Interfacial Tension Measurements Research Articles

Unlocking the Effects of Fluid Optimization on Remaining Oil Saturation for the Combined Sulfate-Modified Water and Polymer Flooding

Interfacial interactions and wettability alteration remain as the main recovery mechanism when modified water is applied seeking to obtain higher oil recoveries. Fluid-fluid interaction could lead to the development of the called viscoelastic layer at the interface in oil-brine systems. This interfacial layer stabilizes thanks to the slow chemical interaction between oil polar compounds and salts in the brine. This study investigates the role of sulfate presence in injection brine that could possible lead to develop the interfacial viscoelastic layer and hence to contribute to the higher oil recovery. Furthermore, polymer flooding is performed in tertiary mode after brine flood to investigate/unlock the synergies and potential benefits of the hybrid enhanced oil recovery. Brine optimization is performed using the composition of two formation brines and four injection brines. Moreover, interfacial tension measurements and oil drop snap-off volume measurements are performed in parallel with the core flooding experiments to define the role of interfacial viscoelasticity as the recovery mechanism other than wettability alteration. Synthetic seawater spiked with double amount of sulfate depicted potential results of interfacial viscoelastic layer development and hence to contribute the higher oil recovery. Total oil recovery after secondary-mode using sulfate-modified water and tertiary-mode polymer flood was higher than the combination of seawater brine in secondary-mode and polymer flood in tertiary-mode. Nevertheless, experiments helped us concluding that the amount of sulfate added is a critical factor to obtain maximum oil recovery and to avoid pore-plugging problems. We, therefore, demonstrate that executing a detailed fluid optimization leads to promising laboratory results, potentially linked with an improvement in the economics of the field applications.

Determination of dynamic interfacial tension in a pulsed column under mass transfer condition

AbstractInterfacial tension is an essential physical property in two‐phase flow, and it changes due to the mass transfer. The measurement of dynamic interfacial tension (DIFT) in such a condition is a difficult problem. In the previous study (Zhou et al., Chem Eng Sci. 2019; 197:172–183), we presented the quantitative relation between the droplet breakup frequency function (DBFF) and interfacial tension. It is found that the DBFF is highly depended on interfacial tension. Therefore, the DBFF is a suitable parameter to quantitatively characterize the interfacial tension. Based on this concept, the DIFT in the column is determined by regression method after the DBFF under mass transfer condition is measured. It is found that the DIFT is smaller than the static interfacial tension. This result indicates that interphase mass transfer leads to decreasing of the interfacial tension. The decreasing extent of the DIFT has a positive correlation with the mass transfer flux.

Experimental Investigation of Water Incompatibility and Rock/Fluid and Fluid/Fluid Interactions in the Absence and Presence of Scale Inhibitors

SummaryWaterflooding is known as an affordable method to enhance oil recovery after primary depletion. However, the chemical incompatibility between injected water and the water in the reservoir may cause the formation of mineral scales. The most effective method for managing such a problem is to use a variety of scale inhibitors (SIs) along with a waterflooding plan. It is necessary to perform a comprehensive study on the incompatibility scaling issue for the candidate-brine/SI formulations, and also their effect on the reservoir-rock/fluid characteristics. In this study, both in the absence and presence of polymeric, phosphonate, and polyphosphonate SIs, the scaling tendency (ST) of different brines is evaluated through experimental and simulation works. Drop-shape analysis (DSA), environmental-scanning-electronic-microscopy (ESEM) observation, energy-dispersive X-ray (EDX) analysis, and microemulsion phase behavior are also used to study the effect of different brine/SI formulations on the rock/fluid and fluid/fluid interactions, through wettability and interfacial-tension (IFT) evaluation. In summary, sulfate (SO42−) was identified as the most problematic ion in the formulation of injected water that causes the formation of solid scales upon mixing with the cation-rich formation water (FW). In the case of SIs, solid precipitation was shifted toward a lower value, with more pronounced effects at higher SI concentrations. At different ionic compositions, the inhibition efficiency (IE%) of all SIs ranged from 16 to 50% at [SI] = 20 ppm and 38 to 81% at [SI] = 50 ppm. In general, phosphonates worked better (i.e., higher IE value) than polymeric SI. Measuring contact angles along with ESEM/EDX data also illustrated the positive effect of SIs on the wettability alteration of the aged carbonate substrates. In the absence of SIs, the contact angles for different brines were in the range of 70° ≤ θ ≤ 104°, whereas these values fell between 35 and 80° for systems containing 50 ppm of SI. In addition, phase-behavior study and IFT measurement illustrated a salinity-dependence effect of SIs on the interfacial behavior of the oil/water system.

