Transition layer thickness at a fluid-porous interface

The length scale of the transition region between a porous layer and its overlying fluid layer is experimentally studied. The experimental setup consists of a rectangular channel, in which a fluid layer flows over a porous bed. Using particle image velocimetry and refractive index matching, two-dimensional velocity measurements in the interfacial region were performed. The thickness of this transition layer, defined by the height below the permeable interface up to which the velocity decreases to the Darcy scale, is measured and compared with the permeability and the matrix grain size. It was observed that the thickness of the transition zone, δ, is of the order of the grain diameter, and hence, much larger than the square root of the permeability as predicted by previous theoretical studies. The Reynolds number and the fluid height over the porous substrate were found to affect the gradient of the horizontal velocity component at the interfacial region while the length scale of the transition layer remains approximately unchanged. The effect of the porous matrix type has been investigated by utilizing spherical glass beads as well as granulates. Scaling the measured velocities by the interfacial velocity near the uppermost solid matrix resulted in a unique velocity distribution in the case of monodisperse glass beads, hinting that the interfacial velocity represents a proper scaling factor. However, for polydisperse granulate material deviation from this behavior was observed

Effect of TiO2–SiO2 hybrid nanofluids on enhanced oil recovery process under different wettability conditions

The effect of TiO2–SiO2 hybrid nanofluid on the enhanced oil recovery process is experimentally investigated. The flooding efficiency is measured for a flooding process in an initially oil-filled transparent micro-porous medium. Measurements were performed for two different surface wettability conditions, namely water-wet and neutral-wet. The average nanoparticle size, viscosity, surface tension, and contact angle of TiO2–SiO2 hybrid nanofluid are reported. The flooding efficiency of the hybrid nanofluid is compared with that of SiO2 nanofluid and TiO2 nanofluid. The experimental results reveal that for neutral-wet surface condition, SiO2 nanofluid achieves the best recovery, whereas for water-wet surface condition, TiO2–SiO2 hybrid nanofluid produces the best flooding efficiency. Obtained results showed that TiO2 nanofluid is unstable, with larger aggregated particles settling under gravity, and therefore not suitable for the flooding process by itself. The efficiency of hybrid nanofluid flooding depends significantly on fluid stability, wettability of the porous wall, surface tension, and contact angle of the three phases (crude oil, nanofluid solution, and solid surface). The TiO2–SiO2 hybrid nanofluid reduces surface tension while increasing contact angle and solution stability.Document Type: Original articleCited as:  Goharzadeh, A., Fatt, Y. Y., Sangwai, J. S. Effect of TiO2 – SiO2 hybrid nanofluids on enhanced oil recovery process under different wettability conditions. Capillarity, 2023, 8(1): 1-10. https://doi.org/10.46690/capi.2023.07.0

Modeling of Two-Phase Flow with Deposition in Vertical Pipes

Deposition is found in many engineering processes, such as the asphaltene deposition in oil pipelines/wellbores, and biological and chemical foulings in pipes or heat exchangers. These deposition processes usually occur in a two-phase flow environment. This study develops a model for two-phase flow with deposition in vertical pipes. The model consists of three modules: Fluid Transport, Particle Transport, and Particle Deposition. The Fluid Transport module predicts the fluids’ velocities and pressure. The Particle Transport module calculates the particle distribution. The Particle Deposition module models the actual attachment of particles onto the wall. The model is verified against a few limiting cases with analytical solutions. Then, it is validated against experimental data for two-phase flow without deposition. Demonstration of the model for bubbly flow with deposition is performe

Integrated One-Dimensional Modeling of Asphaltene Deposition in Wellbores/Pipelines

—Asphaltene deposition in wellbores/pipelines causes serious production losses in the oil and gas industry. This work presents a numerical model to predict asphaltene deposition in wellbores/pipelines. This model consists of two modules: a Thermodynamic Module and a Transport Module. The Thermodynamic Module models asphaltene precipitation using the Peng-Robinson Equation of State with Peneloux volume translation (PR-Peneloux EOS). The Transport Module covers the modeling of fluid transport, asphaltene particle transport and asphaltene deposition. These modules are combined via a thermodynamic properties lookup-table generated by the Thermodynamic Module prior to simulation. In this work, the Transport Module and the Thermodynamic Module are first verified and validated separately. Then, the integrated model is applied to an oilfield case with asphaltene deposition problem where a reasonably accurate prediction of asphaltene deposit profile is achieve

Three Dimensional Measurements of Asphaltene Deposition in a Transparent Micro-Channel

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 applicatio

Examining Asphaltene Solubility on Deposition in Model Porous Media

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

Experimental investigation of Asphaltene deposition in a transparent mini-channel

Paper presented to the 10th International Conference on Heat Transfer, Fluid Mechanics and Thermodynamics, Florida, 14-16 July 2014.One of the most recurring flow assurance problems in oil and gas industry is associated to the formation of organic and inorganic deposits in the wellbores and the near-wellbore regions. In particular, the depositions of asphaltene in wellbores represent both a major obstacle for petroleum engineers and a challenging topic for scientists. This paper focuses on experimental investigation of asphaltene deposition in transparent mini-channel. The working fluid is a mixture of heptane and crude oil. Induced by the addition of n-heptane, the dissolved asphaltene in crude oil precipitates to form asphaltene particles which deposit on the walls of the transparent mini-channel at ambient temperature. The thickness of asphaltene deposition is estimated using a visualization technique based on 3D microscopy. The thickness of the deposition layer is quantified and the two-dimensional profile of the deposition at selected axial section is measured. The obtained experimental results provide new insights into the deposition process in micro-scale and will be used to validate a developed numerical model.dc201

Characterizing Asphaltene Deposition in the Presence of Chemical Dispersants in Porous Media Micromodels

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 is 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 alkylphenol 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 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 platform to develop and design effective chemical dispersants for flow assurance problems

Experimental study of asphaltene deposition in transparent microchannels using light absorption method

Heptane-induced asphaltene precipitation from crude oil and its deposition in a vertical transparent microchannel is investigated. The amount of asphaltene deposited on a transparent channel wall is quantified using a non-intrusive flow visualization technique based on reflected light intensity and image analysis. Asphaltene deposits strongly affect the reflected light intensity through the change of mixture color in the recorded images. An empirical equation is developed to correlate the intensity of the light absorption to the thickness of the deposited asphaltene in a transparent microchannel. Non-uniform deposition along the longitudinal direction of the microchannel is also characterized