Using a visualization setup, we characterized the solute transport in a micromodel filled with two fluid phases using direct, real-time imaging. By processing the time series of images of solute transport (dispersion) in a two fluid-phase filled micromodel, we directly delineated the change of transport hydrodynamics as a result of fluid-phase occupancy. We found that, in the water saturation range of 0.6-0.8, the macroscopic dispersion coefficient reaches its maximum value and the coefficient was 1 order of magnitude larger than that in single fluid-phase flow in the same micromodel. The experimental results indicate that this non-monotonic, non-Fickian transport is saturation- and flow-rate-dependent. Using real-time visualization of the resident concentration (averaged concentration over a representative elementary volume of the pore network), we directly estimated the hydrodynamically stagnant (immobile) zones and the mass transfer between mobile and immobile zones. We identified (a) the nonlinear contribution of the immobile zones to the non-Fickian transport under transient transport conditions and (b) the non-monotonic fate of immobile zones with respect to saturation under single and two fluid-phase conditions in a micromodel. These two findings highlight the serious flaws in the assumptions of the conventional mobile-immobile model (MIM), which is commonly used to characterize the transport under two fluid-phase conditions.

Hybrid pore-network and Lattice-Boltzmann permeability modelling accelerated by machine learning.

No abstract

It is well-known that solvent treatment and preconditioning play an important role in rejection and flux performance of membranes due to solvent-induced swelling and solvent adsorption. Investigations into the effect of solvent treatment are scarce and application specific, and were limited to a few solvents only. This study reveals the trend in solvent treatment based on solvent polarity in a systematic investigation with the aim to harness such effect for intensification of membrane processes. Nine solvents with polarity indices ranging from 0.1 to 5.8 (hexane to acetonitrile) were used as treatment and process solvents on commercial Borsig GMT-oNF-2, Evonik Duramem 300, and emerging tailor-made polybenzimidazole membranes. TGA-GCMS, HS-GC-FID, and NMR techniques were employed to better understand the effect of solvent treatment on the polymer matrix of membranes. In this work, apart from the solvent treatment's direct effect on the membrane performance, a subsequent indirect effect on the ultimate separation process was observed. Consequently, a pharmaceutical case study employing chlorhexidine disinfectant and antiseptic was used to demonstrate the effect of solvent treatment on the nanofiltration-based purification. It is shown that treatment of polybenzimidazole membranes with acetone resulted in a 25% increase in product recovery at 99% impurity removal. The cost of the process intensification is negligible in terms of solvent consumption, mass intensity, and processing time.

Conventional flow models based on Darcy's flow physics fail to model shale gas production data accurately. The failure to match field data and laboratory-scale evidence of non-Darcy flow has led researchers to propose various gas-flow models for the shale reservoirs. There is extensive evidence that suggests the size of the pores in shale is microscopic in the range of a few to hundreds of nanometers (also known as nanopores). These small pores are mostly associated with the shale's organic matter portion, resulting in a dual pore system that adds to the gas flow complexity. Unlike Darcy's law, which assumes that a dominant viscous flux determines a rock's permeability, shale's permeability leads to other flow processes besides viscous flow such as gas slippage and Knudsen diffusion. This work reviews the dominant gas-flow processes in a single nanopore on the basis of theoretical models and molecular dynamics simulations, and lattice Boltzmann modeling. We extend the review to pore network models used to study the gas permeability of shale.