Interfacial Tension Measurements Research Articles

In-situ petroleum hydrocarbons contaminated soils remediation by polymer enhanced surfactant flushing: Mechanistic investigation

Chemicals injection for in-situ remediation of contaminated soils has attracted great attention. Efficiency of this technology relies on various parameters. Among them, chemical formulation of flushing agents has a key role. In this study, synergistic effect of Sodium Dodecyl Sulfate (SDS) ionic surfactant and Xanthan Gum (XG) biopolymer on the emulsification and solubilization of two types of petroleum hydrocarbon pollutants was investigated. Interfacial tension (IFT) measurements, bottle tests, droplet size distributions determination, and visual fluid flow experiments at pore-scale were conducted to assess pollutants removal strength of the proposed polymer enhanced surfactant flushing strategy. Results showed that although SDS surfactant reduced the equilibrium IFT of system to appropriate low value (i.e. less than 3 mN/m), it was not able to form stable oil-in-water emulsions. Nevertheless, addition of XG biopolymer, with no remarkable effect on IFT, improved emulsions formation and stability. Fluid flow experiments showed that oil snap-off and emulsion division are essential mechanisms of in-situ emulsion formation. A significant amount of hydrocarbon pollutants remained in porous medium after injection of 10 pore volumes of SDS. While, smaller size emulsions, as well as better contaminants removal were achieved for SDS solution with 4000 ppm XG at much lower injected pore volumes.

A collaborative emulsification system capable of forming stable small droplets of oil-in-water emulsions for enhancing heavy oil recovery

Water flooding for heavy oil development has a relatively low recovery effect. Emulsification system flooding is a very effective method for enhanced heavy oil recovery after water flooding. However, the sizes of oil-in-water (O/W) emulsion droplets formed by conventional emulsification systems and heavy oil are relatively large. Large droplet emulsions result in higher additional resistance when flowing in the porous media of the reservoir, which restricts the development effect on heavy oil recovery. In this study, a primary alcohol ethoxylate (AEO12) + sodium dodecyl sulfate (SDS) + alkali (NaOH) mixed collaborative emulsification (CE) system was developed and its formula was optimized. The optimal collaborative emulsification system formula is primary alcohol ethoxylate (0.25%) + sodium dodecyl sulfate (0.25%) + NaOH (0.05%). Through interfacial tension measurements, microemulsion state observations, emulsion particle size distribution tests, multiple light scattering, and fluidity experiments in simulated reservoir porous media, the oil-in-water emulsion stability and the mechanism of collaborative emulsification for improving heavy oil recovery were studied. Compared with the surfactant, the collaborative emulsification system can be more closely arranged at the heavy oil–water interface, so that the system can significantly reduce interfacial tension (IFT) (0.008 mN/m), formed a more stable and smaller oil-in-water emulsion (0.2 μm). It can greatly reduce the influence of additional resistance on its fluidity in reservoir porous media, and still has an excellent viscosity reduction rate at high temperatures (99.50% at 20 °C; 88.55% at 100 °C). Finally, through microscopic visualization experiments, it was shown that the collaborative emulsification system has an excellent ability to improve the sweep coefficient, and the residual heavy oil can be emulsified into oil droplets that are much smaller than pore throats. The developed collaborative emulsification system has excellent potential for enhancing heavy oil recovery after water/hot water flooding.

Stone Mineral Salt Solution As A Potential Nutrient For Biosurfactant And Biosolvent Production On Meor Application

