We present a real-rock micromodel approach whereby microfluidic channels are fabricated in a naturally occurring mineral substrate. The method is applied to quantify calcite dissolution which is relevant to oil/gas recovery, CO2 sequestration, and wastewater disposal in carbonate formations - ubiquitous worldwide. The key advantage of this method is the inclusion of both the relevant substrate chemistry (not possible with conventional microfluidics) and real-time pore-scale resolution (not possible with core samples). Here, microchannels are etched into a natural calcite crystal and sealed with a glass slide. The approach is applied to study acidified brine flow through a single channel and a two-dimensional micromodel. The single-channel case conforms roughly to a 1-D analytical description, with crystal orientation influencing the local dissolution rate an additional 25%. The two-dimensional experiments show highly flow-directed dissolution and associated positive feedback wherein acid preferentially invades high conductivity flow paths, resulting in higher dissolution rates ('wormholing'). These experiments demonstrate and validate the approach of microfabricating fluid structures within natural minerals for transport and geochemical studies. More broadly, real-rock microfluidics open the door to a vast array of lab-on-a-chip opportunities in geology, reservoir engineering, and earth sciences.

In this paper, we present a microfluidic approach to measure liquid solvent diffusivity in Athabasca bitumen. The method has three distinguishing features: (a) a sharp initial condition enabled by the high wettability of the solvent; (b) one-dimensional diffusive transport (in the absence of convection) ensured by microscale confinement; and (c) visible-light-based measurement enabled by the partial transparency of the bitumen at small scales. The method is applied to measure the diffusion of toluene into bitumen by imaging transmitted light profiles over time, and relating intensities to the mass fractions. Plotting toluene mass fraction versus distance/sqrt(time), results in a tight superposition of all curves (time-dependent mass fractions) demonstrating the diffusion dominated nature of the system and the robustness of the method. The diffusion transport equations were solved and fit to a constant diffusion coefficient as well as a variety of concentration-dependent diffusion coefficient relations found in the literature. For intermediate toluene mass fractions (0.2–0.8), a constant diffusion coefficient of 2.0 × 10–10 m2/s provides an appropriate representation. However, at low toluene mass fractions (<0.2), significantly reduced diffusive transport is observed, and endpoint analysis indicates diffusion coefficients trending toward 4.3 × 10–11 m2/s. At high toluene mass fractions (>0.8), the values trend toward 1.5 × 10–10 m2/s. This microfluidic method provides an inexpensive and rapid mutual diffusion coefficient evaluation, with significantly improved spatial/composition resolution vis-à-vis competing measurement methods.

In this paper, we evaluate nanoparticle-stabilized CO2 foam stability and effectiveness in enhanced oil recovery at the pore and micromodel scales. The nanoparticle-stabilized CO2 gas-in-brine foams maintain excellent stability within microconfined media and continue to be stable after 10 days, as compared to less than 1 day for surfactant foam. The nanoparticle-stabilized CO2 foams are shown to generate a 3-fold increase in oil recovery (an additional 15% initial oil in place), as compared to an otherwise similar CO2 gas flood. Fluorescence imaging is applied to quantify emulsion size distribution (down to 1 μm) in both CO2 and nanoparticle-stabilized CO2 foam flood cases. Nanoparticle-stabilized CO2 foam flooding results in significantly smaller oil-in-water emulsion sizes with an average size of 1.7 μm (∼80% smaller than a CO2 gas flood), with negligible impact on water-in-oil emulsions. The effectiveness of nanoparticle-stabilized CO2 foam is compared for representative light, medium, and heavy oils. All three oils show substantial additional oil recovery and a potentially valuable reservoir homogenization effect. Collectively, these results highlight the pore-scale dynamics, effectiveness, and potential for nanoparticle-stabilized foams in enhanced oil recovery.

Predicting carbon dioxide (CO(2)) security and capacity in sequestration requires knowledge of CO(2) diffusion into reservoir fluids. In this paper we demonstrate a microfluidic based approach to measuring the mutual diffusion coefficient of carbon dioxide in water and brine. The approach enables formation of fresh CO(2)-liquid interfaces; the resulting diffusion is quantified by imaging fluorescence quenching of a pH-dependent dye, and subsequent analyses. This method was applied to study the effects of site-specific variables--CO(2) pressure and salinity levels--on the diffusion coefficient. In contrast to established, macro-scale pressure-volume-temperature cell methods that require large sample volumes and testing periods of hours/days, this approach requires only microliters of sample, provides results within minutes, and isolates diffusive mass transport from convective effects. The measured diffusion coefficient of CO(2) in water was constant (1.86 [± 0.26] × 10(-9) m(2)/s) over the range of pressures (5-50 bar) tested at 26 °C, in agreement with existing models. The effects of salinity were measured with solutions of 0-5 M NaCl, where the diffusion coefficient varied up to 3 times. These experimental data support existing theory and demonstrate the applicability of this method for reservoir-specific testing.

In this paper, we demonstrate the first application of microfluidics to study diffusive transport in extra heavy oils, such as bitumen. A cross-channel glass microfluidic chip was used to measure the CO2 diffusion in Athabasca bitumen. The device was initially filled with CO2 at low pressure (<1.0 bar). A plug of bitumen was injected into the central (50 μm wide and 20 μm deep) channel and, subsequently, exposed to high-pressure CO2 on both ends. One-dimensional oil swelling in response to CO2 diffusion was imaged over time. A simple mathematical approach was applied to calculate the diffusion coefficient based on the oil-swelling data. Measurement results are reported here at a range of pressures (1–5 MPa) and room temperature (21 °C). The measured diffusion coefficients in this range are on the order of 10–10 m2/s, in good agreement with the relevant published data using conventional methods. In sharp contrast to conventional methods that require hours or days and ∼0.5 L of sample, the method presented here requires ∼10 min and a 1 nL plug of sample.