Experimental Investigation of Asphaltene Content Effect on Crude Oil/CO2 Minimum Miscibility Pressure

Minimum Miscibility Pressure (MMP) is regarded as one of the foremost parameters required to be measured in a CO2 injection process. Therefore, a reasonable approximation of the MMP can be useful for better development of injection conditions as well as planning surface facilities. In this study, the impact of asphaltene content ranging from 3.84 % to 16 % on CO2/heavy oil MMP is evaluated. In this respect, slim tube miscibility and Vanishing Interfacial Tension (VIT) tests are used. Regarding the VIT test, the Interfacial Tension (IFT) is measured by means of two methods including pendant drop and capillary apparatuses, and thereafter the MMP measurement error between slim tube and VIT methods are calculated. Based on the results, by increasing the asphaltene content, the measured MMP by slim tube method increases linearly while that by VIT follows no clear trend. The results also indicate that there is an asphaltene content range within which the MMP error between slim tube and VIT tests is minimized. IFT measurement by pendant drop and Capillary Glass Tube (CGT) methods show that by increasing asphaltene content up to 10.15 %, IFT declines, whereas for further increase in content, IFT increases because of the irregular dispersion of asphaltene in oil droplets.

Separation of oily wastewater using titanium modified multi-walled carbon nanotubes as demulsifier

Oily wastewater causes a lot of environment problems and draws wide attention. In this paper, titanium modified multi-walled carbon nanotubes (CNTs/TiO2) for the treatment of oily wastewater were synthesized using in situ sol-gel methods. Fourier transform infrared spectroscopy (FT-IR) and X-ray diffraction (XRD) were employed to characterize the structure and composition of CNTs/TiO2. Also, scanning electron microscope (SEM) and transmission electron microscope (TEM) showed that TiO2 was evenly distributed in carbon nanotubes (CNTs) to induce a good synergistic effect. After the oily wastewater was treated with 400 mg/L of CNTs/TiO2 at room temperature for 30 min, the light transmittance of the aqueous phase was 89.7%. Furthermore, the composites with good interfacial activity could be reused at least five times. The combination of dynamic interfacial tension measurements, interfacial activity, interfacial film assemble and optical microscope was employed to investigate the demulsification mechanism.

Experimental investigation of Alfalfa natural surfactant and synergistic effects of Ca2+, Mg2+, and SO42− ions for EOR applications: Interfacial tension optimization, wettability alteration and imbibition studies

