Asphaltene Adsorption Research Articles

Asphaltene adsorption on MgO, CaO, SiO2, and Al2O3 nanoparticles synthesized via the Pechini-type Sol−Gel method

Basic, amphoteric, and acidic metal oxide nanoparticles including MgO, CaO, SiO2 and Al2O3 were synthesized via the Pechini-type sol–gel process and evaluated for adsorption of two types of asphaltenes (Ap1, Ap2) extracted from two different Iranian crude oils. The adsorbents were characterized by the N2 adsorption–desorption, XRD, FE-SEM, TEM, and EDS and the asphaltene samples were examined using FTIR analysis. The effects of citric acid to metal precursor molar ratio (M), calcination temperature, type of adsorbent, textural properties, adsorption temperature, and regeneration on the adsorbent performance were investigated. The SiO2 nanoparticle with the highest specific surface area and an amphoteric character was an excellent adsorbent capable of removing more than 70% of asphaltene from a model oil with initial asphaltene concentration of 3000 ppm. However, CaO exhibited the highest specific adsorption capacity, indicating that basic sites were active centers for asphaltene adsorption. It was demonstrated that with increasing the calcination temperature, the crystallite sizes of MgO and SiO2 increased and their BET surface areas decreased. The maximum asphaltene adsorption capacities of MgO and SiO2 nanoparticles were obtained at optimal calcination temperatures of 600 °C and 500 °C, respectively. Moreover, the optimum M value for the synthesis of MgO nanoparticle, in terms of asphaltene adsorption capacity, was M = 1, while it was M = 2 (for Ap1) and M = 1 (for Ap2) for SiO2. The adsorption isotherms were best fitted by the Jovanovic model. Moreover, kinetic data for the best adsorbents (MgO and SiO2) were in maximum agreement with the Elovich model. The adsorbents could be easily regenerated by calcination at 600 °C.

Applications of zeolite-zirconia-copper nanocomposites as a new asphaltene inhibitor for improving permeability reduction during CO2 flooding

Using nanoparticles for adsorbing asphaltene was known as an efficient method among researchers for crude oil upgrading. In this study, zeolite-zirconia-copper nanocomposites (NCs) have been synthesized and characterized with Scanning electron microscopy (SEM), X-ray diffraction (XRD), Brunauer–Emmett–Teller (BET), and energy-dispersive X-ray (EDX). Then, CO2-oil interfacial tension (IFT) tests, Ultraviolet–visible spectroscopy (UV–Vis) Langmuir and Freundlich isotherm models, asphaltene precipitation tests at static phase, and dynamic CO2 flooding tests were performed in the presence of NCs and the results were compared with zeolite nanoparticles. Based on the characterization results, zirconia-copper particles were distributed at the surface of zeolite with total dimensions less than 30 nm, and the specific surface areas of the NCs (327.82 m2/g) was less than the pure zeolite (369.48 m2/g). It was seen that NCs had a greater asphaltene adsorption capacity and the application of decreasing asphaltene precipitation was higher in comparison to the zeolite nanoparticles. Accordingly, NCs were selected for performing dynamic CO2 tests and investigation of the permeability and porosity reduction parameters at obtained static condition. After adding NCs at the dynamic phase, asphaltene depositions that occured after CO2 injection was decreased and permeability/porosity reduction parameters were improved.

On the evaluation of asphaltene adsorption onto dolomite surface: The roles of flow condition, composition of asphaltene, and dolomite size

Asphaltene precipitation/deposition is one of the main problems in petroleum industry at various stages. In this study, various controlling factors on the adsorption of different types of asphaltene on the surface of dolomite of different size, as one of the most abundant minerals in the reservoir is investigated. First, asphaltenes and adsorbents (dolomite) properties were analyzed via several analytical techniques. Then, adsorption of four asphaltene samples of various origins and chemical composition on dolomite at micron and nano size were carried out in both static and dynamic modes and results were examined following the adsorption process. Based on the static tests, the adsorption amount of asphaltenes on nano- and micro-dolomite was measured 3.52–11 mg/m2 and 0.82–2.74 mg/m2, respectively. The results revealed that the most significant parameters that would affect the asphaltene adsorption on dolomite as an adsorbent are the total nitrogen and sulfur (N + S) content and the aromaticity of the asphaltenes. Moreover, as the flow rate was increased three times in the dynamic experiments, a decrease of 15–25% in asphaltene adsorption was observed, which was attributed to physisorption of asphaltene on dolomite or due to higher flow velocities. Collectively, the findings of this study can enable us to better understand the mechanisms of asphaltene adsorption/precipitation on dolomite and lead to better management of oil production from dolomitic reservoirs.

