Oil-brine Interface Research Articles

Brine-Oil Interfacial Tension Modeling: Assessment of Machine Learning Techniques Combined with Molecular Dynamics.

The physical chemistry mechanisms behind the oil-brine interface phenomena are not yet fully clarified. The knowledge of the relation between brine composition and concentration for a given oil may lead to the ionic tuning of the injected solution on geochemical and enhanced oil recovery processes. Thus, it is worth examining the parameters influencing the interfacial properties. In this context, we have combined machine learning (ML) techniques with classical molecular dynamics simulations (MD) to predict oil/brine interfacial tensions (IFT) effectively and compared this process to a linear regression (LR) method. To diversify our data set, we have introduced a new atomistic crude oil model (medium) with 36 different types of hydrocarbon molecules. The MD simulations were performed for mono- and multicomponent (toluene, heptane, Heptol, light, and medium) oil systems interfaced with sulfate and chloride brines with varying cations (Na+, K+, Ca2+, and Mg2+) and salinity concentration. Thus, a consistent IFT data set was built for the ML training and LR fitting at room temperature and pressure conditions, over the feature space considering oil density, oil composition, salinity, and ionic concentrations. On the basis of gradient boosted (GB) algorithms, we have observed that the dominant quantities affecting the IFT are related to the oil attributes and the salinity concentration, and no specific ion dominates the IFT changes. When the obtained LR model was validated against MD and experimental data from the literature, the error varied up to 2% and 9%, respectively, showing a robust and consistent transferability. The combination of MD simulations and ML techniques may provide a fast and cost-effective IFT determination over multiple and complex fluid-fluid and fluid-solid interfaces.

Effects of salts and silica nanoparticles on oil-brine interfacial properties under hydrocarbon reservoir conditions: A molecular dynamics simulation study

Abstract Nanoparticles (NPs) have been extensively studied for enhanced oil recovery (EOR), in which the oil/brine/NPs interfacial properties play a critical role. However, the effects of NPs on oil-brine interfacial tension (IFT) have been much of debate from both experiment and simulation perspectives. In addition, the knowledge about salinity effects in oil/brine/NPs systems is still very limited. In this work, we use molecular dynamics (MD) simulations to study the effects of NPs (hydrophilic, hydrophobic, and Janus NPs, respectively) and salt concentration (NaCl and CaCl2) up to ~11 wt% on the oil-brine IFT and other interfacial properties under typical oil reservoir conditions. We find that NPs are adsorbed at the oil-brine interface, while salt ions are depleted from the interface. Ca2+ exhibits accumulations adjacent to the NP surfaces and the oil-brine interfaces before depletion, which is not observed in the cases containing Na+. All three NPs make water less ordered at the interfaces, but have negligible effects on oil-brine IFT. Divalent ions have a more pronounced layering structure than monovalent ions. While oil-brine IFT increases as the salinity increases, the three-phase contact angle is independent upon the salinity and cation types.

Zeta potential in intact carbonates at reservoir conditions and its impact on oil recovery during controlled salinity waterflooding

It is well known that oil recovery from carbonate reservoirs can be increased by modifying the injected brine composition in a process ‘controlled salinity water-flooding’ (CSW). However, the mineral- to pore- scale processes responsible for improved oil recovery (IOR) during CSW remain ambiguous and there is no method to predict the optimum CSW composition for a given crude-oil-brine rock system. Here we report the first integrated experimental measurements of zeta potential and IOR during CSW obtained at reservoir conditions. The zeta potential is a measure of the electrical potential at mineral-brine and oil-brine interfaces and controls the electrostatic forces acting between these interfaces.We find that the measured zeta potential in clean samples saturated with formation brine is typically positive and becomes more negative with brine dilution irrespective of temperature. After aging and wettability alteration, the zeta potential changes and we suggest a more positive zeta potential indicates a positive zeta potential at the oil-brine interface and vice-versa. Injecting low salinity brine yields IOR when the oil-brine zeta potential is identified to be negative, but no response when it is identified to be positive, consistent with the hypothesis that IOR during CSW is caused by an increase in the repulsive electrostatic force acting between mineral-brine and oil-brine interfaces. We suggest that the optimum brine composition for IOR during CSW should be chosen to yield the largest change in zeta potential at the mineral-brine interface with opposing polarity to the oil-brine interface and can be determined using the experimental method reported here.

Effect of dissolution, evaporation, and photooxidation on crude oil chemical composition, dielectric properties and its radar signature in the Arctic environment.