Fractured moderate oil-wet carbonate reservoirs are the main productive formations in the Middle East. The change in wettability state toward water wetness beside interfacial tension (IFT) reduction is one of the potential scenarios for more oil recovery process. Smart water and natural surfactant injection into the porous media will alter the rock wettability and reduce IFT which consequently results in more oil sweep from untouched pores. In this paper, a novel natural surfactant (Alfalfa species) is introduced for EOR applications. IFT and contact angle tests were carried out between the oil phase, rock surface, Alfalfa natural surfactant, and surfactant—ion hybrid aqueous solutions. The results of Alfalfa natural surfactant showed a 29.29 mN/m reduction of IFT (63.39% IFT optimization) at the concentration of 4 wt% as the critical micelle concentration (CMC). Also, after addition of Alfalfa the wettability of rock tends to be more water-wet from the initial oil-wet state by application of Alfalfa because of 86.84° reduction of contact angle (49.91% wettability alteration). Solutions of calcium, magnesium, and sulfate ions were prepared as modified synthetic seawater at CMC of Alfalfa natural surfactant to investigate their synergistic influences on intensifying the optimizations of IFT and wettability alteration as hybrid solutions. IFT measurements of the hybrids demonstrated that among mentioned ions calcium brings the best results as it showed good synergistic effects with mentioned non-ionic natural surfactant in advancing the optimization of IFT reduction from 63.39 (surfactant solution) to 71.0 (surfactant—ion hybrid solution) percent. Also, contact angle measurements of the hybrids demonstrated that calcium ions gain the best results and advance the contact angle optimization from 49.91 (surfactant solution) to 61.8 (surfactant—ion hybrid solution) percent. Therefore, the solution of 3 times Ca concentrated seawater + CMC of surfactant selected to conduct imbibition tests as a displacement experiment based on the hybrid results and the candidate solution caused a 19.2% increase in oil recovery factor regarding seawater flooding and a total oil recovery factor of 62%.

Equilibria in DPPC-Diosgenin and DPPC-Diosgenin Acetate Bilayer Lipid Membranes: Interfacial Tension and Microelectrophoretic Studies

Interactions between components of model lipid membranes (spherical lipid bilayers and liposomes) are investigated here. Parameters characterizing equilibria in the 1,2-dipalmitoyl-sn-glycero-3-phosphocholine (DPPC)-diosgenin (Dio) and 1,2-dipalmitoyl-sn-glycero-3-phosphocholine (DPPC)-diosgenin acetate (DAc) membrane systems have been determined. The interfacial tension measurement of spherical lipid bilayers was based on the Young-Laplace’s equation using a homemade computer-controlled device. We assume a 1:1 complex in the DPPC-Dio and DPPC-DAc membrane systems. The parameters A 3 − 1 , the surface concentration of lipid membranes formed from these complexes, γ 3 , the interfacial tension of such membranes, and, K, the constant stability of these complexes were calculated. Microelectrophoresis was used for examinations of the surface charge density of lipid membranes. The values were obtained here from electrophoretic mobility data applying Smoluchowsky’s equation. The effect of pH (pH ranged of 2 to 10) on the electrolyte solution and the compositions of the membranes was analyzed. The obtained results indicate that the modification of DPPC membranes with both Dio and DAc causes changes in surface charge density values and shifts of the isoelectric point.

Gas/water foams stabilized with a newly developed anionic surfactant for gas mobility control applications

Carbon dioxide (CO2) flooding is one of the most globally used EOR processes to enhance oil recovery. However, the low gas viscosity and density result in gas channeling and gravity override which lead to poor sweep efficiency. Foam application for mobility control is a promising technology to increase the gas viscosity, lower the mobility and improve the sweep efficiency in the reservoir. Foam is generated in the reservoir by co-injection of surfactant solutions and gas. Although there are many surfactants that can be used for such purpose, their performance with supercritical CO2 (ScCO2) is weak causing poor or loss of mobility control. This experimental study evaluates a newly developed surfactant (CNF) that was introduced for ScCO2 mobility control in comparison with a common foaming agent, anionic alpha olefin sulfonate (AOS) surfactant. Experimental work was divided into three stages: foam static tests, interfacial tension measurements, and foam dynamic tests. Both surfactants were investigated at different conditions. In general, results show that both surfactants are good foaming agents to reduce the mobility of ScCO2 with better performance of CNF surfactant. Shaking tests in the presence of crude oil show that the foam life for CNF extends to more than 24 h but less than that for AOS. Moreover, CNF features lower critical micelle concentration (CMC), higher adsorption, and smaller area/molecule at the liquid–air interface. Furthermore, entering, spreading, and bridging coefficients indicate that CNF surfactant produces very stable foam with light crude oil in both deionized and saline water, whereas AOS was stable only in deionized water. At all conditions for mobility reduction evaluation, CNF exhibits stronger flow resistance, higher foam viscosity, and higher mobility reduction factor than that of AOS surfactant. In addition, CNF and ScCO2 simultaneous injection produced 8.83% higher oil recovery than that of the baseline experiment and 7.87% higher than that of AOS. Pressure drop profiles for foam flooding using CNF was slightly higher than that of AOS indicating that CNF is better in terms of foam–oil tolerance which resulted in higher oil recovery.