Effect of water cut on the performance of an asphaltene inhibitor package: experimental and modeling analysis

In this work, the influence of water cut on the effectiveness of a newly developed asphaltene inhibitor was studied. The asphaltene inhibitor concentration during adsorption and desorption processes on the rock surface was evaluated at various values of water cut. Inhibitor adsorption on the rock surface was studied by determining the amount of adsorbed reagent when injecting the solution containing the inhibitor into core samples. This was done by measuring the inhibitor concentration at the outlet of the coreholder. Also, the analysis of the inhibitor desorption from the rock surface was performed after the completion of the adsorption process by injecting the solution without the inhibitor. At 500 ppm of the inhibitor, its effectiveness was decreased by only about 2% with a change in water cut from 40 to 90%. The results showed that a minimum inhibitory concentration (MIC) was observed about 3 times faster when the water cut was increased from 40% to 90%. Moreover, the amount of asphaltene adsorption onto the rock surface was decreased from 712 to 502 mg/kg due to an increase in the water cut.

Effect of asphaltene adsorption on the magnetic and magnetorheological properties of heavy crude oils and Fe3O4 nanoparticles systems

An essential understanding of the adsorptive phenomena involving nanomaterials and asphaltenes has received considerable attention in oil recovery and production applications. Particularly, iron oxide-based nanoparticles have emerged as advanced materials due to their unique physicochemical properties, including thermal conductivity and superparamagnetism. On this basis, the kinetics and adsorption isotherms of magnetite (Fe3O4) nanoparticles/asphaltene systems were investigated, as well as the synergistic effect of resins acting as stabilizing colloidal agents. The results indicated rapid asphaltene adsorption that, essentially, follows the phenomenological external mass transfer (EMT) model. At the equilibrium, the asphaltene adsorption was adequately described by the monolayer Langmuir model. By these findings, it was studied for the first time the effect of the adsorbed asphaltenes on the magnetic dipolar interactions in nanoparticles/asphaltene powder state configurations, by applying a simple analytical model based on magnetic susceptibility and demagnetizing field concepts. It was proven accurately that asphaltenes coated the surfaces of the nanoparticles forming layers that stimulate a steric repulsive barrier between particles and, thus, reducing the intensity of interactions. Accordingly, a theoretical method was validated to estimate the magnetic-size distribution parameters by comparison with the physical distribution data obtained by Transmission Electron Microscopy (TEM). Finally, from the magnetically modified dynamic rheological properties, it was inferred that isotropic aggregates are naturally formed in the absence of the magnetic field, and these morphological features were not dramatically changed after the imposition of the field, leading to direct extrapolation of the modeling-based procedure for powders to real colloidal configurations applied in oil field operations.

Effects of Asphaltene Concentration and Test Temperature on the Stability of Water-in-Model Waxy Crude Oil Emulsions.

In oil fields, the formation of water-in-waxy crude oil emulsion is inevitable. The dissolved/crystallized state wax can interact with asphaltenes and then greatly affect the emulsion stability. However, studies on this aspect are still insufficient. In this work, the effects of the test temperature (30 °C well above the wax appearance temperature (WAT) and 15 °C well below the WAT) and asphaltene concentration (0∼1.5 wt %) on the stability of the water-in-model waxy crude oil emulsions containing 10 wt % wax were systematically investigated. When the model crude oils contain no wax, the flowability of the oils is good and the asphaltene concentration has little influence on the oil rheology. Increasing the asphaltene concentration facilitates the adsorption of asphaltenes to the oil–water interface, thus reducing the interfacial tension and water droplet size while enhancing the interfacial dilatational modulus. The stability of the emulsions improves with the increase in the asphaltene concentration, but the emulsions are still unstable. When the model crude oils contain 10 wt % wax, the WAT slightly decreases from the initial 25 to 24 °C after the addition of asphaltenes. The oil rheology is greatly improved by the addition of 0.05 wt % asphaltenes. With the further increase of the asphaltene concentration, the improved rheological ability of the asphaltenes deteriorates rapidly. At the asphaltene concentration of 1.5 wt %, the oil rheology is dramatically aggravated. The stability of the emulsion containing 10 wt % wax is mainly controlled by two aspects: on the one hand, the dissolved-state wax (30 °C) could facilitate the adsorption of asphaltenes to the interface, further reduce the interfacial tension and the water droplet size, and enhance the interfacial dilatational modulus; on the other hand, the wax crystals precipitated in the oil phase (15 °C) can form a stronger network structure at relatively high asphaltene concentrations (0.5∼1.5 wt %) and then immobilize the water droplets. The above two aspects greatly improve the sedimentation and coalescence stabilities of the emulsions at 15 °C. In addition, we did not find persuasive evidence showing that the wax could crystallize around the water droplets and strengthen the oil–water interfacial films.

