Microfluidic mass transfer of CO2 at elevated pressures: implications for carbon storage in deep saline aquifers.

Carbon capture and sequestration (CCS) in a deep saline aquifer is one of the most promising technologies to mitigate anthropologically emitted carbon dioxide. Accurately quantifying the mass transport of CO2 at pore-scales is crucial but challenging for successful CCS deployment. Here, we conduct high-pressure microfluidic experiments, mimicking reservoir conditions up to 9.5 MPa and 35 °C, to elucidate the microfluidic mass transfer process of CO2 at three different states (i.e., gas, liquid, and supercritical phase) into water. We measure the size change of CO2 micro-bubbles/droplets generated using a microfluidic T-junction to estimate the volumetric mass transfer coefficient (kLa), quantifying the rate change of CO2 concentration under the driving force of concentration gradient. The results show that bubbles/droplets under high-pressure conditions reach a steady state faster than low pressure. The measured volumetric mass transfer coefficient increases with the Reynolds number (based on the liquid slug) and is nearly independent of the injection pressure for both the gas and liquid phases. In addition, kLa significantly enlarges with increasing high pressure at the supercritical state. Compared with various chemical engineering applications using millimeter-sized capillaries (with typical kLa measured ranging from ≈0.005 to 0.8 s-1), the microfluidic results show a significant increase in the volumetric mass transfer of CO2 into water by two to three orders of magnitude, O (102-103), with decreasing hydrodynamic diameter (of ≈50 µm).

Microfluidic salt precipitation: implications for geological CO2 storage.

Salt precipitation in porous media can detrimentally hinder the processes of carbon capture and storage (CCS) in deep saline aquifers because pore-blocking salt crystals can decrease the injectivity of wells and formation permeabilities. It is, however, challenging to unravel the pore-scale dynamics and underlying mechanisms of salt nucleation using conventional core-flooding techniques. Here, we conduct microfluidic experiments to reveal the high-resolution, pore-scale measurements of the de-wetting patterns and drying rate of brine and subsequent salt precipitation during gas injection. We investigate the effects of pore structures and brine concentrations. The results show three distinct stages: (I) initial, (II) rapid growth, and (III) final phases in the progression of salt nucleation, with different rates and size distributions upon brine drying. Two types of crystal patterns, bulk crystal and polycrystalline aggregate, are observed. In addition, most of the large salt deposits (≥0.5 × 105µm2) are precipitated at the near outlet region during the second rapid growth stage. The influence of porosity is demonstrated by correlating the brine-drying and salt-precipitation speeds during the second rapid growth phase.

Development of a Microfluidic Method to Study Enhanced Oil Recovery by Low Salinity Water Flooding.

Microfluidics is an appealing method to study processes at rock pore scale such as oil recovery because of the similar size range. It also offers several advantages over the conventional core flooding methodology, for example, easy cleaning and reuse of the same porous network chips or the option to visually track the process. In this study, the effects of injection rate, flood volume, micromodel structure, initial brine saturation, aging, oil type, brine concentration, and composition are systematically investigated. The recovery process is evaluated based on a series of images taken during the experiment. The remaining crude oil saturation reaches a steady state after injection of a few pore volumes of the brine flood. The higher the injection rate, the higher the emulsification and agitation, leading to unstable displacement. Low salinity brine recovered more oil than the high salinity brine. Aging, initial brine saturation, and the presence of divalent ions in the flood led to a decrease in the oil recovery. Most of the tests in this study showed viscous fingering. The analysis of the experimental parameters allowed to develop a reliable and repeatable procedure for microfluidic water flooding. With the method in place, the enhanced oil recovery test developed based on different variables showed an increase of up to 2% of the original oil in place at the tertiary stage.