An experimental evaluation of low salinity water mechanisms in a typical Brazilian sandstone and light crude oil with low acid/basic number

Low salinity water injection (LSWI) is a current and cost-effective method to enhance oil recovery by changing the salinity and composition of the injected water. However, the synergistic effect of chemical composition, concentration and in particular the pH of the brine in oil recovery during LSWI remains not well understood. In addition, there is a lack of low salinity studies in Brazilian sandstone rocks and light paraffinic crude oils of low acid/basic number to date. This paper investigates oil recovery mechanisms and the pH effect in high and low salinity brine solutions using samples from a clastic reservoir in Recôncavo basin, northeastern Brazil. Zeta potential and interfacial tension measurements, oil adsorption analysis using a quartz crystal microbalance with dissipation monitoring, and core flooding experiments were performed using different concentrations and pH values of synthetic formation water (SFW), NaCl and CaCl2 brine solutions. The results indicate that when the reservoir pH changes towards the alkaline conditions driven by ionic exchanges during LSWI, it may approximate the isoelectric point (IEP) of pH-dependent surface charges in oil and rock minerals, weakening the electrostatic attraction between their surfaces, and consequently contributing to increased oil recovery. The findings of this study can help understand oil recovery mechanisms during LSWI according to the type and content of pH-dependent surface charges in sandstone rocks and crude oils. This study also shows how to pre-select potential field candidates in the Recôncavo basin and similar formations for stand-alone and hybrid LSWI applications.

Polymer or microgel particle: Differences in emulsifying properties of pectin as microgel or as individual polymer chains

The differences and similarities in the emulsion stabilising behaviour of pectin as individual polymer chains or as pectin-based microgels (particulate polymer network) were investigated. To compare the emulsifying properties and the adsorption mechanism, oil-in-water emulsions were produced with either pectin as individual polymer chains or as pectin-based microgels. The droplet size distribution of polymer stabilised emulsions varied depending on the used pectin type (apple and citrus pectin or pectinic acid). However, when microgel particles were used, the droplet size distribution remained constant, regardless of the pectin type. Further investigations were conducted with pectinic acid, due to comparable emulsification results when used as individual polymer chains or as microgel particle. Interfacial tension measurements revealed that microgel particles made from pectinic acid do not affect the oil-water interfacial tension, whereas pectinic acid as individual polymer chains decreases its value. This shows that microgels prepared with pectinic acid stabilise emulsions with a completely different mechanism than pectinic acid as individual polymer chains. The effect of the homogenising pressure difference on the droplet size distribution was investigated to gain further insight into the stabilizing mechanism. Emulsions stabilised with pectinic acid as individual polymer chains showed increased coalescence with increasing pressure difference, whilst emulsions stabilised with pectinic acid as microgel particles were not affected by an increase in the pressure difference. The gained knowledge can help to choose suitable process and formulation parameters for applications in which pectin is used as an emulsifier, whether as an individual polymer chain or as a microgel particle. For example, when high homogenisation pressure differences are required, microgel particles are more suitable than pectin as individual polymer chains, due to the low oil droplet coalescence. On the other hand, when high concentrations of emulsifying agent is required, pectin as individual polymer is the more appropriate choice.