Adsorption Behavior of Asphaltene on Clay Minerals and Quartz in a Heavy Oil Sandstone Reservoir with Thermal Damage

AbstractDifferences in the properties of clay minerals cause formation damage under the condition of thermal production in heavy-oil reservoirs; asphaltenes adsorbed on clay minerals exacerbate the formation damage. The purpose of the present study was to reveal the variation in clay minerals and the adsorption behavior of asphaltenes on clay mineral surfaces under thermal recovery conditions. Volume changes and transformations of typical clay minerals were studied under various conditions (80 and 180°C, pH 9 and 11, aqueous and oven-dry conditions). On this basis, the adsorption behavior and mechanism of asphaltenes on the surfaces of clay minerals in various simulated conditions were investigated. The adsorption mechanism was revealed using kinetics and isothermal adsorption models. The results showed that the volume of montmorillonite expanded by up to 159.13% after water–rock interaction at 180°C with pH 11; meanwhile, the conversion rates of kaolinite and illite to montmorillonite were 6.6 and 7.8%, respectively. The water–rock interaction intensified the volume changes and transformations of clay minerals under thermal conditions. The amounts of asphaltene adsorbed on clay minerals at 180°C were greater than those at 80°C. The adsorption process of asphaltenes was inhibited under aqueous conditions. The abilities of the constituent minerals to bind asphaltenes was in order: montmorillonite > chlorite > kaolinite > illite > quartz sand. The adsorption process of asphaltenes yielded high coefficients of regression with both the Freundlich and Langmuir models under oven-dry (>0.99) and aqueous (>0.98) conditions. At 180°C under aqueous conditions, the water film significantly inhibited the adsorption of asphaltene on the clay minerals. The adsorption process of asphaltenes, therefore, could be regarded as the adsorption occurring at lower concentrations under oven-dry conditions.

Oil production enhancement, asphaltene precipitation and permeability damage during CO2-SAG flooding of multi-layer sandstone reservoirs

The process of CO2-SAG flooding involves conventional miscible CO2 flooding until breakthrough (BT), followed by a period of CO2 soaking or shut-in, and then a continuation of the miscible CO2 flooding. The SAG process provides different improvements in the oil recovery for different positions of each layer in multilayer reservoirs, and has different effects on the distribution of pore throat blocking and adsorption of asphaltene to mineral surfaces. In this paper, both miscible CO2-SAG and conventional CO2 flooding experiments have been carried out at reservoir conditions and on multi-layer systems composed of 3 long cores each with increasing porosities and permeabilities, which were connected in parallel. After CO2-SAG flooding oil recovery factors (RF) of the low, medium and high permeability cores were 7.7%, 8.3%, and 7.6% higher compared to the RFs after CO2 flooding, respectively. The respective fractional oil production (FOP) of each long core was 10.6%, 27.7%, and 61.6% after CO2-SAG flooding, with less difference between each long core than for CO2 flooding. After CO2 flooding, the permeability of the high permeability core at the injection end dropped by 24.5–25.8%, which is 5.5–14.3% higher than the value at the outlet. The permeability decrease due to CO2-SAG flooding was 0.7–9.7% higher than that due to CO2 flooding, and the distribution of permeability decline was more homogeneous. The contribution of the total permeability decrease attributable to asphaltene particle blockage due to CO2 flooding was 84.7–62.7%, 5.2–10.1% higher than that due to CO2-SAG flooding, gradually decreasing along the flow direction. Complex two-phase flow of oil and gas is more likely to cause pore throat blockage instead of causing the adsorption of asphaltene precipitation.

