Structure of surfactants adsorbed on solid surfaces is a key knowledge in various technologies and applications. It is widely accepted in the literature that the surface–surfactant headgroup electrostatic interaction is a major driving force of adsorption of ionic surfactants on charged substrates. Our result shows that the adsorption of surfactants as monomers is driven by both electrostatic and nonelectrostatic interactions. Further adsorption of surfactants in aggregates is essentially driven by the tail–tail interaction. To a great extent, the substrate–tail interaction determines the structures of the adsorbed surfactant aggregates. Water and counterions influence the headgroup–substrate and tail–substrate interactions. We investigate two vastly different surfactants and substrates by molecular dynamics simulations: (1) SDS on alumina (SDS–Al2O3), and (2) CTAB on silica (CTAB–SiO2). We study the adsorption of a single surfactant at the solid surface by the density profiles and free energy of adsorption. In the SDS–Al2O3 system, we analyze the free energy of adsorption on the substrate covered by aggregates of different sizes. We examine the configurations of surfactants and the distribution of water and ions at the liquid–solid interface as the number of adsorbed molecules on the substrate increases. In the SDS–Al2O3 system, the headgroup adsorption is mediated by the Na+ counterions; the adsorbed water molecules may be displaced by the surfactant headgroup but unlikely by the hydrocarbon tails. As a function of the surfactant adsorption, we observe single surfactants, aggregates of different morphologies, and bilayers. The CTAB–SiO2 system combines both electrostatic attraction of the surfactant headgroup and affinity for the surfactant’s hydrocarbon tail. At low surfactant adsorption, aggregates and single surfactant molecules lie on the substrate; hemimicelles form at intermediate adsorption; and micelles form at high surfactant adsorption. Our results agree with experimental observations and indicate two different surfactant adsorption mechanisms where the tail–tail and tail–substrate interactions play a fundamental role.

We report results from a systematic investigation of the effect of the temperature on the wettability of oil/brine/rock systems. An oil sample, produced from a sandstone reservoir, was tested on sandstone-like substrates (i.e., mica and quartz) in NaCl and MgCl2 solutions with concentrations ranging from 0 to 3 M. Raising the temperature from 25 to 50 °C has no discernible effect on the contact angle, regardless of substrate type, brine type, or salt concentration. Another oil sample, obtained from a carbonate reservoir, was examined on carbonate-like substrates (i.e., calcite) in NaCl and MgCl2 solutions over a concentration range of 0–1 M. The contact angles decrease as the temperature increases from 25 to 65 °C, and this temperature effect also strongly depends upon the brine type and salt concentration. A systematic examination of the ζ potential of rock/brine and oil/brine interfaces under different conditions and subsequent discussions indicate that contact angle and ζ potential may not be directly linked. These findings regarding the wettability of oil/brine/rock systems may improve the understanding of low-salinity wateflooding mechanisms by elucidating the combined effects of the temperature and other critical variables, including brine type, brine concentration, crude oil composition, and substrate type.

The aggregation and structure of polar molecules in nonpolar media may have a profound effect on bulk phase properties and transport. In this study, we investigate the aggregation and deposition of water and asphaltenes, the most polar fraction in petroleum fluids. In flow-line experiments, we vary the concentration of water from 500 up to 175 000 ppm and provide the evidence for clear changes in asphaltene deposition. Differential interference contrast (DIC) microscopy and dynamic light scattering (DLS) are used to measure the size of the aggregates. Rheological measurements are performed to get fixed ideas on the structural changes that water induces at different concentrations. This study demonstrates the significant effect of water on asphaltene aggregation and deposition and explores the molecular basis of water–asphaltene interaction. Our aggregate size measurements show that while asphaltene molecules increase the solubilization of water, there is no increase in the aggregate size. Our aggregation size measurements are different from the reports in the literature.

The Peng–Robinson (PR) and cubic-plus-association (CPA) equations of state are used to predict the phase behavior and solubility of CO2 and normal alkanes from C1 to nC10 in several bitumens. Both of the equations of state are investigated over wide ranges of temperature and pressure. The results show that the PR-EOS describes mixure of bitumens with CO2 and alkanes when there is no second liquid phase or when the asphaltene content in the second liquid phase is not high. The CPA-EOS describes the phase behavior of mixtures of bitumens and CO2 and alkanes in liquid–liquid states even when the asphaltene content of one of the phases is high. High asphaltene content results in significant association and cross-association where the CPA-EOS is a natural choice. In this work the only adjustable parameter in the CPA-EOS is the cross-association energy parameter, and we show that the solubility of CO2 and alkanes in bitumens is usually not sensitive to this parameter. However, in two-phase liquid–liquid and three-phase liquid–liquid–vapor states with one phase having a high concentration of asphaltenes, the results become sensitive to the cross-association energy parameter.

Wetting and alteration of wetting are among the most important material properties of fluid–fluid–substrate systems in biological and industrial systems. An important industrial application of wetting and wetting alteration is related to displacement of crude oil by water injection in porous media. Water injection in oil reservoirs has been used since the early periods of oil production. Recently, it has been discovered that the salt concentration in the injected water may have a significant effect on the oil recovery. The process is under active research for the need of an improved understanding. In this work, we investigate the governing elements of surface wettability with two different crude oils on two atomistically smooth surfaces (mica and quartz) and one smooth surface (calcite) as a function of the salt concentration (0–3 M) and type (mono- versus divalent). We investigate the change of wettability from NaCl and MgCl2 salts over a wide concentration for the first time. The measurements are based on long enough aging times and droplet sizes that give equilibrium and size-independent contact angles. Our measurements show a non-monotonic behavior, in that, as NaCl concentration increases, there is a decrease (increase of water-wetting) and then an increase (decrease of water-wetting) of the contact angle in all of the systems that we have studied. MgCl2 salt shows two trends with an increasing concentration. For mica and quartz, there is first a decrease of the contact angle and then an increase followed by a second sharp decrease at high MgCl2 concentrations. For calcite substrate, we observe an increase of the contact angle reaching a maximum and then a decrease with an increasing salt concentration. These observations have profound implications on the effect of salts on wettability alteration. The measurements have set the stage for atomistic simulations for a molecular understanding of the salt effect in complex fluids.