Effects of CO2-foam stability, interfacial tension and surfactant adsorption on oil recovery by alkaline-surfactant-alternated-gas/CO2 flooding

In this study, experimental investigations were carried out to develop optimum chemical formulations for alkaline-surfactant-alternated-gas/CO2 (ASAG) flooding based on the combined effect of forming strong/stable foam, achieving ultra-low interfacial tension (IFT), and lowering surfactant adsorption. First, laboratory experiments were aimed to formulate the chemical slugs on the basis of CO2-foam stability, IFT measurements, phase behavior tests, and dynamic adsorption studies. Second, formulated chemical slug was tested with and without alternated gas/CO2 injection in field reservoir cores through core flooding experiments for a better insight into the oil recovery processes. The results indicated that CO2-foam stability decreased with the increased in temperature and maximum stability was achieved at specific surfactant concentrations. Adding alkali at optimum concentrations decreased the oil-water IFT values of the alkali-surfactant (AS) formulations to ultra-low values (0.0068 mN/m and 0.0087 mN/m). 70 % of formation brine salinity was identified as the optimal salinity through phase behavior tests, where the equilibrium IFT was also the lowest. The results of the dynamic adsorption studies showed that adding alkali could reduce surfactant adsorption from 1.41 mg/g to 0.52 mg/g. Additionally, preflush with a secondary surfactant (black liquor, BL) at its CMC value further reduced surfactant adsorption to 0.21 mg/g. ASAG flooding resulted in incremental oil recovery of 8.35 % original oil in place over AS flooding which involved only chemical slug injection. The study suggests that alternate injection of AS solution and gas/CO2 in short slugs into low permeability reservoir cores can result in higher additional oil recovery due to in-situ foam formation and ultra-low IFT environment. Additionally, preflush with a low-cost surfactant significantly reduces primary surfactant loss due to adsorption thereby improving oil recovery by ASAG flooding.

Study of Asphaltene Precipitation during CO2 Injection into Oil Reservoirs in the Presence of Iron Oxide Nanoparticles by Interfacial Tension and Bond Number Measurements

CO2 injection is one of the most frequently used enhanced oil recovery methods; however, it causes asphaltene precipitation in porous media and wellbore and wellhead facilities. Carbon dioxide saturated with nanoparticles can be used to enhance oil recovery with lower asphaltene precipitation issues. In this study, the vanishing interfacial tension technique was used to investigate the possibility of diminishing asphaltene precipitation by nanoparticles. The interfacial tension (IFT) of synthetic oil/carbon dioxide was measured using the pendant drop method. The results illustrated that, for synthetic oil samples containing asphaltene, the IFT data versus pressure decrease linearly with two different slopes at low- and high-pressure ranges. At high pressures, the slope of the plot is lower than the one in the low-pressure range. The addition of iron oxide nanoparticles to the oil solution reduces the interfacial tension at higher pressures with a steeper slope, showing that nanoparticles can decrease asphaltene precipitation. The plot of Bond number versus pressure also confirmed the impact of nanoparticles on reducing asphaltene precipitation. In terms of the temperature effect, the presence of nanoparticles at 50 °C resulted in a 16.34% reduction in asphaltene precipitation and a 19.65% reduction at 70 °C. The minimum miscibility pressure changed from 10.17 to 30.96 MPa at 70 °C; however, in the presence of nanoparticles, it reduced from 10.06 to 16.56. Therefore, the technique introduced in this study could be applied to avoid the problems associated with altering the gas injection mode from miscible to immiscible.

Hybrid of quantum dots for interfacial tension reduction and reservoir alteration wettability for enhanced oil recovery (EOR)