Effect of solvent on the adsorption behavior of asphaltene on silica surface: A molecular dynamic simulation study

In recent years, the hybrid thermal-solvent process has been widely applied to improve the recovery performance of steam injection processes in heavy oil reservoirs. In this paper, the method of Molecular Dynamics (MD) simulation is employed to illuminate the asphaltenes adsorption behavior in the thermal-solvent recovery process. Three different solvent molecules (CO2, C3H8, and nC4H10) and SARA (Saturates, Aromatics, Resins, Asphaltenes) simulated heavy oil model are constructed as the basic simulation model. A series of MD simulations at different temperature conditions are performed. Results show that for the SARA model, the asphaltene molecules can interact with the silica by a T-shape stacking, finally forming the asphaltene dense aggregates as a basic heavy oil occurrence state. The steric hindrance effect of other SARA components can also contribute to this configuration. Temperature significantly affects the adsorption configuration of asphaltenes by disassembling the dense core and loosening the structure of the aggregates. For the SARA model in three solvent atmospheres, the increasing temperature can benefit the extraction of light components. CO2 can only extract saturates, while nC4H10 and C3H8 can simultaneously extract the saturates and aromatics. Besides, asphaltenes re-precipitation behavior can be observed in the 393 K CO2 atmosphere. Both nC4H10 and C3H8 have mutual solubility with the heavy oil system. No apparent precipitation of asphaltenes occurs in the above two atmospheres. Comparing the performance of extraction capability and diffusion capability in all MD simulations, the nC4H10 can both extract light oil components and control the asphaltenes precipitation. It further reveals that nC4H10 can recover heavy oil more efficiently at a microcosm level. Among the three different solvents, nC4H10 is the optimal solvent for hybrid thermal-solvent processes in heavy oil reservoirs.

Evaluation of Asphaltene Adsorption Free Energy at the Oil–Water Interface: Effect of Oil Solvents

We investigated asphaltene adsorption behaviors at the oil–water interface, focusing on the effect of oil solvents, by molecular dynamics simulations. Heptane, toluene, and their mixtures with ratios of heptane to toluene of 25:75, 50:50, and 75:25 by volume (namely, heptol25, heptol50, and heptol75) were used as the oil models. Two asphaltene models with essentially the same structure were employed: one contains a basic pyridine-type nitrogen heteroatom; another contains no heteroatoms. The asphaltene adsorption Gibbs free energy at the oil–water interface was evaluated by potential of mean force (PMF) calculations using the umbrella sampling method. The results show that the oil solvent not only affects the adsorption Gibbs free energy but also the adsorption structure as revealed by PMF minimum numbers, locations, and asphaltene orientation angles. For nitrogen-containing asphaltene, the adsorption Gibbs free energy increases linearly with the heptane volume fraction. Noteworthily, the adsorption Gibbs free energy value of this nitrogen-containing asphaltene is high enough to adsorb at the toluene–water interface. It implies that solely adding solvent (such as toluene) may not be enough for solving the emulsion problems induced by interface-active asphaltenes. For the asphaltene without heteroatoms, the asphaltene prefers to be solvated in the oil phase, and there is no well-defined adsorption state when the heptane volume fraction is less than half. For heptol75–water and heptane–water interface systems, the asphaltene adsorption minima can be detected. This clearly indicates that the oil solvent can influence the surface activity of asphaltenes. The study highlights the importance of subtle balances of different noncovalent interactions between asphaltenes, water, and oil components in the oil solvent. The detailed understanding of the asphaltene adsorption behaviors presented in this study will be helpful to solve oil–water emulsion problems and understand the effect of water cut to asphaltene deposition in crude oil production.

