Interfacial Tension Reduction Research Articles

A Molecular Dynamics Study on Low-Pressure Carbon Dioxide in the Water/Oil Interface for Enhanced Oil Recovery

SummaryThe microscopic displacement efficiency of supercritical carbon dioxide (CO2)-based enhanced oil recovery (EOR) depends critically on the phase behavior of CO2 and residual oil. Traditionally, we assume that the main drive mechanisms of supercritical CO2 EOR are attributed to oil swelling and reduced oil viscosity, and research focuses on how the supercritical CO2 interacts with remaining oil under the reservoir conditions. However, our recent study finds that once the CO2 is introduced into the reservoir, CO2 partitions into the aqueous and oil phases, reducing the interfacial tension (IFT) between the oil and water. This is particularly important when CO2 is generated through a series of chemical reactions for in-situ CO2 EOR. In this paper, we used molecular dynamics (MD) simulations to study the interfacial properties between water and oil with different mole fractions of CO2 in pressures below the minimum miscibility pressure. Simulation results show that with the increase in CO2 mole fraction, rather than evenly distributed in phases, CO2 molecules are prone to concentrate in the water/oil interface region, which decreases IFT between the aqueous phase and oil. Furthermore, the effect of CO2 orientation on the water/oil IFT reduction was observed. The change of CO2 concentration affects CO2 orientation near the interface, which in return dominates the IFT change.

Spontaneous Imbibition Oil Recovery by Natural Surfactant/Nanofluid: An Experimental and Theoretical Study.

Organic surfactants have been utilized with different nanoparticles in enhanced oil recovery (EOR) operations due to the synergic mechanisms of nanofluid stabilization, wettability alteration, and oil-water interfacial tension reduction. However, investment and environmental issues are the main concerns to make the operation more practical. The present study introduces a natural and cost-effective surfactant named Azarboo for modifying the surface traits of silica nanoparticles for more efficient EOR. Surface-modified nanoparticles were synthesized by conjugating negatively charged Azarboo surfactant on positively charged amino-treated silica nanoparticles. The effect of the hybrid application of the natural surfactant and amine-modified silica nanoparticles was investigated by analysis of wettability alteration. Amine-surfactant-functionalized silica nanoparticles were found to be more effective than typical nanoparticles. Amott cell experiments showed maximum imbibition oil recovery after nine days of treatment with amine-surfactant-modified nanoparticles and fifteen days of treatment with amine-modified nanoparticles. This finding confirmed the superior potential of amine-surfactant-modified silica nanoparticles compared to amine-modified silica nanoparticles. Modeling showed that amine surfactant-treated SiO2 could change wettability from strongly oil-wet to almost strongly water-wet. In the case of amine-treated silica nanoparticles, a strongly water-wet condition was not achieved. Oil displacement experiments confirmed the better performance of amine-surfactant-treated SiO2 nanoparticles compared to amine-treated SiO2 by improving oil recovery by 15%. Overall, a synergistic effect between Azarboo surfactant and amine-modified silica nanoparticles led to wettability alteration and higher oil recovery.

Enhanced oil recovery mechanism with nanofluid injection

The development and application of enhanced oil recovery technologies using nanofluids have been observed in last decade. It was found that the use of these reagents leads to the wettability alteration of the pore walls of the rock, an interfacial tension reduction, a decrease in oil viscosity, and an increase in the disjoining pressure. This paper presents the results of studying the displacement of residual oil on homogeneous quartz sandstone using the nanofluids, obtained by peptizing the sediments in a mixture of seawater with calcium and magnesium salts. Nitric and organic acids were used as peptizing agents. When using the developed nanofluids, an increase in oil production by 15-20% was achieved in comparison with seawater. A new approach for the mechanism of action of nanoparticles on the formation, leading to an increase in oil production, is proposed. Keywords: oil recovery; displacement efficiency; nanofluid; peptization; wettability alteration; interfacial tension.

The effect of mixed micelle formation on the dynamics of phase partitioning for a polydisperse ethoxylated nonionic surfactant

AbstractMixed surfactants are common in practical applications, and their behaviors are often observed to deviate from the behaviors of pure surfactants with similar average properties in striking, and sometimes unexpected ways. The focus of this work was on exploring the role of mixed micelle formation in a mixed ethoxylated nonionic surfactant on the dynamics of partitioning between immiscible phases. The work examined partitioning of an ethoxylated nonylphenol surfactant between water and tetrachloroethylene (PCE) in a stagnant system at two different phase volume ratios. A model describing partitioning rate was developed and calibrated to experimental data, and then used to predict the long‐term dynamic approach to equilibrium in mixed and pure systems. The work suggests that micelle formation slows partitioning time by limiting the concentration of monomers in water; in pure systems, time to approach equilibrium increases with increasing concentration, but then reaches a maximum. However, in mixed systems, time to approach equilibrium continues to increase with increasing concentration over the physically‐possible concentration range. For the mixed system studied here, partitioning could be expected to take two orders of magnitude longer at very high concentrations than a similar pure system. Because of the similarity of the mathematics, this result might be expected for any monomer‐driven interaction, such as adsorption or interfacial tension reduction.