Surfactant aggregation plays an important role in a variety of chemical and biological nanoscale processes. On a larger scale, using small amounts of amphiphiles compared to large volumes of bulk-phase modifiers can improve the efficiency and reduce the environmental impact of many chemical and industrial processes. To model ternary mixtures of polar, nonpolar, and amphiphilic molecules, we develop a molecular thermodynamic theory for polydisperse water-in-oil (W/O) droplet-type microemulsions and reverse micelles based on global minimization of the Gibbs free energy of the system. The incorporation of size polydispersity into the theoretical formulation has a significant effect on the Gibbs free energy landscape and allows us to accurately predict micelle size distributions and micelle size variation with composition. Results are presented for two sample ionic surfactant/water/oil systems and compared with experimental data. By predicting the structural and compositional characteristics of w/o microemulsions, the molecular thermodynamic approach provides an important bridge between the modeling of ternary systems at the molecular and the macroscopic level.

In oil–water–mineral substrate systems, we show that the contact angle can be tuned by ionic structures in the water layer confined between an oil droplet and the substrate. We perform molecular dynamics simulations of a complex oil droplet in a NaCl aqueous solution on a mica surface; the oil is a mixture of n-decane and surfactant molecules. The surfactant head contains an OH group and an aromatic ring. A thin water layer between the oil droplet and the substrate and ionic stratification regulate the wetting behavior. The concentration of salt ions in the thin film is nonmonotonic; it first increases, then decreases, and starts increasing again as the salt concentration in the bulk increases. On the other hand, the surfactant head adsorption in the thin film first increases as the bulk salt concentration increases. Then, it decreases with further increase in the bulk salt concentration. The change of contact angle with salt concentration also shows a nonmonotonic behavior; the contact angle is first nearly constant to a low salt concentration of 0.1 wt % NaCl. Then, it decreases sharply as the salt concentration increases from 0.1 to 1.1 wt % NaCl. A reverse trend in contact angle follows with further salt concentration increase. The nonmonotonic trend unlike the monotonic trend of interfacial tension with salt concentration is in line with recent measurements of contact angle of oil–brine–substrate systems. A sharp increase of surfactant head adsorption in the thin film, the decrease of ion adsorption, and the minimum of contact angle are all related. This is the first report of such correlations with change of wetting in the brine–complex oil–mineral substrate predicted from molecular simulations.

Oil–water–substrate wettability is of prime importance in most branches of science and technology, from biology and nanomaterials to geology and petroleum science. Wetting is a three-phase interaction phenomenon as expressed in Young’s equation. Microscopically wetting is from the fluid–substrate interactions and surfaces are designated as lyophilic and lyophobic (fluid-wet and nonwet). Here we investigate the microscopic mechanisms of wettability changes by salt concentration in oil–water–mineral substrate systems. A model oil droplet (n-decane) placed in an aqueous electrolytic solution next to a solid substrate surface (muscovite mica) is simulated. A thin water layer between oil and the substrate regulates the oil–substrate interaction. We find that at zero and low salt concentrations, the oil adsorption on the hydrophilic mineral substrate is stabilized by a thin layer of water giving rise to a nonzero contact angle (partial oil wetting). As the salt concentration increases ionic adsorption and the water layer thickness increase reducing the oil–substrate wettability. Ions adsorb unsymmetrically on the substrate and promote water adsorption into the water layer. Ionic adsorption is higher away from the droplet than under the droplet. Our contact angles by molecular dynamics simulations are in agreement with experimental measurements.

Injection of optimized chemistry water in enhanced oil recovery (EOR) has gained much interest in the past few years. Crude oil–water interfaces can have a viscoelastic character affected by the adsorption of amphiphilic molecules. The brine concentration as well as surfactants may strongly affect the fluid–fluid interfacial viscoelasticity. In this work we investigate interfacial viscoelasticity of two different oils in terms of brine concentration and a nonionic surfactant. We correlate these measurements with oil recovery in a glass-etched flow microchannel. Interfacial viscoelasticity develops relatively fast in both oils, stabilizing at about 48 h. The interfaces are found to be more elastic than viscous. The interfacial elastic (G′) and viscous (G″) moduli increase as the salt concentration decreases until a maximum in viscoelasticity is observed around 0.01 wt % of salt. Monovalent (Na+) and divalent (Mg2+) cations are used to investigate the effect of ion type; no difference is observed at low salinity. The introduction of a small amount of a surfactant (100 ppm) increases the elasticity of the crude oil–water interface at high salt concentration. Aqueous solutions that give the maximum interface viscoelasticity and high salinity brines are used to displace oil in a glass-etched “porous media” micromodel. Pressure fluctuations after breakthrough are observed in systems with high salt concentration while at low salt concentration there are no appreciable pressure fluctuations. Oil recovery increases by 5–10% in low salinity brines. By using a small amount of a nonionic surfactant with high salinity brine, oil recovery is enhanced 10% with no pressure fluctuations. Interface elasticity reduces the snap-off of the oil phase, leading to reduced pressure fluctuations. This study sheds light on significance of interface viscoelasticity in oil recovery by change in salt concentration and by addition of a small amount of a nonionic surfactant.

Temperature affects the aggregation of macromolecules such as surfactants, polymers, and proteins in aqueous solutions. The effect on the critical micelle concentration (CMC) is often nonmonotonic. In this work, the effect of temperature on the micellization of ionic and nonionic surfactants in aqueous solutions is studied using a molecular thermodynamic model. Previous studies based on this technique have predicted monotonic behavior for ionic surfactants. Our investigation shows that the choice of tail transfer energy to describe the hydrophobic effect between the surfactant tails and the polar solvent molecules plays a key role in the predicted CMC. We modify the tail transfer energy by taking into account the effect of the surfactant head on the neighboring methylene group. The modification improves the description of the CMC and the predicted micellar size for aqueous solutions of sodium n-alkyl sulfate, dodecyl trimethylammonium bromide (DTAB), and n-alkyl polyoxyethylene. The new tail transfer energy describes the nonmonotonic behavior of CMC versus temperature. In the DTAB–water system, we redefine the head size by including the methylene group, next to the nitrogen, in the head. The change in the head size along with our modified tail transfer energy improves the CMC and aggregation size prediction significantly. Tail transfer is a dominant energy contribution in micellar and microemulsion systems. It also promotes the adsorption of surfactants at fluid–fluid interfaces and affects the formation of adsorbed layer at fluid–solid interfaces. Our proposed modifications have direct applications in the thermodynamic modeling of the effect of temperature on molecular aggregation, both in the bulk and at the interfaces.