Effects of asphaltene structure and polythiophene-coated magnetite nanoparticles on surface topography and wettability alteration of silica surface

Natural chemical structures in asphaltene cause it to form a colloidal aggregate that can affect crude oil properties, alter the wettability of reservoir rock surface, and reduce oil recovery. The objective of this research work is to investigate variations in surface properties of silica surface such as topography and wettability during asphaltene precipitation in the presence of magnetite (Fe3O4) nanoparticles (NPs). The magnetite nanoparticles (MNP) are coated with polythiophene to make them more stable and enhance their adsorption capacity. The structure of three asphaltenes used in this research work is determined using nuclear magnetic resonance (NMR), elemental analysis, and Fourier-transform infrared spectroscopy (FTIR) to obtain more details about asphaltene adsorption on the surface of the polythiophene-coated magnetite nanoparticles (MNP@PT). The results show that heteroatoms (e.g., O, N, and S) and aromatic rings as functional groups can affect asphaltene agglomeration and adsorption process onto silica surface. Atomic force microscopy (AFM) is used to obtain adequate topography information. Roughness parameters show that a heterogeneous surface is formed after asphaltene precipitation on the homogeneous silica surface. Contact angle measurement technique and modified Wenzel model are used to investigate the effect of MNP@PT on wettability alteration. The change in contact angle for pure silica upon asphaltene precipitation is lower in the presence of MNP@PT. The silica surface is extremely oil-wet after asphaltene precipitation, but it becomes preferentially oil-wet in the presence of MNP@PT. We showed that MNP@PT are an excellent absorbent to reduce asphaltene precipitation/deposition. The outcome of this research work can increase the current understanding of molecular interactions between asphaltene and solid surfaces in the presence of MNP@PT to reduce impact of asphaltene precipitation on wetness characteristics of the silica surface during oil production.

МАГНИТО-СОРБЦИОННАЯ ДЕАСФАЛЬТИЗАЦИЯ НЕФТЯНЫХ ФРАКЦИЙ

The article uses a magneto-sorption method for extracting asphaltenes from petroleum fractions using nanosized magnetite. Factors affecting the sorption separation of asphaltenes from toluene were evaluated using model systems prepared by dissolving asphaltenes isolated from superviscous oil from the Ashalchinskoye field (Tatarstan). It was found that the presence of polar compounds has the greatest effect on the sorption of asphaltenes from toluene solutions. Benzoic acid or isopropyl alcohol was used to evaluate the effect of acids and polar compounds. To study the effect of solution viscosity on asphaltene adsorption, model solutions of polystyrene in toluene with different viscosities were prepared by adding different amounts of polymer. Two types of sorbents were investigated: magnetite powder and suspensions of magnetite, modified with oleic acid, in toluene and n-pentane. The efficiency of using magnetite suspensions in comparison with its powder for sorption of asphaltenes is shown: for a suspension in toluene sorption increases 5 times, and in n-pentane, sorption increases 14 times. The influence of a magnetic field (0.5 T) on the increase in the sorption of asphaltenes from light oil feedstock was revealed: for a suspension in n-pentane, sorption increases from 220 ± 25 to 313 ± 38 g/g of adsorbent). The increase in sorption in the samples that passed through the magnetic installation is explained by the greater availability of asphaltenes due to the destruction of some of their clusters.

Mechanistic Investigation of Asphaltene Adsorption and Oxidation by Nanoparticles: A New Solution to an Old Problem

Mechanistic Investigation of Asphaltene Adsorption and Oxidation by Nanoparticles: A New Solution to an Old Problem

On the use of metallic nanoparticulated catalysts for in-situ oil upgrading

An exhaustive review on the application of different metal-based nanoparticles for the upgrading of heavy oils has been performed. Particular emphasis has been put on those catalysts used for in-situ upgrading using various thermal treatment methods aiming at extracting heavy oils in a more effective manner. Different types of catalysts have been identified, such as monometallic (Mg, Al, Si, Ca, Ti, V, Cr, Mn, Fe, Co, Ni, Cu, Zn, Zr, Mo, Ce, and W), non-supported bimetallic (Ti/Zr), non-supported polymetallic (various mixtures of Co, Mo, Ni, W, Al, Zn, Cu), and supported (various metals on silica, alumina, carbon, zeolite, biogenic particles, complex inorganic and organic). Due to the great diversity of nanoparticulated catalysts (type, metal content, synthesis procedure, particle size) and evaluation conditions (experimental setup, reaction conditions, type of feed), it is not possible to make a direct comparison on their performance. Some results are highlighted on the effectiveness of the catalysts for heavy oil upgrading in terms of asphaltene adsorption, viscosity reduction, increase of API gravity, and coke formation. The reviewed literature indicates the need for more research on this topic as to develop more effective catalysts not only for increasing the recovery factor but also for permanent upgrading of the quality of heavy and extra-heavy oil.