Accidental release of petroleum in the Arctic is of growing concern owing to increases in ship traffic and possible future oil exploration. A crude oil-in-sea ice mesocosm experiment was conducted to identify oil-partitioning trends in sea ice and determine the effect of weathering on crude oil permittivity. The dissolution of the lighter fractions increased with decreasing bulk oil-concentration because of greater oil-brine interface area. Movement of the oil towards the ice surface predominated over dissolution process when oil concentrations exceeded 1 mg/mL. Evaporation decreased oil permittivity due to losses of low molecular weight alkanes and increased asphaltene-resin interactions. Photooxidation increased the permittivity of the crude oil due to the transformation of branched aromatics to esters and ketones. Overall, the weathering processes influenced crude oil permittivity by up to 15%, which may produce sufficient quantifiable differences in the measured normalized radar cross-section of the ice.

Water versus Asphaltenes; Liquid\u2013Liquid and Solid\u2013Liquid Molecular Interactions Unravel the Mechanisms behind an Improved Oil Recovery Methodology

Understanding of possible molecular interactions at liquid-liquid and solid-liquid interfaces can shed lights onto the nature’s design and authorise fine manipulation aptitude in biological, manufacturing, microfluidic and oil recovery applications. Of particular interest is the capability to control the aggregation of organic and biological macromolecules, which typically poses significant challenges for oil industry and human life, respectively. Following asphaltene aggregation phenomenon through π-stacking and hydrogen bonding interactions, asphaltene aggregates can form a thin layer at the crude oil-brine interface through noncovalent interactions such as -O-H···O hydrogen bonds and/or alter the wettability state of the solid surface from initially water-wet into mixed-oil wetting. Here, we probe the impact of water with variety of salinities and ion types on formation of water in oil micro-emulsions, asphaltene deposition, and induced water wettability transition at micro scale. For the first time we investigate the influence of water in oil micro-emulsions on asphaltene aggregation and deposition phenomena at elevated pressure and temperature conditions. We also monitor the micro-wettability alterations of gold surface of the QCM owing to ion valency/concentration changes using state of the art ESEM imaging facility. Our results depict that owing to the substitution of divalent cations with monovalent ones, asphaltene deposition is repelled and the solid surface becomes more hydrophilic, proposing a generalizable strategy to control wettability and an elucidation for the profitability of so-called low salinity water flooding, an enhanced oil recovery methodology. For the biological applications, this study provides insights into the potential roles of ions and hydrogen bonds in the protein deposition in tissues and self-assembly interactions and efficiency of drugs against protein aggregation drivers.

A Synergy between Controlled Salinity Brine and Biosurfactant Flooding for Improved Oil Recovery: An Experimental Investigation Based on Zeta Potential and Interfacial Tension Measurements

In this study, we have investigated the effects of brine and biosurfactant compositions on crude-oil-rock-brine interactions, interfacial tension, zeta potential, and oil recovery. The results of this study show that reduced brine salinity does not cause significant change in IFT. However, addition of biosurfactants to both high and low salinity brines resulted in IFT reduction. Also, experimental results suggest that the zeta potential of high salinity formation brine-rock interface is positive, but oil-brine interface was found to be negatively charged for all solutions used in the study. When controlled salinity brine (CSB) with low salinity and CSB with biosurfactants were injected, both the oil-brine and rock-brine interfaces become negatively charged resulting in increased water-wetness and, hence, improved oil recovery. Addition of biosurfactants to CSB further increased electric double layer expansion which invariably resulted in increased electrostatic repulsion between rock-brine and oil-brine interfaces, but the corresponding incremental oil recovery was small compared with injection of low salinity brine alone. Moreover, we found that the effective zeta potential of crude oil-brine-rock systems is correlated with IFT. The results of this study are relevant to enhanced oil recovery in which controlled salinity waterflooding can be combined with injection of biosurfactants to improve oil recovery.

An overview of the oil-brine interfacial behavior and a new surface complexation model

The few existing surface complexation models (SCM) for the brine-oil interface have important limitations: the chemistry of each crude oil is not considered, they cannot capture the water/non-polar hydrocarbons surface charge, the interactions between Na+ and the acid sites are not included, and the equilibrium constants for the adsorption reactions are not validated against experimental data. We address the aforementioned constraints by proposing an improved diffuse-layer SCM for the oil-brine interface. The new model accounts for the chemistry of crude oils by considering surface sites linearly dependent on the TAN (total acid number) and TBN (total base number). We define weak sites to account for the negative surface charge observed for non-polar hydrocarbons in water. We optimize the parameters of our model by fitting the model to reported zeta potential measurements of oil in aqueous solutions. When we validate the optimized model against different experimental data sets, it generally shows a good performance in predicting the surface charge of oil in different brines with different pHs. We show that the acid and base numbers are only useful as a qualitative estimation of the distribution of polar groups at the oil surface, and more sophisticated analysis is necessary to quantify the chemistry of the oil-brine interface.