Low-salinity waterflooding is a relatively new method for improved oil recovery that has generated much interest. It is generally believed that low-salinity brine alters the wettability of oil reservoir rocks towards a wetting state that is optimal for recovery. The mechanism(s) by which the wettability alteration occurs is currently an unsettled issue. This paper reviews recent studies on wettability alteration mechanisms that affect the interactions between the brine/oil and brine/rock interfaces of thin brine films that wet the surface of reservoir rocks. Of these mechanisms, we pay particular attention to double-layer expansion, which is closely tied to an increase in the thickness and stability of the thin brine films. Our review examines studies on both sandstones and carbonate rocks. We conclude that the thin-brine-film mechanisms provide a good qualitative, though incomplete, picture of this very complicated problem. We give suggestions for future studies that may help provide a more quantitative and complete understanding of low-salinity waterflooding.

Risk management of gas hydrates is a major challenge in offshore hydrocarbon production. Use of anti-agglomerants (AAs) is an attractive option because of effectiveness at low dosage and high subcooling. The literature suggests that anti-agglomeration requires formation of water-in-oil emulsion. Our recent work has demonstrated that the process can occur without emulsion or through oil-in-water emulsion. We have shown anti-agglomeration in oil-free systems in methane hydrates and natural gas hydrates. In this work, through particle size measurements in an autoclave setup in both freshwater and brine, light is shed on the effectiveness of our chemical formulation. Hydrate particle sizes are determined by the focus beam reflectance measurement (FBRM). The results show that our formulation reduces hydrate particle size significantly and eliminates large particles. The AA formulation is a mix of three chemicals: surfactant, base, and oil (e.g., n-octane). n-Octane helps with even distribution of the surfactant in the solution. The base helps with elimination of small amounts of hydrogen ions in the aqueous solution in conditions when acid gas species are present in the natural gas. These two additives increase the effectiveness of the surfactant for anti-agglomeration. Hydrate particle size measurements show that small amounts of n-octane reduce particle sizes by a factor of 2. Our measurements reinforce the idea of effective anti-agglomeration to be the most feasible approach in hydrate flow assurance, with superiority over other alternatives. The formulation has many features, including viscosity reduction of slurry.

We use molecular dynamics simulations and molecular thermodynamics to investigate the formation of reverse micelles in a system of surfactants and nonpolar solvents. Since the early observation of reverse micelles, the question has been whether the existence of polar solvent molecules such as water is the driving force for the formation of reverse micelles in nonpolar solvents. In this work, we use a simple coarse-grained model of surfactants and solvents to show that a small number of polar solvent molecules triggers the formation of large permanent aggregates. In the absence of polar molecules, both the thermodynamic model and molecular simulations show that small aggregates are more populated in the solution and larger ones are less frequent as the system evolves over time. The size and shape of reverse micelles depend on the size of the polar core: the shape is spherical for a large core and ellipsoidal for a smaller one. Using the coarse-grained model, we also investigate the effect of temperature and surfactant tail length. Our results reveal that the number of surfactant molecules in the micelle decreases as the temperature increases, but the average diameter does not change because the size of the polar core remains invariant. A reverse micelle with small polar core attracts fewer surfactants when the tail is long. The uptake of solvent particles by a micelle of longer surfactant tail is less than shorter ones when the polar solvent particles are initially distributed randomly.

Clathrate hydrates are crystalline structures composed of small guest molecules trapped into cages formed by hydrogen-bonded water molecules. In hydrate nucleation, water and the guest molecules may stay in a metastable fluid mixture for a long period. Metastability is broken if the concentration of the guest is above a certain limit. Here we study propane hydrates by means of molecular dynamics simulations. First we simulate three-phase equilibrium of water, propane, and propane hydrates; the simulated melting temperature and solubility of propane in water are agreement with experimental measurements. In the main part we simulate hydrate nucleation in water–propane supersaturated solutions. At moderate temperatures we show that hydrate nucleation can be very fast in a very narrow range of composition, namely, close to the limit of stability. Propane density fluctuations near the fluid–fluid demixing are coupled with crystallization, producing enhanced nucleation rates. This is the first report of propane-hydrate nucleation by molecular dynamics simulations. We observe motifs of the crystalline structure II in line with experiments and new hydrate cages not reported in the literature. Our study relates nucleation to the fluid–fluid spinodal decomposition and demonstration that the enhanced nucleation phenomenon is more general than short-range attractive interactions as suggested in nucleation of proteins.

•We demonstrate gas hydrate powder formation for the first time.•Hydrate volume fraction can be as high as 95% with fluidity features.•The new anti-agglomerant shows kinetic inhibition effect.•We propose a mechanism for the formation of hydrate powders.Gas hydrates may plug hydrocarbon flowlines even at low hydrate volume fraction due to agglomeration. Anti-agglomeration is perhaps the most effective approach for flow assurance. An effective anti-agglomerant (AA) can prevent gas hydrate particles from sticking together by lowering of the water–oil interfacial tension and increase of the contact angle of water on hydrate surface. In a recent work, we have introduced a new AA formulation which is effective; it forms hydrate slurry over a broad range of oil to water ratio. In this study, we introduce a modified chemical formulation effective at extreme conditions when hydrate powders are formed from two different gases. The formation of hydrate powders has not been reported in the literature. The powders flow readily in rocking cells. The hydrate fraction can be as high as 95% with fluidity behavior. The AA effectiveness reported in this study is much higher than the past work. A new anti-agglomeration mechanism is also proposed. The gas hydrate powder formation may have applications not only in flow assurance, but also in energy storage.