Bioproduct from microbial enzymatic activities such as biosurfactant, bioacid, biosolvent, and biopolimer is a useful product in improving oil recovery. The nutrient factors such as the difference and variation of the nutrient, influence microbial growth and enzymatic activities. The objective of this study is to examine the feasibility of Stone Medium Salt Solution (SMSS) as a potential nutrient for biosurfactant and biosolvent production on MEOR application. In the tube test, microbial mixed culture and 3 asphaltic crude oils, tested as C1, C2, and C3, were examined in 0%, 25%, 75%, and 100% SMSS concentrations. The microbial activities were determined by pH, viscosity, and interfacial tension measurements under microaerophilic and aerophilic conditions at 0-day and 7-day incubations. The Microbial Core Flooding (MCF) experiment was measured to observe in field application. The microbial consortia in all crudes had good growth using 100 % SMSS medium. After 7 days, the population increased in both microaerophilic and aerophilic conditions. The interfacial tension and viscosity of all crudes decreased except the viscosity of C1 in microaerophilic condition. The highest decrease occurred in C2 crude, which reduced 51% of interfacial tension and 58.73% of viscosity. Although the result of MCF experiment showed insignificant recovery (only 1.63% from Original Oil in Place), this study proves that SMSS nutrient can be applied in MEOR research by ex situ biosurfactant and biosolvent production for enhancing oil recovery.

Role of aqueous phase composition and hydrophilic emulsifier type on the stability of W/O/W emulsions

Double W1/O/W2 emulsions can act as fat substitutes in food matrices, although synthetic emulsifiers are commonly used due to their inherent instability and susceptibility to coalescence. In order to guarantee the stability of the W/O interface, the synthetic emulsifier polyglycerol polyricinoleate (PGPR − 4.5% w/w) was used. However, the replacement of chemically synthesized ingredients by natural alternatives has been extensively pursued in food applications. In this sense, whey protein isolate (WPI) and sodium caseinate (SC) were used to stabilize the external aqueous phase (W2) of water-in-oil-in-water double emulsions (W1/O/W2), in addition to Tween 80 that was used as a control. The composition of the internal aqueous phase and its effects on the double emulsion were studied by the addition of sodium chloride (0.2% w/w NaCl), gallic acid (0.5% w/w GA) or a GA/NaCl mixture (0.5% / 0.2% w/w). The effect of these different hydrophilic components was evaluated from measurements of droplet size, viscosity, ζ potential, interfacial tension and kinetic stability. SC-stabilized W/O/W emulsions showed better kinetic stability than WPI- and T80-systems. These results can be attributed to the initial droplet size (SC < T80 < WPI) and viscosity of the emulsions (SC < T80 < WPI). SC is a more flexible and unfolded protein that can quickly adsorb and rearrange at the interface, favoring the formation of smaller droplets and limiting the migration of inner water droplets to the outer phase. In addition to smaller droplets, the addition of SC (8% w/w) to the external aqueous phase promoted an increase in the viscosity of bulk systems, which reduced the destabilization rates by creaming and coalescence. All W/O/W systems containing NaCl in the inner aqueous phase presented greater kinetic stability during 7 days of storage. Although the addition GA was less efficient to stabilize double emulsions compared to NaCl, this phenolic compound reduced the interfacial tension, favoring the formation of WPI- and T80-droplets with smaller diameters. However, the use of GA/NaCl blend improved the stability and functionally of W/O/W double emulsions. We concluded that the type of hydrophilic emulsifier, the properties of the inner water droplets and the viscosity of phases influenced the droplet size, viscosity and kinetic stability of double emulsions. This work provides a better understanding of how composition influences the properties of double emulsions and how it can be used to design W/O/W emulsions as fat substitutes in more complex food systems.

Hydrophobically Modified Cellulose Nanofibers-Enveloped Solid Lipid Microparticles for Improved Antioxidant Cargo Retention.

This study introduces a cellulose nanofiber surfactant system, in which the surface is hydrophobically modified with different alkyl chain structures for the effective envelopment of solid lipid microparticles (SLMs). To endow bacterial cellulose nanofibers (BCNFs) with excellent ability to assemble at the lipid-water interface, alkyl chains with designated molecular structures, such as decane, didecane, and eicosane, are covalently grafted onto the BCNF surface. Interfacial tension and interfacial rheology measurements indicate that dialkyl chain-grafted BCNFs (diC10 BCNF) exhibit strong interfibrillar association at the interface. The formation of a dense and tough fibrillary membrane contributes significantly to the enveloping of the SLMs, regardless of the lipid type. Because the diC10 BCNF-enveloped SLMs exhibit a core molecular crystalline phase at the microscale, they can immobilize an oil-soluble antioxidant while maintaining its long-term storage stability. These findings show that the cellulose-surfactant-based SLM technology is applicable to the stabilization and formulation of readily denatured active ingredients.