Wettability alteration by surface adsorption of asphaltene molecular in carbonate porous media

In this study, the effect of four asphaltene samples on the wettability alteration of carbonate reservoir rock is investigated. The wettability of each core, before and after the deposition of asphaltene, is evaluated using two methods: relative permeability and contact angle. Normally, core samples got oil-wet after the asphaltene deposition, and the contact angle on the surface increased. However, the degree of wettability of each crude oil was different based on the asphaltene composition. According to the elemental analysis of asphaltene samples, the H/C index alone cannot show the asphaltene adsorption potential. The sulfur is an element that enhances asphaltene-asphaltene interaction, but weakens calcite-asphaltene interaction. The oxygen can also enhance the adsorption of asphaltene to calcite, depending on the functional group and its location in the molecule. According to the results of the FTIR spectrum of asphaltene and rock powder, there are three main mechanisms for adsorption of asphaltene to calcite surface, followed by wettability alteration. The first mechanism is the electrostatic interaction between asphaltenes and calcite, which is because of the poly-aromatic nature of asphaltene. The intensity of the electrostatic interaction between asphaltene and rock is directly related to the aromaticity and condensation index of asphaltene. The second mechanism is dispersion, in which the side alkyl chain in the aromatic rings causes asphaltene to be adsorbed into the surface of the rock. The intensity of this mechanism is also proportional to the aliphatic index and the long chain index of asphaltene. The third mechanism, which is less important than the two above-mentioned ones, is the hydrogen bond that is proportional to the ROH index, calculated from the FTIR spectrum. To study the relationship between the electrostatic property of the surface after asphaltene adsorption with surface wettability, zeta potential was used. The results showed that asphaltene, because of its acidic nature, adsorbed to the calcite surface, would make its zeta potential negative. However, more negative zeta potential will not necessarily increase the contact angle. In other words, the surface wettability and electrostatic properties of the surface are two distinct categories that do not have a clear relationship. The surface wettability is more dependent on the amount of aromaticity index of asphaltene, whereas the electrostatic property of the surface is a function of the percentage of oxygen and sulfur compounds in the asphaltene structure. Finally, the scanning electron microscopy (SEM), along with the elemental analysis, was used to investigate the dispersion of various elements at the calcite surface after wettability alteration. The calcium and oxygen are the main elements of calcite production; therefore, the elemental mapping indicated that the surface would be covered with calcium and oxygen prior to the deposition of asphaltene (CaCO3). But by asphaltene deposition on the rock surface, calcium will be observed scattered in some points. For this reason, the amount of calcium in the elemental mapping can be related to the level of surface wettability, so that the lower the percentage of calcium in the surface, the more the asphaltene is adsorbed into calcite, and the changes in the contact angle is greater.

Effect of nanoparticle modified polyacrylamide on wax deposition, crystallization and flow behavior of light and heavy crude oils

In this article, the potential use of silica and alumina polyacrylamide to inhibit wax crystallization and deposition of real crude oils has been studied for the first time. The performance of nanocomposites on a light and heavy crude oil was evaluated using cold finger apparatus, differential scanning calorimeter (DSC), polarizing microscopy, and rheometer. Nanocomposites effectively reduce wax deposition with 79% and 70% maximum efficiency for heavy and light oil, respectively. The flowability of treated heavy oil was improved, while a less pronounced effect was observed for treated light oil. DSC measurements indicated nanocomposites to delay the wax crystallization onset of heavy oil more noticeable than light oil. Polarized microscopy showed a visible morphological change, as the introduction of nanocomposites caused regular roundly shaped and finely dispersed wax crystals for both light and heavy crude oils. The results indicate that the presence of nanocomposites delays the wax crystallization process by presenting multiple spherical nucleation templates, influencing the wax crystal interactions, and preventing the formation of stable wax networks in agreement with the percolation theory predictions. The better inhibition effect of nanocomposites for heavy oil may result from two mechanisms. First, the well-dispersed nanocomposites act as nucleation centers for wax crystals. Second, asphaltene adsorption on the nanocomposite surface may prevent the formation of the asphaltene-wax three-dimensional network and delays wax crystallization. This research indicates the possibility of using silica and alumina polyacrylamide as an effective chemical agent for the inhibition of wax deposition of crude oil.