•Ionic liquids are used to reduce the viscosity of heavy oil and bitumens.•Viscosity reduction up to 35% is observed using 5 ppm of dodecylpyridinium chloride.•Ionic liquids seem to interact with asphaltenes to decrease their aggregate size.•Decrease in asphaltene aggregate size seems to lower the crude viscosity.•Intermolecular interactions include π–π, aliphatic, acid–base, and charge-transfer.Heavy oils and extra-heavy oils (bitumens) are difficult to produce and transport due to problems associated with the aggregation of asphaltene molecules. Asphaltenes, a primary component of heavy oils and bitumens, affect the viscosity significantly. Traditional methods of viscosity reduction for heavy petroleum fluids include thermal or dilution methods. In this work, we employ an alternative method for viscosity reduction, by using functionalized molecules that could interact with the asphaltenes and change the properties of the crude oil at the molecular level, reducing viscosity. Ionic liquids, having favorable thermophysical properties such as low vapor pressure, are the functionalized molecules tested in this work. Various properties of the ionic liquids such as alkyl tail lengths (C2, C4, C6, C8, C10, and C12), counter-ion charge density (chloride, thiocyanate, and tetrafluoroborate), and type of head group (imidazolium, pyridinium, and thiazolium) are tested with a Mexican heavy oil and Canadian and Venezuelan bitumens. Small amounts of the additives (between 1 and 10 ppm), dissolved in toluene, are used. Viscosity reduction up to 35% is observed for the crude oils, with dodecylpyridinium chloride showing the maximum reduction. Various molecular interactions between the ionic liquids and the asphaltene molecules, such as aromatic, acid–base, and charge-transfer interactions, seem to hinder the asphaltene aggregate formation, which consequently reduces the viscosity. These results set the stage for further research on the viscosity reduction of heavy oil and extra-heavy oils by using functionalized molecules.

We study the micro- and macroscale waterflooding performances of unusual crudes which naturally form tight emulsions (stable after 15 months) upon mixing with water and different brines—including the reservoir brine. These crudes are obtained from a large oil field with stock tank oil viscosities in the range 20–100 cP. The waterflooding tests are conducted at constant injection rates in Berea cores and also in a glass-etched micromodel with and without initial water saturation. With the initial water saturation, the emulsions cause final oil recovery to be significantly lower while the breakthrough is surprisingly suppressed. Pressure data suggests that emulsions are formed in situ in the waterflooding tests both with and without the initial water saturation. The injection pressure data show significant fluctuations after about 3 pore volumes of injection. Both the pressure drop and pressure fluctuations are found to be higher at lower injection rates. Furthermore, the pressure drop is higher in tests with the initial water saturation, which may be related to the formation of water-in-oil (w/o) emulsions during the oil injection into water-saturated cores and subsequent aging. We also observe a pronounced initial pressure spike, which cannot be described by the bulk oil rheology as the oil exhibits only a mild shear thinning behavior. The coreflooding results are qualitatively explained from the viewpoint of deep-bed filtration. The pore-scale waterflooding results reveal the formation of both w/o microemulsions and macroemulsions. We observe the accumulation of w/o emulsions at the oil/water interface and in the dead-end pore spaces. Large emulsion droplets are observed to block a significant portion of a pore, which may be re-entrained and mobilized at higher rates. Overall, the formation of w/o emulsions results in significant production challenges because of high pressure drops, especially for the flow initialization.

Petroleum fluids may form hydrate crystals with water at conditions often encountered in nature. Hydrate formation in large pieces is a serious problem in flow assurance and oil capture from the seabed. Use of functionalized molecules in very small quantities offers effective solution through formation of small hydrate particles. The literature suggests water-in-oil emulsion for hydrate antiagglomeration, which limits the application because of requirement of large amounts of the oil phase. In a recent article, we have demonstrated hydrate antiagglomeration of methane in water and brine by a new surfactant molecule at 0.2 wt % without water-in-oil emulsion. However, in a natural gas containing CO2, the same surfactant loses effectiveness. In this work we offer a revised formulation consisting of the surfactant, small amounts of a base, and an alkane. The base adjusts the pH, and the alkane serves as a defoamer. The effects of each component are systematically discussed in this work, and a synergetic effect is found. The new formulation provides effective antiagglomeration in a broad range of conditions. Moreover, our formulation has three other beneficial effects including kinetic inhibition, reduction of slurry viscosity, and corrosion inhibition.

Methane hydrates are crystalline structures composed of cages of hydrogen-bonded water molecules in which methane molecules are trapped. The nucleation mechanisms of crystallization are not fully resolved, as they cannot be accessed experimentally. For methane hydrates most of the reported simulations on the phenomena capture some of the basic elements of the full structure. In few reports, formation of crystalline structures is reached by imposing very high pressure, or dynamic changes of temperature, or a pre-existing hydrate structure. In a series of nanoscale molecular dynamics simulations of supersaturated water–methane mixtures, we find that the order of the crystalline structure increases by decreasing subcooling. Crystalline structures I and II form and coexist at moderate temperatures. Crystallization initiates from the spontaneous formation of an amorphous cluster wherein structures I, II, and other ordered defects emerge. We observe the transient coexistence of sI and sII in agreement with experiments. Our simulations are carried out at high methane supersaturation. This condition dramatically reduces the nucleation time and allows simulating nucleation at moderate subcooling. Moderate temperatures drive hydrates to more ordered structures.

The hydrate/methane gas interface is studied by molecular dynamics simulations. Below the hydrate melting temperature a thin liquid film forms with an associated surface charge density and electrostatic potential. The thickness of the thin liquid film, the charge density, and electrostatic potential at the hydrate/gas interface are established at different subcooling temperatures for the first time. The hydrate interface has mixed polarity, being predominantly positive. A comparison is made with the ice/methane interface, which reveals similarities and differences in the induced charge density. The thin liquid film and the induced charge density have important implications for the interfacial properties of methane hydrates.