Microfluidic investigations of crude oil-brine interface elasticity modifications via brine chemistry to enhance oil recovery

Waterflooding has been widely adopted as an improved oil recovery technique since water is, in general, inexpensive and readily available. More recently, low salinity waterflooding (LSW) has been applied to oil production. LSW has successfully demonstrated higher recovery efficiencies than conventional water flooding, yet the underlying mechanism is still quite unclear. Extensive research has focused upon rock-fluid interactions under low salinity conditions, however very little work has considered interactions between oil and brine and how fluid-fluid interfacial properties are influenced by brine salinity and composition. To fill this gap, we have developed a microfluidic device for multiphase interfacial testing with length scales comparable to the pore scale of oil reservoir rocks. Unlike conventional core flooding tests, fluid-fluid phenomena can be easily visualized within microfluidic devices via optical microscopy. Oil snap-off, a phenomenon that represents a major dispersion mechanism, occurs when crude oil flows through porous media in the reservoir and induces trapping hysteresis, can be investigated within a well-controlled microfluidic flow-focusing geometry. The size of formed droplets is examined as a measure of the resistance to snap-off. It has been previously demonstrated that snap-off events are influenced by brine chemistry, oil composition, and the interaction time between crude oil and brine. Here, we show that asphaltenes in the oil phase contribute directly to the development of the elasticitic film. We also propose the reduction of interfacial elasticity by other polar components, such as naphthenic acids, which counteract asphaltene behavior over different time scales. The contribution of these effects on interfacial elasticity is shown to be mediated by both the composition and concentration of brine and oil.

Interfacial rheological insights of sulfate-enriched smart-water at low and high-salinity in carbonates

Lowering the injection water salinity or modifying its chemistry can improve waterflooding displacement efficiency. This water modification has been frequently alluded to increase rock water-wetness. However, the presence of sulfate anions in the aqueous phase is shown here to also alter the crude oil–water interfacial rheology drastically, in ways similar to that associated to the reduction of water salinity. Under the right conditions, oil recovery could, in principle, be increased to a considerably degree by alteration of fluid–fluid interactions at high salinity. The purpose of this research is to contrast oil recovery behavior in cases when smart-water is designed based on either increasing the sulfate anion concentration in a high-salinity brine or by decreasing salinity considerably, when using seawater as the base aqueous phase. Interfacial rheological and coreflooding results are compared to the case of seawater injection. The effect of various ions on the interfacial shear rheological response of several crude oils and modified seawater were examined. Carefully designed corefloods using Indiana Limestone were run to evaluate the effect of each brine on recovery behavior. Mild temperature and short ageing time were imposed to hinder wettability alteration. Interfacial rheological results show that the visco-elasticity of the crude oil-brine interface is higher for a low-salinity brine compared to the higher-salinity counterpart represented by seawater. However, when the sulfate anion concentration is increased, the interfacial visco-elasticity increases noticeably. Coreflooding results show that brines leading to more a visco-elastic interface, including low salinity and sulfated seawater, yield higher oil recovery factor. Ion analysis of the effluent brine shows that for the model rock used, brine composition does not change significantly from contact with rock surfaces. The recovery response is found to be consistent with changes in interfacial rheology. After the injection of high salinity smart-water in secondary mode, the low-salinity water injection in tertiary mode apparently triggers connection and mobilization of oil ganglia, as hypothesized from the recovery response. Tracking water droplet size distribution seems to support this hypothesis. Low-salinity brine injection is generally conducive to increasing oil production. On the other hand, our findings reveal that the injection of sulfate-enriched water can modify fluid–fluid interactions and consequently the final oil recovery. However, this smart-water appears to lose effectiveness entirely, if injected as residual oil saturation is reached, indicating an apparent threshold in the oil saturation to draw benefits of high-salinity sulfated-water.