Carbonate Stimulation Using Chelating Agents: Improving the Treatment Performance by Optimizing the Fluid Properties.

Chelating agents’ solutions were introduced as effective alternatives to strong acids to be used in acid-sensitive situations such as high temperature and salinity conditions. However, limited studies have been conducted to examine the optimum conditions for improving the chelating agent performance. In this study, a comprehensive study of solubility and physical properties of different chelating agents’ fluids that are commonly used in the oil upstream applications was performed under different conditions. The optimum concentration ranges at which chelating agents are soluble and effective to provide the best acidizing efficiency are determined. Also, more than 340 data sets were used to develop new empirical models that can help in estimating the chelating agents’ properties at wide ranges of concentrations and treatment temperatures. In this work, different experimental measurements were conducted using a pressure of 2000 psi (13.7 MPa) and a temperature of 120 °C (393.15 K). The conducted experiments are density and viscosity measurements, solubility experiments, interfacial tension measurements, computed tomography scan, and coreflooding tests. The used chelating agents are diethylenetriaminepentaacetic acid (DTPA), hydroxyethylenediaminetriacetic acid (HEDTA), and ethylenediaminetetraacetic acid (EDTA). Results revealed that HEDTA and DTPA chelating agents have good solubility at different pH and concentration ranges. However, EDTA showed a limited solubility performance, especially at a concentration greater than 15 wt %. Moreover, the developed correlations provided fast and reliable estimations for the chelating agent density and viscosity, and estimation errors of around 1% were achieved. Also, treating the tight carbonate rocks with the optimized chelating agent solutions showed effective wormholes with a minimum acid volume. Finally, a good match between the actual and predicted pressure drops is achieved, confirming the high reliability of the developed models. Overall, this work can help in designing the stimulation treatment by suggesting the optimum ranges for fluid concentration and solution pH for wide ranges of temperature. Also, the newly developed correlations can be used to provide quick and reliable estimations for the pressure drop and the chelating agent properties at reservoir conditions.

Refractive Index Effects in Pendant Drop Tensiometry

An optical model is established to investigate the effects of refractive index changes on the measurement of interfacial tension by the pendant drop method with axisymmetric drop shape analysis. In such measurements, light passes from the pendant drop through a surrounding bulk phase, an optical window and air to reach the lens of the camera system. The relation between object and image size is typically determined by calibration and, if the refractive indices of any of the materials in the optical path change between calibration and measurement, a correction should be made. The simple model derived in this paper allows corrections to be calculated along with the corresponding contribution to the overall uncertainty of the interfacial tension. The model was verified by measurements of the interfacial tension between decane and water under two different calibration conditions. Neglect of the correction was shown to cause errors of up to 6 % when the bulk phase changed from air (during calibration) to water (during measurements) and of about 9 % when the system was calibrated without the optical window used for the final measurements. The refraction changes due to high pressures and supercritical fluid states can also lead to measurement errors. The proposed model can facilitate more accurate interfacial tension measurements and reduce the amount of repetitive calibration work required.

Laboratory Study on the Oil Displacement Process in Low-Permeability Cores with Different Injection Fluids