The aggregation and structure of polar molecules in nonpolar media may have a profound effect on bulk phase properties and transport. In this study, we investigate the aggregation and deposition of water and asphaltenes, the most polar fraction in petroleum fluids. In flow-line experiments, we vary the concentration of water from 500 up to 175 000 ppm and provide the evidence for clear changes in asphaltene deposition. Differential interference contrast (DIC) microscopy and dynamic light scattering (DLS) are used to measure the size of the aggregates. Rheological measurements are performed to get fixed ideas on the structural changes that water induces at different concentrations. This study demonstrates the significant effect of water on asphaltene aggregation and deposition and explores the molecular basis of water–asphaltene interaction. Our aggregate size measurements show that while asphaltene molecules increase the solubilization of water, there is no increase in the aggregate size. Our aggregation size measurements are different from the reports in the literature.

The self-assembly of amphiphilic molecules is a key process in numerous biological and chemical systems. When salts are present, the formation and properties of molecular aggregates can be altered dramatically by the specific types of ions in the electrolyte solution. We present a molecular thermodynamic model for the micellization of ionic surfactants that incorporates quantum dispersion forces to account for specific ion effects explicitly through ionic polarizabilities and sizes. We assume that counterions are distributed in the diffuse region according to a modified Poisson–Boltzmann equation and can reach all the way to the micelle surface of charge. Stern layers of steric exclusion or distances of closest approach are not imposed externally; these are accounted for through the counterion radial distribution profiles due to the incorporation of dispersion potentials, resulting in a simple and straightforward treatment. There are no adjustable or fitted parameters in the model, which allows for a priori quantitative prediction of surfactant aggregation behavior based only on the initial composition of the system and the surfactant molecular structure. The theory is validated by accurately predicting the critical micelle concentration (CMC) for the well-studied sodium dodecyl sulfate (SDS) surfactant and its alkaline-counterion derivatives in mono- and divalent salts, as well as the molecular structure parameters of SDS micelles such as aggregation numbers and micelle surface potential.

•We suggest a new surfactant for gas hydrate anti-agglomeration applications.•New surfactant is effective at a very low concentration over the entire watercut range.•New surfactant also shows high effectiveness at various cooling rates and in brine systems.•We propose a new mechanism of anti-agglomeration in hydrate particles.Anti-agglomeration is a promising solution for gas hydrate risks in deepsea hydrocarbon flowlines and oil leak captures. Currently ineffectiveness at high water to oil ratios limits such applications. We present experimental results of a new surfactant in rocking cell tests, which show high efficiency at a full range of water to oil ratios; there is no need for presence of the oil phase. We find that our surfactant at a very low concentration (0.2 wt.% of water) keeps the hydrate particles in anti-agglomeration state. We propose a mechanism different from the established water-in-oil emulsion theory in the literature that the process is effective without the oil phase. There is no need to emulsify the water phase in the oil phase for hydrate anti-agglomeration; with oil-in-water emulsion and without emulsion hydrate anti-agglomeration is presented in our research. We expect our work to pave the way for broad applications in offshore natural gas production and seabed oil capture with very small quantities of an eco-friendly surfactant.Graphical abstract

The conjugated π-bonding in asphaltenes, a naturally occurring member of the polyaromatic hydrocarbon family, provides a unique platform for investigating electrostatics and electronics in non-polar systems, but at the same time causes asphaltenes to be insoluble in all except aromatic liquids. Asphaltenes precipitate from petroleum fluids under a variety of conditions, including depressurization and compositional changes, plaguing both recovery operations and remediation in the case of equipment failure. Aromatic solvents like toluene dissolve asphaltenes, but only at very high concentrations, nearly 50% by weight. Polymeric dispersants can stabilize asphaltene colloids, and in some cases can inhibit asphaltene precipitation entirely. Strong organic acids such as dodecyl benzene sulfonic acid (DBSA) can dissolve precipitated asphaltenes when introduced in concentrations as little as 1 percent by weight. Here we demonstrate for the first time that DBSA enables a reversible transition from unstable to stable colloidal-scale asphaltene suspensions to molecularly stable solutions. A continuum of acid–base reactions explains the apparent dual-action of DBSA. The suspension–solution transition occurs through the protonation of heteroatomic asphaltene components and subsequent strong ion pairing with DBSA sulfonate ions, effectively forming DBSA-doped asphaltene complexes with a solvation shell.

Electrostatic stabilization has recently been found to be an important factor in non-polar colloidal asphaltene suspensions. However, the nature of charging in asphaltene systems may be quite different than in other non-polar colloid systems. For instance, the origin of charging in asphaltene colloids arises from both positive and negative charges native to the asphaltenes. In part due to this bimodality of surface charge, some dispersants are shown to stabilize asphaltene colloids at concentrations below their cmc. This effect does not arise from ionic effects of the dispersant, but rather from preferential dispersant adsorption onto charged sites on the colloidal asphaltene surface. Due to the long-range nature of electrostatics in non-polar systems, electrophoretic mobility can depend on both electric-field and particle volume fraction. We investigate the field- and concentration- dependence of electrophoretic mobility in non-polar colloidal asphaltene suspensions. Our results suggest that colloidal asphaltene suspensions stabilized by non-ionic dispersants can exhibit large screening lengths even in the presence of dispersant micelles. Due in part to the large screening length, a decrease in electrophoretic mobility can occur even at low colloidal particle concentrations.

Hydrates are crystalline inclusion compounds where hydrogen bonded water molecules form cages to trap small hydrocarbon and nonhydrocarbon molecules. Under high subcooling conditions, these crystals grow rapidly into large pieces and may cause enormous problems in transport and deepwater oil capture. One of the most effective methods to address gas hydrate problems is through the formation of small hydrate particles in the nanometer or micrometer range dispersed in the fluid phase. In this approach, special surfactants are required, which are called antiagglomerants (AAs). However, there are major limitations when salt is present in water and when volume ratio of water in fluid (i.e., watercut) is high. In this work, we investigate a wide range of alcohols as cosurfactants along with the rhamnolipid as AA in a multiple screening-tube rocking apparatus by monitoring the temperature of vials and morphology of mixtures. The results show medium-sized alcohols, such as isopropanol (IPA), are effective cosurfactants. Small quantities of IPA reduce the effective dosage of surfactant in the formation of hydrate particles in both water and brines. Our emulsion size measurements, by dynamic light scattering, and interfacial tension measurements reveal the effectiveness of alcohol cosurfactants in stabilizing oil-in-water emulsions, therefore enhancing the hydrate antiagglomeration effect.