Effects of Surfactant Blend Formulation on Crude Oil-Brine Interaction and Wettability: An Experimental Study

Interfacial tension of reservoir fluids and wettability are important parameters in the process of enhanced oil recovery. These two parameters affect the fluid distribution within reservoir formation. The fluids distribution in the reservoir strongly affects the flow behavior and residual oil recovery. Interfacial tension plays an important role due to its relationship between foam surface energy and foam stability. The wettability by contact angle measurement provides a method for determining fluid interaction and is considered as a basic research than practical tool for analysis of reservoir formation. The main objective of this research study is to determine the effects of interfacial tension and wettability on foam surfactant blend formulations, brine and crude oil. Anionic and nonionic surfactant blend were selected. The interfacial tension test was performed at 85oC. Dynamic interfacial tension of blended surfactant formulations with Malaysian crude oil were measured in fixed brine salinity. The interfacial tension values of tested surfactant blends were found lower than the interfacial tension between brine and crude oil. Interracial tension between crude oil and foam forming surfactant was reduced by using different concentration of surfactant blend. Good values were obtained by the measurement of contact angle between solid and three foam surfactant blend formulations. The interfacial tension and contact angle experimental studies revealed that, the blend of Alpha Olefin Sulfonate and Sodium Dodecyl Sulfonate with Octylphenol Ethylene Oxide play an important role in reducing the interfacial tension at crude oil-brine interface. The reduced interfacial tension and more wetting surface effects indicated that, these foam surfactant formulations are of great importance in the process of residual oil recovery.

Wetting of quartz by oleic/aqueous liquids and adsorption from crude oil

Contact angles for crude oil and brine on smooth quartz are sometimes used to assess the wettability of sandstone reservoirs. In this paper, the dynamic Wilhelmy plate technique is applied to the study of wetting of quartz by oil and brine. Changes in wetting of the quartz plate from a completely water-wet state were induced by adsorption from crude oil or de-asphalted crude oil (maltenes). Other variables included brine composition, pH, aging temperature and time, the solvent used to remove excess crude oil from the plate, and the temperature of measurement. The effect of plate speed and allowing an equilibration time during the course of measurement were also investigated. Force–distance relationships for a quartz plate passing through an oil–brine interface were used to obtain water-receding and water-advancing contact angles under dynamic conditions. Wetting states ranged from completely water-wet through hybrid-wet (very large contact angle hysteresis) to very strongly oil-wet. Contact angle hysteresis was often observed. Water-receding force–distance curves sometimes exhibited small-scale fluctuations for receding contact angles in the range of about 62–100°. These were ascribed to heterogeneity of wetting. Two modes of contact angle transition, pinning and slippage, were observed. Experimental results were compared with predicted force–distance relationships given by interface pinning during transitions from receding to advancing contact angles. Slippage during contact angle transitions was usually observed for receding angles in the range of 30° to about 60° with associated advancing angles in the range of 65–165°. Slippage was eliminated by allowing an equilibration time of about 30–60 min prior to reversing the direction of movement of the plate; experimental results were then in close agreement with theory.

Wetting properties of n-alkanes on AOT monolayers at the brine-air interface.

On the surface of a brine-surfactant (AOT) mixture, the long-chain alkanes (N>11) do not spread while the shorter ones (N11) spread leaving a very thin oil film at the surface. The interactions between the oil-water and oil-air interfaces stabilizing the height of this film are a van der Waals attractive potential, a short-range repulsive potential due to the alkane-surfactant interactions, and a repulsive potential due to the fluctuations of the oil-brine interface constrained by the oil-air surface. This is related to the phase behavior of mixtures of brine, AOT, and n-alkanes.

Roles of liquid crystals and micelles in lowering interfacial tension

The phases present and the tension behavior of (i) a pure alkyl aryl sulfonate (sodium 8-phenyl-n-hexadecyl-p-sulfonate), (ii) its mixtures with sodium dodecyl sulfate, and (iii) a commercial petroleum sulfonate (Witco TRS 10-80) have been studied in aqueous sodium chloride and decane by a battery of techniques, including a newly developed fast-freeze cold-stage transmission electron microscopy technique. The pure sulfonate is only slightly soluble in water or brine in the temperature range 25 to 90/sup 0/C and forms above the solubility limit a lamellar liquid crystalline phase. Lamellar liquid crystalline phases were also identified in aqueous dispersions of the commercial surfactant and in water-decane dispersions of the pure surfactant. A Kraft-like solubility boundary was observed near 50/sup 0/C for the pure surfactant in decane. In the presence of small amounts of surfactant, oil-brine interfaces can exhibit ultralow tension. The body of data brought together in this paper lead to the conclusion that for the systems examined ultralow tensions are caused by the presence of a surfactant-rich third phase at the oil-brine interface. Micelles do not appear to induce low tensions. With commercial surfactant, oil-brine tension is known to have a minimum with respect to salt and to surfactant concentrationn; the samemore » behavior is mimicked qualitatively by a mixture of the pure sulfonate (a liquid crystal former) and sodium dodecyl sulfate (a micelle former).« less