Although flooding technology has found wide application in low-permeability reservoir development practices, the oil recovery enhancement mechanisms for different injection fluids still lack specific focus based on comprehensive investigations. Therefore, in this paper, supercritical CO2 (ScCO2), N2, and water injection processes in oil-saturated low-permeability tight cores were comparatively studied. To reveal the effect of physicochemical properties of the injection fluid on the oil recovery efficiency, the Berea sandstones with three permeability levels and kerosene were employed in this study to exclude other parameter influences. The flooding processes employing various injection media were investigated based on quantitative comparisons of the oil recovery factor and the displacement pressure difference at two system pressures. The experimental results show recovery efficiencies of 59–91 and 84–92% with the increasing permeability for the ScCO2 injection process at system pressures of 15 and 25 MPa, respectively, which are much higher than 26–40 and 21–52% in the N2 case and 43–46 and 45–49% in the water cases. Interfacial tension (IFT) measurement results indicate that miscibility conditions have been achieved for the ScCO2/oil system, thus leading to much higher oil recovery. On the other hand, the pressure difference results show a similar magnitude of 10 MPa/m for both ScCO2 and N2 processes, which is much lower than the 100 MPa/m for the water flooding cases. Comprehensive comparison shows that ScCO2 shows great advantages in the application of unconventional reservoirs. It is expected that our research work could enrich the investigations of CO2 flooding and the in-depth understanding of the mechanisms and better guide the utilization of CO2.

Evaluation of performance spectra of mono and divalent low saline brine injection in sandy-carbonates for mobilization of crude oil

Low salinity water (LSW) injection is one of the most economical methods of enhanced oil recovery (EOR) but its applicability as a waterflood was very limited. Also, its performance spectra significantly change when exposed to different rock compositions which need to be well understood. Thus, this study reports the impact of monovalent i.e., KCl and divalent i.e., CaCl2 salts (of varying concentration: 0–1 wt%) on rock/fluid interaction and oil recovery from rocks of different compositions (sandstone and sandstone + carbonate). Interfacial tension (IFT) measurements, between brine and crude oil, suggested minimum IFT for KCl brine and CaCl2 brine of 0.25 and 0.1 wt%, respectively. The variation in rock composition significantly affected the solution activity (via zeta potential) of KCl and CaCl2 brines, and brines exhibited maximum change in solution activity and adsorption of ions for the rock samples showing a compositional shift towards carbonate. Finally, flooding experiments were conducted wherein, initially porosity was found to be greater in sandstone (29.4%) as compared to carbonate (24.3%) rock composition. Finally, oil recovery and water cut profiles were obtained for different rock samples flooded by KCl and CaCl2 brines and compared with the ones of the conventional water flooding method. The results showed better performance of low saline brine injection which further improved when tests were performed for synthetic rock samples of pure carbonate (0% sandstone + 100% carbonate). A maximum oil recovery of 51% OOIP (original oil in place) was obtained for 100% sandstone while 100% carbonate demonstrated maximum oil recovery of 59% OOIP. Also, the impact of high temperature (90 °C) on these results was tested for promoting the role of low saline brine injection in carbonate reservoirs of complex conditions. Increasing the temperature further increased the amount of oil recovered to 61% OOIP, demonstrating the high efficacy of LSW at high temperatures.

Low salinity surfactant alternating gas/CO2 flooding for enhanced oil recovery in sandstone reservoirs

Surfactant alternating gas/CO2 (SAG) flooding is a promising enhanced oil recovery (EOR) technology, which has the potential to improve oil production beyond primary and secondary water flooding methods. However, the performance of SAG flooding is restricted due to instability under high salinity reservoir conditions and excessive surfactant adsorption. One convenient and relatively low-cost option to overcome the limitations and improve the performance of SAG flooding is the use of low salinity water (LSW). In this study, an innovative and effective approach in the form of a low salinity surfactant (LSS) system was developed to suitably enhance the efficacy of immiscible SAG flooding in sandstone reservoir cores. The impact of LSS solutions on various mechanisms responsible for EOR including surface and interfacial tension (IFT), wettability alteration, CO2-foam stability, and surfactant adsorption were investigated. The initial IFT measurements revealed that oil-water IFT could be lowered using low salinity formation water (FW), however a more effective reduction was possible only when surfactants were introduced in such a system to form LSS solutions. Similarly, reductions in the contact angle (from initial 122° to 45°) were achieved with LSS solutions which demonstrated favorable wettability alteration of the reservoir rock from oil-wet to water-wet conditions. Foam stability experiments revealed that the half-life of CO2-foams generated with LSS solutions was appreciably higher, thus indicating the positive impact of low salinity water on foam stability. Additionally, anionic LSS solutions displayed reduced surfactant adsorption behavior onto sandstone cores, whereas for cationic LSS solutions the adsorption values were comparatively higher and exhibited a reverse adsorption trend with decreasing salinity. Finally, core flooding experiments illustrated that significantly higher residual oil could be mobilized and recovered through the tertiary immiscible low salinity surfactant alternating gas/CO2 (LSSAG) flooding. Nearly 23% original oil in place (OOIP) was produced by employing anionic LSS solution as the chemical slug during the LSSAG flooding. However, under similar experimental conditions, LSSAG flooding with cationic LSS solution recovered only about 16 %OOIP despite its comparatively better wettability alteration and IFT performance. In summary, using anionic LSS solutions constitute an effective means to suitably improve the performance of immiscible SAG flooding in sandstone reservoir cores.