We derive a criterion for phase stability under constant temperature, moles, and volume using the Helmholtz free energy. Using the volume-based formulation, we develop a numerical algorithm to investigate single-phase stability based on the Newton method. We demonstrate robustness and efficiency of the new method in a number of examples in single-phase stability testing.Highlights► We derive a criterion for phase stability at constant temperature, moles and volume. ► A numerical algorithm to investigate phase stability at constant volume is proposed. ► Several examples of single-phase constant-volume stability testing are presented.

Microemulsions are nanoheterogeneous, thermodynamically stable, spontaneously forming mixtures of oil and water by means of surfactants, with or without cosurfactants. The pledge to use small volumes of amphiphile molecules compared to large amounts of bulk phase modifiers in a variety of chemical and industrial processes, from enhanced oil recovery to biotechnology, fosters continuous investigation and an improved understanding of these systems. In this work, we develop a molecular thermodynamic theory for droplet-type microemulsions, both water-in-oil and oil-in-water, and provide the theoretical formulation for three-component microemulsions. Our thermodynamic model, which is based on a direct minimization of the Gibbs free energy of the total system, predicts the structural and compositional features of microemulsions. The predictions are compared with experimental data for droplet size in water–alkane–didodecyl dimethylammonium bromide systems.

The destabilization of asphaltenes adversely affects many aspects of the petroleum energy industry. Although polymeric dispersants have been shown to stabilize asphaltene colloids in non-polar media, the mechanism by which they prevent aggregation is not well-understood. We use a variety of techniques to investigate systems of colloidal asphaltenes stabilized in heptane by an effective dispersant. Phase analysis light scattering (PALS) measurements reveal an increase in the electrophoretic mobility as a function of dispersant concentration, suggesting electrostatic repulsion as the primary stabilizing force. Dynamic light scattering (DLS) measurements indicate that the increase in mobility corresponds to a decrease in particle size. A simple scaling argument suggests that the dispersant adsorbs to the surface of the asphaltene colloids. UV-visible spectroscopy and static light scattering (SLS) measurements corroborate this proposal. Interestingly, the colloidal asphaltene properties change below the critical micelle concentration (cmc) of the dispersants used. The nature of the asphaltenes themselves plays an important role in allowing for this tunability of their properties. Contrary to currently accepted views of non-polar colloidal suspensions, our results indicate that isolated dispersant molecules, not inverse micelles, can lead to charge-stabilization of asphaltene colloids.

The alteration of the wettability from liquid-wetting to intermediate gas-wetting has great potential in improving gas well productivity, from mitigating water blocking to condensate banking in gas reservoirs. Even a small quantity of salt ions (such as Na+) in the initial saturation in rock has a detrimental effect on the alteration of the wettability by chemical treatments. The initial salt ions may cause clay release and permeability reduction. Berea cores are usually used in laboratory flow studies, including wettability alterations. In this work, we present a comprehensive study on the use of Berea, both unfired and fired, in single- and two-phase flows, with a focus on the salt and firing effect on the chemical treatment. Three fluoropolymeric surfactants are used. We find that one of the three, a nonionic surfactant, is effective in the alteration of wettability in the fired Berea (with and without salt in the initial saturation). The treatment efficiency of ionic surfactants is reduced in the presence of the initial salt.

Hydrate formation in subsea pipelines is a serious problem in gas and oil production for offshore fields. Current methods are mainly based on thermodynamic inhibitors to change bulk phase properties. Thermodynamic inhibitors, such as methanol, are very effective, but large quantities, sometimes as high as a 1:1 volume of alcohol/water, are required. Kinetic inhibitors generally in a 0.005−0.02 volume ratio of surfactant/water can either inhibit hydrate formation or reduce the rate of growth. In the sea bed, the subcooling for hydrates is around 20−25 °C because of the sea bed temperature of about 4 °C. The kinetic inhibitors are not effective at such a high subcooling. An effective method is the use of anti-agglomerants, which allow for hydrate formation in the form of small particles and prevent agglomeration of such particles. Rhamnolipid biosurfactant and methanol are used recently to demonstrate anti-agglomeration in tetrahydrofuran (THF) hydrates. In this work, we present data for cyclopentane hydrates to demonstrate that a mixture of rhamnolipid and methanol is the ideal combination for effective anti-agglomeration. The formation of cyclopentane hydrates is believed to be closely analogous to methane hydrate formation because of the low solubility of cyclopentanes in water and various aspects of crytallization.

Specific ion effects are ubiquitous in biological and colloidal systems. The addition of electrolytes to ionic surfactant solutions has pronounced effects on micellar properties, such as critical micelle concentration (cmc), micellar size, and shape. Ions play an important role in colloid stability and aggregation behavior of ionic surfactant solutions. Despite extensive experimental data, there is no well established molecular theory on specific ion effects. Published molecular thermodynamic theories for ionic surfactants do not properly account for ion-specific effects such as the inversion of the lyotropic series for the cmc of alkyl sulfates and carboxylates. In this work, we present a molecular thermodynamic theory for ionic surfactant solutions to take into account the headgroup−counterion specificity and address ion-specific effects on the cmc and aggregation number. We assume that the charged headgroup and the counterion at the Stern layer form solvent-shared ion pair with different degrees of cosphere overlap. The thickness of the Stern layer is estimated from molecular structures of hydrated surfactant heads and hydrated counterions, and from the knowledge of the qualitative strength of headgroup−counterion interaction in line with Collins’ concept of matching water affinities. Our proposed thermodynamic model properly predicts the cmc of both anionic and cationic surfactants of various counterions, and the effect of different inorganic salts on micellization of ionic surfactants.

Asphaltenes, among the heaviest components of crude oil, can become unstable under a variety of conditions and precipitate and sediment out of solution. In this report, we present sedimentation measurements for a system of colloidal scale asphaltene particles suspended in heptane. Adding dispersants to the suspension can improve the stability of the system and can mediate the transition from a power-law collapse in the sedimentation front to a rising front. Additional dispersant beyond a crossover concentration can cause a significant delay in the dynamics. Dynamic light scattering measurements suggest that the stabilization provided by the dispersants may occur through a reduction of both the size and polydispersity of the asphaltene particles in suspension.