Review on Application of Nanotechnology for Asphaltene Adsorption, Crude Oil Demulsification, and Produced Water Treatment

Nanotechnology is widely recognized for having important applications in many industries, one of which is oil and gas. Both environmental and cost benefits can be achieved when using nanoparticles for the separation of water and oil or further purification of produced water. More efficient emulsion separation can be achieved by selective adsorption of naturally present stabilizing components or magnetic action applied to nanoparticle-tagged droplets. The focus of this review is given to both nanoparticles and nanocomposites that have been studied with respect to asphaltene adsorption, crude oil demulsification, and produced water treatment, as well as oil spill cleanup and improvement of antifouling resistance of filtration membranes. Asphaltene chemistry and its role in emulsion stabilization are discussed in detail.

Can fluid-substitution models continue to ignore the complex physicochemical properties of crude oil?

The mechanical nature of fluid-substitution models has always been recognized as a major cause of their limited predictive power. For instance, saturants are typically treated as simple fluids characterized only by their densities, viscosities, and moduli of elasticity; their chemistry is just ignored, even when that fluid is crude oil. However, crude oil is a complex mixture of several thousand organic compounds characterized by a variety of molecular weights, polarities, and polarizabilities, and the response of its rheological behavior to acoustic wave propagation is difficult to predict, especially when it resides in the pore space of rocks. We have performed ultrasonic-velocity measurements on carbonate core plugs saturated with a brine and with a light crude oil that are mechanically similar (i.e., having comparable densities, viscosities, and moduli of elasticity) and that show a significant and consistent excess of hardening when the saturant is oil. Dispersion and wettability are excluded as explanations for the data. We hypothesize that asphaltene aggregation and adsorption as well as paraffin-wax crystallization (and possibly volumetric expansion) combine to cause crude oil to exhibit a dilatant-like behavior within the pore space of carbonates at ultrasonic frequencies. In general, the observed effect would be similar to the hardening of ooblek at high deformation rates. This hypothesis could be tested in the future by an adequate combination of high-resolution imaging and microfluidic setups. This and similar studies would be beneficial in developing physical fluid-substitution models with a more consistent predictive power.

Suppression of Asphaltene Adsorption and Deposition in Porous Media

Suppression of Asphaltene Adsorption and Deposition in Porous Media

Experimental Measurement and Equilibrium Modeling of Adsorption of Asphaltenes from Various Origins onto the Magnetite Surface under Static and Dynamic Conditions.

Wettability alterations, permeability reduction of reservoir rocks, and oil production decline may occur as a consequence of asphaltene adsorption and deposition on the surfaces of oil reservoir rocks. Magnetite and other iron minerals are abundant in the rock composition of sandstone reservoirs and cause problems by precipitation and adsorption of polar components of crude oil. The main purpose of this study was to investigate the adsorption of six asphaltene samples of various origins onto the magnetite surface. Characterization of magnetite was performed by Brunauer–Emmett–Teller (BET), Fourier transform infrared spectroscopy (FTIR), and X-ray fluorescence (XRF). Also, FTIR, dynamic light scattering (DLS), and elemental analysis were performed to characterize asphaltenes. Static and dynamic adsorption experiments were carried out to investigate the effects of the water phase, adsorbent size, flow rate, and asphaltene compositions on asphaltene uptake by the magnetite. The results showed that an increase in the nitrogen content and aromatic nature of asphaltenes increased their adsorption on magnetite. The addition of water to the adsorption tests significantly reduced the adsorption amount of asphaltenes on the magnetite. A considerable decrease in asphaltene adsorption was observed with an increase in the flow rate in dynamic tests. This shows that higher flow rates reduce the interaction between adsorbed asphaltenes and asphaltene aggregates in the solution, which reduces the uptake of more asphaltenes. Moreover, adsorbed asphaltene components with a weaker bond are detached from the magnetite surface, which can be attributed to the physisorption of asphaltenes. Eventually, four well-known adsorption isotherm models, namely, Langmuir, Dubinin–Radushkevich, Temkin, and Freundlich were utilized to find the mechanisms of asphaltene adsorption onto the magnetite surface. The Freundlich model seems to provide better estimates for the adsorption of asphaltenes on the magnetite surface. The findings of this study render insights into the better management of oil production in formations with iron-containing rocks.