Laboratory investigation of capillary trapping under mixed‐wet conditions

Abstract

[1] Remaining oil saturation established by waterflooding was measured in Indiana limestone in its original, water-wet state and under mixed-wet conditions established by adding organic acid to the oil phase. The porous plate technique was used to establish initial oil saturations ranging from S nwi ¼ 0.23 to 0.93 under capillary-dominated conditions. For water-wet conditions, the residual oil saturation increased linearly with its initial saturation. In contrast, the remaining oil saturation under mixed-wet conditions, S nw , displayed three distinct regimes. First, S nw increased with its initial saturation up to S nwi ¼ 0.58. Next, S nw decreased from S nwi ¼ 0.58 to 0.76. Finally, S nw increased again as S nwi approached one. The nonmonotonic dependence of S nw on S nwi at S nwi > 0.5 is well described by a concaveup quadratic function, and may be a salient feature of mixed-wet rocks.

Oil/water displacement in microfluidic packed beds under weakly water-wetting conditions: competition between precursor film flow and piston-like displacement

“…It can be readily seen that after t = O(10) , oil displacement ceased at all Ca and ⟨ s o ⟩ L reached its long-time, steady-state value. This transient time falls between t = O(1) typically reported under strongly water-wet conditions e.g., (Salathiel 1973;Mungan 1966;Tanino and Blunt 2012;Christensen and Tanino 2017a) and t = O(50 − 1000) reported under mixed-wet conditions (e.g., Salathiel 1973;Tanino and Blunt 2013;Christensen and Tanino 2017a), further corroborating the near-neutral wettability indicated by the measured s . In the discussion that follows, the remaining oil saturation at the end of the waterflood experiment, Ŝ or , was evaluated as the time-average of ⟨ s o ⟩ L after � t > 100.…”

“…Waterflood oil displacement is a function of the hydrophilicity of the grains, grain roughness, pore size distribution and pore geometry, viscosity ratio, Ca, and system dimensions, and meaningful comparison of absolute values with other experimental systems is difficult (e.g., Dullien et al 1989;Xu et al 2017;Yun et al 2017;Nguyen et al 2006;Tanino and Blunt 2013;Vizika et al 1994). Notwithstanding this, present measurements of Ŝ or ≈ 0.52 are broadly larger than values reported in the literature at comparable Ca, which range from Ŝ or ≈ 0.09 in a 3D packed bed of smooth spheres (Datta et al 2014, s ≈ 5…”

Capillary trapping for geologic carbon dioxide storage – From pore scale physics to field scale implications

“…Expanding on this work Tanino and Blunt (2013) showed that oil saturation continued to decrease with over 100 pore volumes of water injected. The results of porescale simulation studies showed that when the residual was finally achieved, the relationship with initial saturation is complex, with the IR curve becoming convex with the maximum residual saturation occurring at an initial saturation below the maximum (Spiteri et al, 2008).…”

Influence of Wettability on Residual Gas Trapping and Enhanced Oil Recovery in Three-Phase Flow: A Pore-Scale Analysis by Use of Microcomputed Tomography

“…We note that oil-layer flow (Table 3) may contribute to further oil recovery but at a slow rate because of the low relative permeability of these layers (caused by their thin cross-sectional area) (Øren et al 1992;Blunt et al 1995). In this context, one clear limitation of the micro-CT technique needs to be mentioned: Thin layers (thickness of a few to a few hundred nm) cannot be observed, although they play a significant role in terms of wettability effects and associated fluid dynamics (Hirasaki 1991;Blunt et al 1995;Tokunaga and Wan 2013).…”

“…This wettability effect is of particular importance in sandstone and carbonate-oil reservoirs because these are frequently intermediate-wet or even oil-wet (Cuiec 1991). Specifically, wettability has a strong impact on petrophysical parameters (Anderson 1987a-f), including residual saturations (Morrow 1990;Tanino and Blunt 2013), relative permeabilities (McCaffery and Bennion 1974), capillary pressures (Morrow 1976;Anderson 1987d), fluid topologies , and CO 2 -storage capacities (Iglauer et al 2015). We demonstrate that there is a large variation in fluid configurations, fluid/ fluid curvatures, and capillary pressures, which leads to the wellknown complexity of three-phase flow (Øren et al 1992).…”