When oil is mixed with light alkanes, asphaltenes can precipitate out of oil solutions in a multistep process that involves the formation of nano and colloidal scale particles, the aggregation of asphaltene colloids, and their eventual sedimentation. Amphiphilic dispersants can greatly affect this process. The mechanism of the dispersant action in colloidal asphaltene suspensions in heptane has been shown through previous work to be due in part to a reduction in the size of the colloidal asphaltene particles with the addition of dispersant. However, previous studies of the sedimentation behavior revealed evidence of aggregation processes in the colloidal asphaltenes in heptane that has yet to be investigated fully. We investigate the effect of dispersants on this aggregation behavior through the use of dynamic light scattering, showing that both the amount of dispersant and the amount of heptane dilution can slow the onset of aggregation in colloidal asphaltene suspensions. An effective dispersant acts by suppressing colloidal aggregation in asphaltene suspensions, as shown by light scattering, and therefore also slows separation from the bulk, as revealed through macroscopic sedimentation experiments.

Natural gas production poses a risk of flow-line hydrate blockage from coproduced water and hydrate-forming species. Our previous studies have focused on gaining further understanding of hydrate antiagglomerants through systematic experimentation as well as testing of a new biosurfactant. Despite great potential, work on hydrate antiagglomeration is still very limited. This work centers on the effect of NaCl and MgCl2 in mixtures of two vastly different antiagglomerants. We use a model oil, water, and tetrahydrofuran as hydrate-forming species. Results show that both salts—added in sufficient quantities—may result in the agglomeration of hydrates. Our results reveal a nonmonotonic agglomeration behavior at low salt and/or large surfactant concentrations. Specifically, dissolved MgCl2 results in agglomeration more than the dissolved NaCl. Our measurements also show that the quaternary ammonium salt—i.e., quat—is more sensitive to dissolved salt than the nonionic rhamnolipid biosurfactant. In this work we show that the rhamnolipid biosurfactant is effective to a low concentration of 0.05 wt %, yet quat has effectiveness down to 0.01 wt %. The biosurfactant—with less toxicity and higher biodegradability—is an attractive alternative to chemical surfactants in antiagglomeration. Results on the model systems show the promise for testing in real fluid systems and field testing of the ideas.

The effect of adding an alcohol to surfactant systems depends much on the alcohol chain length. Investigations on the effect of alcohols in micellar systems point out that medium-chain alcohols are appreciably incorporated in the micellar phase whereas short-chain alcohols are localized mainly in the aqueous phase. Nonetheless, penetration of the hydrocarbon chain of alcohols in the micellar shell has been experimentally observed for the entire homologous series of linear 1-alcohols. We present a thermodynamic model in which the alcohol molecules play two roles: cosurfactant and cosolvent. The cosurfactant effect of the alcohols is included by assuming that the alcohol molecules are nonionic surfactants. The cosolvent effect is modeled by accounting for the changes in the free energy to relocate the surfactant tail from the solvent to the aggregate core. The effects of short-chain alcohols in the macroscopic interfacial tension and dielectric constant of the solvent medium are also taken into account. For short-chain alcohols the partition coefficient of the alcohols between water and liquid hydrocarbons provides knowledge of the fraction of the molecules that participate in each function. Our proposed thermodynamic model improves the modeling of the effect of short- and medium-chain alcohols in self-assembly of molecules that are of increasing importance in modern scientific research and technological processes.

The development of waxy crude oil and some gas condensate fields can lead to serious operational problems because of solidification of the paraffin components of the fluid in flowlines. Many numerical models in the literature predict the thickness of the wax deposit. However, most of these models assume that the wax-oil (gel) deposit has a constant wax content. In this work, we analyze wax deposition in laminar flow regime to predict the thickness and the composition of the gel layer as a function of position and time. The wax-oil gel region is considered as a porous medium. The velocity field and the pressure drop are calculated from the Navier−Stokes equation in the liquid region and from a combined Darcy-type equation and the Navier−Stokes equation in the gel region. The wax amount is estimated as a result of a decrease in fluid temperature below the wax appearance temperature (WAT), counterdiffusion processes from thermal and molecular diffusions, and radial convection which occurs because of nonuniform gel layer thickness. We compare predicted results from our model with several experimental data from the literature. The results which are in agreement with data cannot be predicted by formulations in which chain rule is used to replace concentration gradient with temperature gradient in the molecular diffusion expression.

Because of availability, as well as economical and environmental considerations, natural gas is projected to be the premium fuel of the 21st century. Natural gas production involves risk of the shut down of onshore and offshore operations because of blockage from hydrates formed from coproduced water and hydrate-forming species in natural gas. Industry practice has been usage of thermodynamic inhibitors such as alcohols often in significant amounts, which have undesirable environmental and safety impacts. Thermodynamic inhibitors affect bulk-phase properties and inhibit hydrate formation. An alternative is changing surface properties through usage of polymers and surfactants, effective at 0.5 to 3 weight % of coproduced water. One group of low dosage hydrate inhibitors (LDHI) are kinetic inhibitors, which affect nucleation rate and growth. A second group of LDHI are antiagglomerants, which prevent agglomeration of small hydrate crystallites. Despite great potential, work on hydrate antiagglomeration is very limited. This work centers on the effect of small amounts of alcohol cosurfactant in mixtures of two vastly different antiagglomerants. We use a model oil, water, and tetrahydrofuran as a hydrate-forming species. Results show that alcohol cosurfactants may help with antiagglomeration when traditional antiagglomerants alone are ineffective. Specifically, as low as 0.5 wt. % methanol cosurfactant used in this study is shown to be effective in antiagglomeration. Without the cosurfactant there will be agglomeration independent of the AA concentration. To our knowledge, this is the first report of alcohol cosurfactants in hydrate antiagglomerants. It is also shown that a rhamnolipid biosurfactant is effective down to only 0.5 wt. % in such mixtures, yet a quaternary ammonium chloride salt, i. e., quat, results in hydrate slurries down to 0.01 wt. %. However, biochemical surfactants are less toxic and biodegradable, and thus their use may prove beneficial even if at concentrations higher than chemical surfactants.

