres (MIS) methods (Silin et al, 2011), and level set methods (Jettestuen et al, 2013;Prodanoviíc and Bryant, 2006). Among these approaches, network modeling is currently the most developed technique for three-phase flow.…”

Section: Introductionmentioning

confidence: 99%

“…Previously, direct computational techniques were limited to simulating two-phase displacements at uniform wettability. However, the lattice-Boltzmann method was used recently to compute two-phase relative permeability in 3D mixed-wet pore structures (Landry et al, 2014). Further, the variational level set method has emerged as a promising technique to simulate three-phase capillary-dominated displacements directly on 3D segmented rock images under arbitrary, yet uniform wettability (Helland and Jettestuen, 2014).…”

Section: Introductionmentioning

confidence: 99%

Computation of Three-Phase Capillary Pressure Curves and Fluid Configurations at Mixed-Wet Conditions in 2D Rock Images

Zhou

Helland

Hatzignatiou

2014

SPE Annual Technical Conference and Exhibition

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We present a three-phase, mixed-wet capillary bundle model with cross-sections obtained from a segmented 2D rock image, and apply it to simulate gas invasion processes directly on images of Bentheim sandstone after two-phase saturation histories consisting of primary drainage, wettability alteration and imbibition. We calculate three-phase capillary pressure curves, corresponding fluid configurations and saturation paths for the gas invasion processes and study the effects of mixed wettability and saturation history by varying the initial water saturation after primary drainage and simulating gas invasion from different water saturations after imbibition. In this model, geometrically allowed gas-oil, oil-water and gas-water interfaces are determined in the pore cross-sections by moving two circles in opposite directions along the pore/solid boundary for each of the three fluid pairs separately. These circles form the contact angle with the pore walls at their front arcs. For each fluid pair, circle intersections determine the geometrically allowed interfaces. The physically valid three-phase fluid configurations are determined by combining these interfaces systematically in all permissible ways, and then the three-phase capillary entry pressures for each valid interface combination are calculated consistently based on free energy minimization. The valid configuration change is given by the displacement with the most favorable (that is, the smallest) gas-oil capillary entry pressure. The simulation results show that three-phase oil-water and gas-oil capillary pressure curves are functions of two saturations at mixed wettability conditions. We also find that oil layers exist in a larger gas-oil capillary pressure range for mixed-wet conditions than for water-wet conditions, even though a non-spreading oil is considered. Simulation results obtained in sandstone rock sample images show that gas invasion paths may cross each other at mixed-wet conditions. This is possible because the pores have different and highly complex, irregular shapes, in which simultaneous bulk-gas and oil-layer invasion into water-filled pores occurs frequently. The initial water saturation at the end of primary drainage has a significant impact on the gas invasion processes after imbibition. Small initial water saturations yield more oil-wet behavior, whereas large initial water saturations show more water-wet behavior. However, in both cases, the three-phase capillary pressure curves must be described by a function of two saturations. For mixed-wet conditions, in which some pores are water-wet and other pores are oil-wet, the gas-oil capillary pressure curves can be grouped into two curve bundles that represent the two wetting states. Finally, the results obtained in this work demonstrate that it is important to describe the pore geometry accurately when computing the three-phase capillary pressure and related saturation paths in mixed-wet rock.

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Relative permeability of homogenous-wet and mixed-wet porous media as determined by pore-scale lattice Boltzmann modeling

Cited by 94 publications

References 58 publications

Steady-state two-phase relative permeability functions of porous media: A revisit

Steady-state two-phase relative permeability functions of porous media: A revisit

Wetting Behavior of Tight Rocks: From Core Scale to Pore Scale

Computation of Three-Phase Capillary Pressure Curves and Fluid Configurations at Mixed-Wet Conditions in 2D Rock Images

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