Asphaltenes are known to cause severe flow assurance problems in the near-wellbore region of oil reservoirs. Understanding the mechanism of asphaltene deposition in porous media is of great significance for the development of accurate numerical simulators and effective chemical remediation treatments. Here, we present a study of the dynamics of asphaltene deposition in porous media using microfluidic devices. A model oil containing 5 wt % dissolved asphaltenes was mixed with n-heptane, a known asphaltene precipitant, and flowed through a representative porous media microfluidic chip. Asphaltene deposition was recorded and analyzed as a function of solubility, which was directly correlated to particle size and Péclet number. In particular, pore-scale visualization and velocity profiles, as well as three stages of deposition, were identified and examined to determine the important convection-diffusion effects on deposition.

Asphaltenes are components in crude oil known to deposit and interrupt flows in critical regions during oil production, such as the wellbore and transportation pipelines. Chemical dispersants are commonly used to disperse asphaltenes into smaller agglomerates or increase asphaltene stability in solution with the goal of preventing deposition. However, in many cases, these chemical dispersants fail in the field or even worsen the deposition problems in the wellbores. Further understanding of the mechanisms by which dispersants alter asphaltene deposition under dynamic flowing conditions are needed to better understand flow assurance problems. Here, we describe the use of porous media microfluidic devices to evaluate how chemical dispersants change asphaltene deposition. Four commercially used alkyl-phenol model chemical dispersants are tested with model oils flowing through porous media, and the resulting deposition kinetics are visualized at both the matrix-scale and the pore-scale. Interestingly, initial asphaltene deposition worsens in the presence of the tested dispersants, but the mechanism by which plugging and permeability reduction in the porous media varies. The velocity profiles near the deposit are analyzed to further investigate how shear forces affect asphaltene deposition. The deposition tendency is also related to the intermolecular interactions governing the asphaltene-dispersant systems. Furthermore, the model system is extended to a real case. The use of porous media microfluidic devices offers a unique

Asphaltenes are surface-active polyaromatic molecules in crude oil that are known to deposit in pipelines or stabilize water droplets by flocculating at interfaces resulting highly viscous emulsions, leading to significant flow assurance problems. Commercial dispersants have been developed to disturb asphaltene aggregation to mitigate deposition, but their role on the interfacial properties of asphaltene films is unclear. In this study, we elucidate asphaltene interfacial rheology at air-water and oil-water interfaces at high and low asphaltene surface coverage and in the presence of dispersants. A modified Langmuir trough with double-wall ring rheometer is used to simultaneously visualize the microstructure of asphaltene interface and measure the rheological responses. Two surface coverages, 0.5 and 4 lg cm À2 , show widely different rheological responses at air-water interfaces. Strong yielding behavior was observed for higher coverage while a less yielding behavior and wider linear viscoelastic regime were observed for the lower coverage. Additionally, asphaltenes at decane-water interfaces were less shear-thinning than at air-water interfaces. Surface pressure-area compression-expansion curves show that the interface is more compressible in the presence of commercial chemical dispersants. This combined imaging and interfacial rheology platform provide an effective method to correlate asphaltene microstructure to interfacial rheological properties. V

Asphaltene-related flow assurance problems are prevalent in oil production processes and are at the heart of issues such as the plugging of pipelines, the damage of rock formations, and the stabilization of viscous water-in-oil emulsions. A comprehensive understanding of the interfacial behavior of asphaltenes, from a physical–chemical perspective, is required for an accurate design of solutions to these challenges. In this work, we elucidate the deposition dynamics of various asphaltene subfractions in a porous media microfluidic model. Extrography fractions from the interlaboratory sample known as PetroPhase 2017 asphaltenes, reported to be a mixture of abundant island and archipelago motifs, and Wyoming deposit C7 asphaltenes, known for being island type dominated, are investigated. The deposition rate increases when the compositional ratio archipelago/island motif increases for PetroPhase 2017 derived fractions, whereas Wyoming deposit asphaltenes appear to exhibit stronger aggregation for fractions whose composition is uniformly island type. In general, the deposition rate is consistent with the amount of precipitated asphaltenes. However, the correlation is not merely a linear one and the pore-scale morphology changes even with similar deposition rates. Estimated diffusivity, the relative ratio of convection and diffusion, and fluid flow profiles are used to explain the dynamic growth of the deposit at the pore scale.