Nanoparticle stabilized emulsions in enhanced oil recovery are more attractive and practical than conventional emulsions which stabilized by colloidal particles and different surfactants due to their advantages and special characteristics such as high stability in harsh condition, move long distance in reservoirs without high retention due to small size of nanoparticles. Only one third of original oil in place (OIP) is usually produced and two third of oil in place will be trapped to reservoir rockthus suitable chemical enhanced oil recovery (C-EOR) methods should be used. In this research, we have suggested a novel, economical and commercial method for synthesis N-doped graphene quantum dots (N-GQDs)/MoS2 quantum dots (MQDs) nanohybrids for preparing different percentage of Nanoemulsions which can reduce alterfacial tension significantly so it can used for Enhanced Oil Recovery (EOR) application. MoO3 material was used as a base of MQDs. MQDs was synthesized via exfoliation of MoS2 nanoparticles by Butyl lithium under N2 atmosphere condition. N-GQDs were synthesized by citric acid and urea materials via hydrothermal method. GQDs/MQDs were prepared via a simple sol-gel method for 5 h string. Synthetic materials were characterized with X-ray diffraction (XRD), Fourier transform infrared (FT-IR), UV–visible absorption, Scanning Microscopic Electron (SEM), EDX profile and mapping, Transmission electron microscopy (TEM), High Resolution Transmission electron microscopy (HRTEM) and differential scanning calorimetry (DSC). Then, emulsions were prepared with two different cationic and anionic surfactants and the stability and morphology of emulsion droplets were investigated in condition close to reservoir environment. Our results show that 10% GQDs/MQDs in cationic surfactant and 50% GQDs/MQDs in anionic surfactant have good stability and very small and fine emulsion droplets in simulated reservoir conditions in laboratory. The Interfacial Tension (IFT) measurement shows >70% improvement which indicates the high ability of these nanohybrids in reducing the surface tension than previous nanohybrids. Contact angle values show that these nanohybrids can alter the wettability of reservoir rock from oil-wet to water-wet so the trapped oil in the porous region of rock can be easily extracted in the presence of a layer of these nanohybrids. Furthermore, according to the results of altering the density and viscosity of nanohybrids, these are not as limiting parameters and only about 1% increasing observed for density and viscosity, respectively. Coreflooding test revealed the high oil recovery efficiency (22%) at very low nanofluid concentration (0.01 wt%).

Effects of synthesized nanoparticles and Henna-Tragacanth solutions on oil/water interfacial tension: Nanofluids stability considerations

Rising global energy demand has encouraged engineers to create and design new methods to improve oil recovery from reservoirs. In this study, feasibility of using Henna extract as a natural surfactant and synthesized nanoparticles (Titanium dioxide (TiO2), Silicon dioxide (SiO2), Graphene and composite of TiO2-Graphene) for reduction of oil-water interfacial tension has been experimentally investigated. Nanoparticles were synthesized via sol-gel method and XRD, FESEM, EDAX and FTIR tests were conducted to confirm the authenticity of this synthesizing materials. Nano-surfactants were stabled with a natural water-based suspending surfactant called Tragacanth extract, which could be introduced as a practical substitute for industrial nanoparticles' stabilizers in oil industry. After CMC determination of Henna extract surfactant, the optimal concentration of Tragacanth extract surfactant, with the purpose of nano-surfactants’ stabilization, was determined through particle size and zeta potential tests. Results of interfacial tension (IFT) measurements showed that the increase of Henna extract concentration from 0 wt% to 10 wt% reduced IFT between kerosene and water from 37.23 to 15.24 mN/m. Furthermore, adding 1 wt% of synthesized TiO2 nanoparticle to the Henna extract surfactant at its CMC value reduced IFT from 18.43 to 14.57 mN/m. As an impact of this significant reduction in IFT value, oil recovery factor could be improved drastically during EOR operations. Results proved that TiO2 nano-surfactant was as effective as industrial surfactants, which put human's and environment's health at risk and impose heavy economic strain on governments.