New thermal diffusion coefficients of binary mixtures are measured for n-decane−n-alkanes and 1-methylnaphthalene−n-alkanes with 25 and 75 wt % at 25 °C and 1 atm using the thermogravitational column technique. The alkanes range from n-pentane to n-eicosane. The new results confirm the recently observed nonmonotonic behavior of thermal diffusion coefficients with molecular weight for binary mixtures of n-decane−n-alkanes at the compositions studied. In this work, the mobility and disparity effects on thermal diffusion coefficients are quantified for binary mixtures. We also show for the binary mixtures studied that the thermal diffusion coefficients and mixture viscosity, both nonequilibrium properties, are closely related.

Compositional simulation is an important tool in for evaluation of oil recovery and carbon sequestration. Several compositional models have been proposed in the past that are based on finite-difference, finite-volume or finiteelement methods. These methods are typically of low order of approximation and suffer excessive numerical diffusion. These deficiencies can be significantly suppressed using the high resolution methods like mixed-hybrid and discontinuous Galerkin finite element methods. We have shown recently that these methods are much more sensitive to problem formulation than the conventional first-order methods. In this work we discuss several problems connected with application of high resolution schemes. These problems include formulation of boundary conditions, proper evaluation of phase fluxes, and formulation of the slope limiter in the discontinuous Galerkin method. The latter problem is common to all high resolution methods. We will present new examples of compositional simulations showing the advantages of our approach over the traditional first-order finite-volume schemes in single-phase and two-phase.

Numerical simulation of two-phase multicomponent flow in permeable media with species transfer between the phases often requires use of higher-order methods. Unlike first-order methods, higher-order methods may be very sensitive to problem formulation. The sensitivity to problem formulation and lack of recognition have hindered the widespread use of higher-order methods in various problems including improved oil recovery and sequestration from CO2 injection. In this work, we offer proper formulation of species balance equations and boundary conditions which overcome problems of formulations used previously that were detrimental to the efficiency of higher-order methods. We also present proper approximation of phase fluxes in the mixed finite element method. Our proposals remove major deficiencies in using higher-order methods in two-phase multicomponent flow. Numerical examples are presented to demonstrate robustness and efficiency of our approach.

Numerical simulation of multiphase compositional flow in fractured porous media, when all the species can transfer between the phases, is a real challenge. Despite the broad applications in hydrocarbon reservoir engineering and hydrology, a compositional numerical simulator for three-phase flow in fractured media has not appeared in the literature, to the best of our knowledge. In this work, we present a three-phase fully compositional simulator for fractured media, based on higher-order finite element methods. To achieve computational efficiency, we invoke the cross-flow equilibrium (CFE) concept between discrete fractures and a small neighborhood in the matrix blocks. We adopt the mixed hybrid finite element (MHFE) method to approximate convective Darcy fluxes and the pressure equation. This approach is the most natural choice for flow in fractured media. The mass balance equations are discretized by the discontinuous Galerkin (DG) method, which is perhaps the most efficient approach to capture physical discontinuities in phase properties at the matrix-fracture interfaces and at phase boundaries. In this work, we account for gravity and Fickian diffusion. The modeling of capillary effects is discussed in a separate paper. We present the mathematical framework, using the implicit-pressure-explicit-composition (IMPEC) scheme, which facilitates rigorous thermodynamic stability analyses and the computation of phase behavior effects to account for transfer of species between the phases. A deceptively simple CFL condition is implemented to improve numerical stability and accuracy. We provide six numerical examples at both small and larger scales and in two and three dimensions, to demonstrate powerful features of the formulation.

CO2 injection has been used to improve oil recovery for the last 4 decades. In recent years, CO2 injection has become more attractive because of the dual effect: injection in the subsurface (1) allows for reduction of the CO2 concentration in the atmosphere to reduce global warming and (2) improves the oil recovery. One of the screening criteria for CO2 injection as an enhanced oil recovery method is based on the measurement of CO2 minimum miscibility pressure (MMP) in a slim tube. The slim tube data are used for the purpose of field evaluation and for the tuning of the equations of state. The slim tube represents one-dimensional (1D) horizontal flow. When CO2 dissolves in the oil, the density may increase. The effect of the density increase in high-permeability reservoirs when CO2 is injected from the top has not been modeled in the past. The increase in density changes the flow path from 1D to two-dimensional (2D) and three-dimensional (3D) (downward flow). As a result of this density effect, the compositional path in a reservoir can be radically different from the flow path in a slim tube. In this work, we study the density effect from CO2 dissolution in modeling of CO2 injection. We account for the increase in oil density with CO2 dissolution using the Peng–Robinson equation of state. The viscosity is modeled based on the Pedersen–Fredenslund viscosity correlation. We perform compositional simulation of CO2 injection in a 2D vertical cross-section with the density effect. Our results show that the density increase from CO2 dissolution may have a drastic effect on the CO2 flow path and recovery performance. One conclusion from this work is that there is a need to have accurate density data for CO2/oil mixtures at different CO2 concentrations to model properly CO2 injection studies. Our main conclusion is that the downward flow of the CO2 and oil mixture may not be gravity-stable, despite the widespread assumption in the literature.

While aromatic chemicals are applied to petroleum oil systems to thermodynamically prevent asphaltene precipitation, amphiphilic dispersants can truncate the precipitation process and create stable suspensions of asphaltene colloids in the submicrometer size range. Bulk sedimentation and dynamic light scattering have shown that stabilizing dispersants inhibit colloidal asphaltene aggregation at approximately the same concentration as is needed to effectively slow bulk sedimentation. At the same time, these same types of dispersants can alter the electrostatic properties of colloidal asphaltenes in nonpolar suspensions. While electrostatic stabilization has been linked to aggregation dynamics in several types of colloidal systems, both aqueous and nonpolar, the complete linkage between electrostatic interactions and aggregation inhibition has yet to be shown in colloidal asphaltene suspensions. In this work, we present dynamic light scattering and electrophoresis measurements in colloidal asphaltene suspensions, using three different petroleum fluids and a dispersant which truncates asphaltene precipitation and colloidal aggregation by enabling uniform electrostatic charging at the colloidal asphaltene surface.