Complex study of acid-in-oil emulsions, their formation, stabilization and breakdown

Different problems may occur during acid treatment of oil reservoirs because of the incompatibility of acid with rocks and fluids. One of the issues is the formation of acid-in-oil emulsions, which block pore throats and hinder acid removal. The standard “bottle-test” method does not fully characterize such emulsions and allows only quick reagent selection. This article presents a new methodology that enables the evaluation of emulsion formation and the possible risk for acid treatment. This methodology includes visual control and measurement of viscosity, interfacial tension, and voltage stability. We found that HCl-based emulsions are generally more viscous, finer, and stable, but the high strength of the acid may lead to emulsion breakdown. We also established that emulsions that are stable under static conditions may break down after applying mechanical stress, which is a characteristic of sulfamic acid-based emulsions. Although it may not be possible to separate emulsions visually, a water content gradient may be observed in an emulsion column. Our results demonstrate that the acid and oil parameters are interconnected in emulsion formation issues. This methodology and the obtained results may be applied for quick and proper reagent selection for better acid treatment results.

Measurements and interpretation of crude Oil-Water/Brine dynamic interfacial tension at subsurface representative conditions

Interfacial tensions (IFTs) between crude oil and water or brine systems are critically important in many processes. Exhibited dynamic behavior often remains poorly studied and requires in-depth analysis. In this study, 27 series of dynamic IFT measurements were conducted for three different crude oils in combination with three different aqueous phases (pure water and two synthetic reservoir brines) at temperatures of 298.15, 343.15 and 393.15 K and pressures up to 30 MPa. This study provides a large database of crude oil-water/brine IFTs encompassing reservoir conditions of temperature and pressure. Specific effects of temperature, pressure, and fluid composition on the crude oil-water and oil-brine IFTs were evaluated. The dynamic evolution of the IFT between the crude oils and aqueous phases was categorized according to typical relationships observed. The most commonly observed evolution was an initial rapid decline in IFT, over a period of 100 to 1,000 s, followed by levelling off at a nearly-constant long-term value. However, in certain cases, the initial rapid decline was followed by a broad minimum and a subsequent slow increase towards a nearly-steady long-time value. In either case, the initial decline is described by a simple model based on diffusion of surface-active components in the oil and their subsequent adsorption at the interface. The longer-term behavior may be further attributed to a combination of saturation, rearrangement and dissolution of the surface-active components.

Microfluidic macroemulsion stabilization through in situ interfacial coacervation of associative nanoplatelets and polyelectrolytes

HypothesisSince macroemulsions tend to break down to lower free energy, they hardly retain their initial drop state. Therefore, studies are being conducted to overcome this based on advanced interface engineering techniques, but it is still challenging. Herein we hypothesize that the stability of giant droplets can be secured without chemical bonding through the interfacial coacervation of polyelectrolyte and associative nanoplatelets. ExperimentsWe synthesized associative silica nanoplates (ASNPs) via polypeptide-templated silicification and consecutive wettability adjustment. To produce monodisperse macrodroplets, the inner fluid containing partially positively charged ASNPs and the outer fluid dissolving negatively charged polyacrylic acid (PAA) were coflowed through a capillary-based microfluidic channel. FindingsDynamic interfacial tension and interfacial rheology measurements revealed that the migration of ASNPs and PAA from each phase to the interface led to the formation of a complex bilayered thin membrane with an enhanced interfacial modulus. In addition, we demonstrated that adjusting the surface properties of ASNPs by coupling a fluorochemical enabled the production of monodisperse fluorocarbon-in-oil-in-water double macroemulsions. These results highlighted the applicability of our microfluidics-based interfacial coacervation technology in the development of complex fluid products with visual differentiation and drug encapsulation.