This study presents in situ visualization of the emulsification/demulsification of asphaltene-stabilized water-in-oil emulsions using microfluidic devices. Monodisperse water-in-oil emulsions were generated using a T-junction, and droplet coalescence was analyzed further upstream of the collision chamber. The state of aggregation of asphaltenes contained in the model oil was found to strongly affect the stability of the emulsions. The aqueous phases used in this study contained either surfactant (C12–15E7) or microemulsion with and without demulsifiers. Different demulsifiers and their concentrations were observed to dramatically affect the coalescence rate. The dilatational surface viscoelasticity properties were also measured using a pendant drop tensiometer. Surprisingly, no correlation was found between the dilatational surface viscoelasticity response and the coalescence rate of the water-in-oil emulsions.

Angular resolved velocity distributions of laser desorbed neutral matrices (dihydroxybenzoic acids, DHB) and analytes (tryptophan) embedded in these matrices were investigated at 322 nm by a modified crossed molecular beam apparatus. Desorbed ions generated from MALDI were measured by a time-of-flight mass spectrometer. Desorptions of neutral matrix and analyte from 2,3-DHB, 2,4-DHB, 2,5-DHB, 2,6-DHB, and 3,5--DHB at 322 nm have similar properties, but the ion intensities are in the order 2,3DHB ≅ 2,6-DHB > 2,5-DHB ≅ 2,4-DHB > 3,5-DHB. It indicates that the combination of various parameters related to neutral species, including absorption coefficient, sublimation energy, contact of analyte and matrix in crystal, and plume dynamics of desorbed species are not crucial in the determination of MALDI process for DHB isomers. The difference of matrix activity of DHB isomers at this wavelength must result from the other properties, like the excited state lifetime, proton affinity, gas-phase basicity, acidity, ionization energy, or the other properties related to the primary reactions in ion generation.

Asphaltenes are a significant contributor to flow assurance problems related to crude oil production. Because of their polydispersity, model molecules such as coronene and violanthrone-79 (VO-79) have been used as mimics to represent the physiochemical properties of asphaltenes. This work aims to evaluate the emulsion-stabilization characteristics of fractionated asphaltenes and these two model molecules. Such evaluation is expected to better characterize the stabilizing mechanisms of asphaltenes on water-in-oil emulsions. The coalescence process of water-in-oil emulsion droplets is visualized using a microfluidic flow-focusing geometry. The rate of coalescence events is used as the parameter to assess emulsion stability. Interfacial tension (IFT) and oil/brine zeta potential are measured to help explain the differences in the rates of coalescence. VO-79 is found to be better at stabilizing emulsions as compared to coronene. Although VO-79 and asphaltenes have similar interfacial tension and oil/brine zeta potential values, the rate of coalescence differs significantly. This highlights the difficulty in using model molecules to mimic the transport dynamics of asphaltenes.

This study describes a novel experimental approach to directly measure the thicknesses of asphaltene deposits in micro-channels. The thickness of the asphaltene deposit is estimated using a visualization technique based on 3D digital microscopy. The working fluid is a mixture of n-heptane and dead oil. Induced by the addition of n-heptane, the asphaltenes present in crude oil phase separate at ambient temperature to form aggregates of asphaltene-rich phase. Part of the asphaltene aggregates deposit on the walls of the transparent micro-channel. A two-dimensional profile of the deposit across the channel at selected axial sections is measured. The influences of injection mixture volume on the growth of the thickness of deposited asphaltenes is investigated using two experimental conditions, (i) varying elapsed time at constant flow rate and (ii) increasing the flow rate at a constant elapsed time. In both cases the deposit thickness of asphaltene (δ) increases with the total injection volume (V). The experimental results obtained in this work provide new insights into the deposition process at the micro-scale level, which can be used to facilitate the development of more accurate numerical model for this application.