Nucleation kinetics of clopidogrel hydrogen sulfate polymorphs in reactive crystallization: Induction period and interfacial tension measurements

Nucleation kinetics of clopidogrel hydrogen sulfate polymorphs has been investigated in the mixture of 2-butanol and ethyl acetate by reactive crystallization. The effect of supersaturation and temperature on the nucleation rate was researched by measuring the induction period. The results show that the induction period decreases with the increase of supersaturation and temperature. After identifying the form of nuclei, the results disclose the metastable form seems to favor generating at a high supersaturation level. The reasons have been explained from the view of critical nucleation size. The interfacial energy of two polymorphs (20 °C, γslI = 4.49 mJ/m2, γslII = 4.94 mJ/m2; 25 °C, γslI = 5.60 mJ/m2, γslII = 6.27 mJ/m2) was also determined from induction time. The value calculated of Form II at 25 °C was close to the ones obtained from directly methods: by contact angle measurement (6.85 mJ/m2). The effect of different contents of ethyl acetate on the induction period at 20 °C was also explored. The results reveal the addition of a small amount of ethyl acetate can significantly promote nucleating.

Efficiency of Urea Solutions in Enhanced Oil Recovery.

We examine the applicability of urea solutions as a novel cost-effective chemical for enhanced oil recovery processes. Two sandpack flooding experiments were conducted using 5 and 10 wt % urea solutions. Another flooding experiment was also carried out using the same sandpack with fresh water and used as a reference. Supporting experiments such as interfacial tension (IFT), viscosity of water in oil (W/O) emulsions, total acid number (TAN), and Fourier-transform infrared (FTIR) spectroscopy were conducted to confirm the generation of in situ surfactants by reacting urea solutions with the naphthenic acids in bitumen and evaluate their impact on the oil recovery. The analyses of FTIR, IFT, TAN, and viscosity measurements support the generation of in situ surfactants that leads to the formation of stable water in oil emulsions and hence a more stable displacement front resulting in higher oil recovery.

Brine composition effect on the oil recovery in carbonate oil reservoirs: A comprehensive experimental and CFD simulation study

In order to understand the potential role of divalent ions involved in smart water, fluid-fluid and rock-fluid interactions are studied through contact angle and interfacial tension (IFT) measurements. Then, the suitable brines in changing contact angle and IFT are brought into measurement with spontaneous imbibition experiments to evaluate the co-impact of fluid-fluid and rock-fluid interactions. The results show the importance of SO42− ions during smart water injection as removing them from the injection water leads to a sharp drop in ultimate oil recovery. Accordingly, when the concentration of SO42− within the injection water increases four times, 10% ultimate oil recovery is recovered. Furthermore, the spontaneous imbibition measurements exhibit the higher ultimate oil recovery from the neutrally-wet core plugs more rather than the strong water-wet plugs. Further elaborating about the effect of wettability on the pore-scale displacement of oil by injection water is conducted through Computational Fluid Dynamics (CFD) modelling. The results confirm that the lowest residual oil saturation is achieved in the model with neutral wettability state as well as the highest oil recovery which is in line with the piston-like displacement in the neutral wet rock medium.

Hydroxyl-functionalized silicate-based nanofluids for enhanced oil recovery

During the production life of the reservoir, wettability alteration from an oil-wet to a strongly water-wet condition and/or lowering the interfacial tension (IFT) between the water and oil phases is required at various stages to enhance oil recovery (EOR). Several chemical agents as potential wettability modifiers (e.g., surfactants and polymers) have been regarded and widely used in oil-wet systems. Recently, various nano-fluids, prepared by dispersing nanoparticles in brine solutions or solvents, have attracted attention as injecting fluid due to their unique properties. A large number of nanoparticles are being investigated for EOR applications either as stand-alone or in combination with surfactants and/or polymers. Because of its stability in brine even at low concentrations, totally or partially hydroxyl-functionalized nano-pyroxenes are capable of recovering additional oil after water flooding. However, the influence of their concentration on various parameters has not been previously investigated. Thus, in this study, we investigated the influence of nano-pyroxene on wettability, IFT and asphaltene aggregation. Wettability measurements were performed by contact angle measurements, imbibition experiments and wettability index to understand the underlying mechanisms. The interaction between nanopyroxene and asphaltene size distribution was investigated as a function of nanopyroxene concentration by dynamic light scattering (DLS) measurements. Results from the IFT measurements, contact angle, imbibition experiments and core flooding tests confirm that nanopyroxene affects oil recovery. Contact angle and wettability index measurements confirmed that adsorption of the nanoparticles on the rock surfaces alters the wettability from intermediate wet to stronger water-wet in the absence and presence of initial water films. In the presence of irreducible water saturation during wettability index measurements, depending on the brine composition and pH, initial alteration with aging resulted in a mixed or intermediate wet that changed to stronger water-wet as the nanopyroxene concentration increased. Moreover, increasing the concentration of nanopyroxene resulted in a noticeable IFT reduction but not an ultra-low range that can remobilize trapped oil due to higher capillary forces. Core flooding tests indicated that nanopyroxene-based nanofluid injection offers ~12–14.5% additional oil in addition to waterflooding.