Effect of bacteria on oil/water interfacial tension in asphaltenic oil reservoirs

Microbial enhanced oil recovery (MEOR), due to the formation of biofilm and the presence of biosurfactants generated by microorganisms in the reservoir, can play a role in reducing interfacial tension (IFT) and wettability alteration. In this work, the fluid-fluid interaction by measuring the IFT has been evaluated for combining two EOR methods, including low salinity water and MEOR, due to the high importance of fluid-fluid interaction in EOR. GeoBacillus stearothermophilus has been used as a bacterium to study changes in IFT. The effect of different salts, including monovalent and divalent cations and anions at different salinities, on biosurfactant performance, is investigated using IFT measurements. Also, the type of oil is evaluated in terms of its acidic and basic properties on the performance of biosurfactants. According to the results of this study, injection of GeoBacillus stearothermophilus bacteria reduces interfacial tension in acidic oil by 10.26% and in basic oil by 5.26%. According to the results, increasing salinity in the presence of oil-containing asphaltene with basic properties increases the IFT of the solution containing GeoBacillus stearothermophilus bacteria, but in the presence of acidic oil, a decrease in IFT is observed. The most significant effect of reducing the IFT of acidic oil and solution containing GeoBacillus stearothermophilus is obtained in the presence of the following salts, respectively: CaCl2 > MgCl2 > NaCl. The results show that with increasing CaCl2 concentration, the IFT between basic oil and GeoBacillus stearothermophilus solution gradually increases. This ascending trend is in the presence of NaCl salt with a lower slope. However, in the presence of MgCl2 salt, dual behavior is observed before and after the concentration of 1000 ppm, so that before this concentration, the IFT increases and then decreases. The findings of this study can help for a better understanding of the interaction of bacteria with asphaltenic oils in the presence of effective salts for low salinity water injection. The results of this study showed that by combining low salinity water with bacteria, less IFT could be obtained than low salinity water or bacteria alone.

Effect of 2D Alpha-Zirconium Phosphate Nanosheets in Interfacial Tension Reduction and Wettability Alteration: Implications for Enhanced Oil Recovery

Summary α-Zirconium phosphate (α-ZrP) nanocrystals were synthesized by refluxing method and subsequently exfoliated into extremely thin 2D nanosheets by tetrabutylammonium hydroxide (TBAOH) solution. Dynamic light scattering, scanning electron microscopy (SEM), and transmission electron microscopy (TEM) were used to characterize the size distribution and morphology of α-ZrP nanosheets. Interfacial tension (IFT) and contact angle measurement were conducted by different concentrations of α-ZrP nanosheets solutions. The results displayed that the wettability of porous media surface was altered from oleophilic to hydrophilic and the IFT decreased with the increasing of α-ZrP nanosheets concentrations. A new method was proposed to calculate the Hamaker constant for 2D α-ZrP nanosheets. The calculated results displayed that α-ZrP nanosheets were not easy to agglomerate under experimental environment and when the interaction energy barrier increased, the transport amount of α-ZrP nanosheets also increased. Coreflooding tests were also performed with various concentrations and the oil recovery efficiency increased from 33.59 to 51.26% when α-ZrP nanosheets concentrations increased from 50 to 1,000 ppm.