Spectroscopic analysis of the adsorption of carbon based nanoparticles on reservoir sandstones

The development of effective recovery techniques that can resolve the complexities of high interfacial tension (IFT), high viscosity and wettability in petroleum reservoirs will aid efforts to meet the world’s growing energy demands. Nanoparticles prove to be able to form adsorption layers on surfaces of sandstone and significantly change wettability and IFT. Despite the remarkable properties of graphene nanopaticles, not many studies have researched their potential application in EOR. In this study, sandstone coreplugs infused with crude oil, brine and carbon nanofluids (carbon nanocomposite and graphene) were characterized using field emission scanning electron microscopy (FESEM), Fourier Transform Infrared (FTIR), Raman spectroscopy, and X-ray photoelectron spectroscopy (XPS). IFT measurements were performed for oil/brine/CNPs and graphene nanofluid. The measured IFT values for brine/oil, carbon nanofluid/oil and graphene nanofluid/oil are 39–40 mN/m, 41–44 mN/m, and 9.8–11.4 mN/m, respectively. Spectroscopic analyses show that graphene has a stronger interaction (higher adsorption) on sandstone compared to the normal carbon nanoparticles, which is indicated by the lower Si–O Raman, lower FTIR transmittance for C–H peaks and the emergence of loss feature phenomenon in the XPS spectra of graphene infused with sandstone. The relatively lower FTIR transmittance intensities, well distributed carbon atoms and detected D' and D+D' Raman shifts also support the high interaction of graphene with oil and rock surface. The higher IFT reduction by graphene nanofluids is attributed to the combined high hydrophobicity and hydrophilic natures, which provides a dynamism for their detachment at the biphasic liquid/fluid interface.

Synthesis and application of castor oil maleate and castor oil maleate-styrene copolymers as demulsifier for water-in-oil emulsions

Oil industry has encountered a series of difficulties associated with flow assurance of petroleum fluids, especially those related with stable emulsion formation. Such emulsified systems could present problems during transportation, handling, and refining, because of their relation to operational factors, as follows: fluid viscosity, processing energy expenditure, and water coproduction. For this reason, the addition of interfacial active compounds, often polymers, is used in an attempt to phase separation in industrial processes. In this paper, five different chemical surfactants, referred to here as MACO 1, MACO 2, R1, R2, and R3, were synthesized based on castor oil. These additives were characterized by Fourier Transform Infrared (FTIR), Size-Exclusion Chromatography (SEC), and Thermogravimetrical Analyses (TGA). The demulsification activity was studied in synthetic emulsions by using two Brazilian crude oils and 30% (v/v) brine cut with 60 and 240 g/L NaCl, at neutral pH, and average droplet diameter of 10 μm. Bottle tests were carried out at 60 °C in graduated ASTM test tubes for 2 h, varying additive concentration from 100 to 5000 ppm. Interfacial tension measurements were performed to elucidate the demulsification activity in water-oil interface, at the same bottle test experimental conditions. These results were discussed on the basis of the oil characterization, mechanisms of demulsifying action, as well as interfacial tension data. Ward and Tordai equation was applied according to asymptotic approximations to evaluate additives diffusivity. The results show that demulsification is more significant for MACO 1, with maximum water resolution of around 90% for both emulsion systems.