The amphoteric cartilage surface tested in the pH Range from 2.0 to 9.0

Background: Phospholipids adsorbed to negatively-charged proteoglycan matrix form phospholipid (membrane), have negatively charged surface (-PO4-) and are hydrophilic. Strong adsorption and strong cohesion are necessary for phospholipids to provide a good lubricant. The surface energy of spherical lipid bilayers have "bell-curve" shaped has amphoteric character and lowest surface energy at a pH 7.4 ± 1 of the natural joint. Objectives: The amphoteric character of the natural surface of the articular cartilage was determined by measuring the surface energy of the model spherical bilayer lipid membrane. It was found that the friction (f) vs. pH 2.0 to 9.0 of the pair (cartilage/cartilage) has the amphoteric character by exposing "bell-curve" shaped with an isoelectric point (IEP). Methods: The friction coefficient (f) was measured with the sliding pin-on-disc tribotester the friction between two surfaces (cartilage/cartilage) pair. The method of interfacial tension measurements of the spherical lipid bilayer model vs the pH over the range 0.2 to 9.0 was used. Results: The dependence of friction coefficient between two cartilage surfaces on the pH over the range 2.0 to 9.0 is demonstrated by a “bell - curve” in Fig. 2(A). The surface energy of a model spherical bilayer lipid membrane vs. the pH has the character of a “bell - curve” with an (IEP) is shown in Fig. 2(B). Conclusion: The amphoteric effect on friction between the bovine cartilage/cartilage contacts has been found to be highly sensitive to the pH of an aqueous solution. In this paper we demonstrate experimentally that the pH sensitivity of cartilage to friction provides a novel concept in joint lubrication on charged surfaces. The change in friction was consistently related to the change of charge density of an amphoteric surface.

Study on the Liquid-Liquid and Liquid-Solid Interfacial Behavior of Functionalized Graphene Oxide.

With the rise of carbon neutrality, the applications of carbon-based materials are gaining considerable attention. Graphene oxide (GO) is a two-dimensional sheet with epoxy and hydroxyl groups on the basal plane and carboxyl groups at the edge. In order to change the oil/water (o/w) interfacial activity, GO was controlled and modified by dodecylamine to get two kinds of functionalized GOs (fGOs), named as basal plane-functionalized GO (bGO) and edge-functionalized GO (eGO), respectively. The interfacial tension measurement showed that fGOs could reduce more interfacial tension at the poly-α-olefin/water interface than those at synthetic esters or aromatic compounds/water interfaces. Besides, eGO can reduce more poly-α-olefin-4/water interfacial tension compared to bGO. The interfacial dilatational rheology of eGO and fatty alcohol polyoxyethylene ether-4 (MOA4) showed that MOA4 gradually replaced eGO at the interface with the increase of MOA4, until the interface was completely occupied. eGO and MOA4 complex emulsion exhibited the best friction-reducing performance at 250 rpm. The coefficient of friction (COF) curves of the emulsions with eGO showed two platforms, with the COF reduced by 37.42% at the most. The rheological results of emulsions showed that the addition of eGO increased the elasticity of the emulsion. Emulsions showed shear-thinning and friction-thickening properties, which make it easier for the emulsion to form a lubricating film on the metal surface. Our research results suggested that the functionalization on the edge of GO will change the interfacial properties significantly, which have widespread applications in the encapsulation of active materials, surface protection, adsorption, and separation of pollutants.

Investigation on the effect of CuO nanoparticles on the IFT and wettability alteration at the presence of [C12mim][Cl] during enhanced oil recovery processes

In the current study, the effect of CuO nanoparticles (CuO-NPs) at the presence of dodecyl-3-methylimidazolium chloride ([C12mim][Cl]) is investigated on the interfacial tension (IFT) reduction, wettability alteration, and even tertiary oil recovery. Since the prepared solutions with CuO-NPs are completely dark and it is impossible to measure the IFT of these solutions in the presence of crude oil using the pendant drop method (since one of the phases must be transparent for IFT measurement using the pendant drop method), n-heptane (representative of saturates) and toluene (representative of aromatics) are used only for IFT measurement of solutions prepared by CuO-NPs, while rest of the experiments are performed using crude oil. The obtained results reveal that CuO-NPs are not stable in the aqueous solution in the absence of surfactant which means fast precipitation of CuO-NPs and a high risk of pore plugging. In this way, the stability of CuO-NPs is investigated at the presence of dodecyl-3-methyl imidazolium chloride ([C12mim][Cl]) as an effective surfactant for stabilizing the CuO-NPs in the aqueous solution (more than 1 month without precipitation using 1000 ppm of IL). Further measurements reveal that although the presence of IL in the aqueous solution can reduce the IFT of oil/aqueous solution system, especially for the aqueous solutions prepared by formation brine (0.65 mN.m−1), the presence of CuO-NPs has no considerable effect on the IFT. On the other hand, not only the contact angle (CA) measurements reveal the considerable effect of IL on the wettability alteration toward water-wet condition (68.3° for IL concentration of 1000 ppm) but also the addition of CuO-NPs can significantly boost the wettability alteration toward strongly water-wet condition (23.4° for the concentration of 1000 ppm of CuO-NPs). Finally, several core flooding experiments are performed using different combinations of chemicals to find the effect of these chemicals on the tertiary oil recovery factor. The results reveal that the presence of CuO-NPs can enhance the oil recovery of injected chemical slug (aqueous solution prepared by dissolution of IL with an oil recovery factor of 10.1% based on Original oil in place (OOIP)) to 13.8, %, 16.9%, and 21.2% based on OOIP if 500, 1000, 2000 ppm of CuO-NPs existed in the solution concomitant with 1000 ppm of [C12mim][Cl].

Capillary pressure-based measurement of dynamic interfacial tension in a spontaneous microfluidic sensor

The size of droplets and bubbles, and the properties of emulsions and foams strongly depend on dynamic interfacial tension (γd) - a parameter that is often inaccessible due to the very short time scales for droplet and bubble formation, and the inaccessibility of (e.g., food) production lines. To solve this challenge, we developed a microfluidic tensiometer that can measure γd by monitoring the formation time of both droplets and bubbles. Our tensiometer is a pressure-driven microfluidic device that operates based on the principle of a pressure balance: the formation of a droplet (or a bubble) is initialized when the Laplace pressure of the interface is decreased below the externally applied pressure, and this decrease is caused by a reduction in γd that can be calculated from the applied pressure and the Young-Laplace equation. The decay of γd due to surfactant adsorption can be followed at the characteristic time scale, which is dependent on surfactant type and concentration. For 0.05-1% wt sodium dodecyl sulfate (SDS), we were able to measure γd at time scales down to 1 ms and 0.1 ms for droplet and bubble interfaces, respectively, at increasing applied pressures and SDS concentrations. Our tensiometer proves to be a simple, robust method that inherently allows access to nearly the full range of dynamic interfacial tension at relevant time scales.

On surface interactions of environmental friendly surfactant/oil/rock/low salinity system: IFT, wettability, and foamability

In recent years, natural surfactants have been considered as part of the EOR processes given their non-toxic and environment friendly nature. However, once chosen wisely, surfactants can only reduce the interfacial tension (IFT) and are often unable to alter the surface wettability for a better hydrocarbon production. Low salinity water (LSW) is a good candidate on these occasions, but the interaction of LSW with natural surfactants for wettability alteration has not been deeply understood. In this work, an attempt was made to extract and characterize a natural surfactant which could be used together with LSW for EOR purposes. To do this, a natural surfactant was extracted from Saponin and its physico-chemical properties such as CMC, foamability, and thermal stability were tested. A series of IFT and wettability measurements were then conducted to evaluate the performance of the surfactant as an EOR additive. The results obtained indicated that the extracted surfactant has a high thermal stability and can be fully functional in the temperature of up to 100 °C. It appears that increasing the level of salinity in the solution can improve the efficiency and foamability of the surfactant. It was observed that the extracted surfactant as can reduce the IFT of an air-water system by 78.65% and is capable of favorably altering the surface wettability of sandstone for a better hydrocarbon production once combined with LSW.