Mechanism responsible altering in interfacial tension and emulsification of the crude oil-water system with nano Gemini surface active ionic liquids, salts and pH

Gemini surface active ionic liquids (GSAILs) exhibit desired activities for enhanced oil recovery (EOR). This study explores the simultaneous effects of homologous series of imidazolium nano GSAILs, [Cnim-C4-imCn][Br2], n = 4, 8, and 12 with individual and mixture of NaCl, MgCl2 salts and also with aqueous phase pH on the crude oil–water system. In the presence of the medium and long alkyl chain GSAILs, electrolytes can establish extra 93.1 and 52.6% reductions in interfacial tension (IFT) and the critical micelle concentration (CMC), compared to the salt-free system, respectively. These were while, the IFT and the CMC were initially decreased with the concentration of electrolytes and then a slight increase was corresponding with the short alkyl chain GSAIL. Results also revealed 79.2% more IFT reductions under pH 9.5 compared to the natural pH as well as high stability of GSAILs within the wide pH range of (2.5–9.5). Meanwhile, crude oil and electrolyte aqueous solutions showed one day emulsification indices within (40–85)% with little decrease after one week. Remarkably, an emulsification index of more than 90% could be achieved at pH 9.5.

Experimental evaluation of non-ionic mixed surfactant formulations at high-temperature and high-salinity conditions

Non-ionic alkyl polyglucoside (APG) surfactants have been considered as eco-friendly, nontoxic and biodegradable surfactants. This study investigated the feasibility and advantages of new formulations for mixed surfactants consisting of a commerical APG product and one of the following alkyl amines (AAs) – dodecylamine (C12A), tetradecylamine (C14A), hexadecylamine (C16A), and octadecylamine (C18A) for improved oil production applications in carbonate reservoirs under high-temperature and high-salinity (HTHS) conditions. The physicochemical properties including compatibility, surface tension, interfacial tension (IFT), static adsorption, wettability alteration of the solutions comprising APG and various AA under HTHS conditions were evaluated. The self-assemble behavior of molecules between APG and C12A was characterized based on the Scanning Electron Microscopy (SEM) analysis. The formulations with an ultra-low IFT were introduced and the mechanisms resulting in such ultra-low IFT were further studied and discussed. The yielded APG/AA formulation was injected as the chemical flooding agent into a micromodel to investigate the efficiency of oil displacement. Commercial APG products exhibited excellent compatibility with the simulated injection water at reservoir temperature. After mixed with AA, the APG solution became hazy or phase separated above a critical concentration (Ccrit) of AA. Ccrit was found to decrease with an increase of the hydrocarbon chain, suggesting that more APG surfactants are required to solubilize the AA with longer alkyl hydrocarbon chain. In the presence of AA, the critical micelle concentration (CMC) of APG surfactant significantly reduced due to the formation of a compact micellar structure. APG yielded a low IFT at 90 °C and a concentration of 2 g/L in the order of 10−2 mN/m, while an ultra-low IFT in the order of 10−3 mN/m was obtained upon addition of a small amount (0.3–0.5 g/L) of C12A. SEM images and proposed IFT reduction mechanisms indicated that APG and C12A synergistically generated a more compact structure via hydrophobic interaction between the hydrophobic moieties and hydrogen bonding between the hydrophilic parts of the chemicals comparing the aggregated structure formed by APG alone, such effect could eventually lead to a decrease in IFT between oil and water. The amounts of chemical adsorption and contact angle of an oil droplet on carbonate cores were not affected upon addition of AA. The micromodel test showed that the produced oil by injection of the designed APG/AA formulations was further enhanced after water flooding. Among the formulations, APG/C12A flooding resulted in a highest effectiveness on oil displacement with a cumulative oil production of 78.7% at the end of injections. To sum up, new APG/AA-based formulations were designed with an ultra-low IFT resulting from a much compact amphiphilic structure along oil-water interface. This study shows a great potential of APG surfactant and the related formulations in improving oil production for HTHS carbonate reservoirs.

Dissipative particle dynamics simulation and experimental analysis of effects of Gemini surfactants with different spacer lengths on stability of emulsion systems

Understanding the effects of the structure of surfactants on the interfacial properties and dynamic processes of emulsions is critical for the rational design and selection of surfactants for the formation of stable emulsions. In this study, a series of Gemini cationic surfactants with different spacer lengths and an anionic surfactant were examined. The effects of single surfactants, as well as mixed surfactant systems, on the interfacial properties of oil/water systems were systematically investigated using dissipative particle dynamics simulations. The Gemini surfactants were modeled as “π-shaped” coarse-grained molecules with different spacer lengths to examine variations in their properties, including the radial distribution function, interfacial tension, and interfacial thickness. We found that Gemini surfactants with shorter spacers exhibit better surface activity. Longer spacers result in the binding of more oil molecules to the chain, which reduces the surface activity. The effect of mixed surfactant systems on the reduction of interfacial tension is significant. Emulsion systems constructed from anionic surfactants and Gemini cationic surfactants with shorter spacers exhibited a lower sedimentation index after aging. Emulsion models were able to capture the dynamic process of emulsion breaking at the microscopic level and were used to analyze the effects of surfactants on emulsion stabilization. Based on the analysis of the effect of surfactants on the oil-water interface, this work further analyzes the effect of surfactants on the stability of emulsions. In addition, an ingenious emulsion system is established, which provides a basis for the rational design and selection of high-efficiency surfactants to prepare stable emulsion systems.

Interfacial tension of brine-oil interface using Fe2O3, ZnO, and SiO2 nanoparticles endorsed by electromagnetic waves

The interaction of nanoparticles (NPs) with crude oil in a porous media activated by electromagnetic (EM) waves is projected to be a crucial approach to reduce interfacial tension (IFT) for the achievement of oil productivity. Various NPs were reported to have been used in the oil reservoirs and found to reduce IFT between fluids and crude oil. However, the NPs undergo a persistent problem of perpetual detachment at the fluids/oil interface caused by the high temperature of the reservoir which renders the NPs inactive. Hence, NPs need to be activated to increase their task accomplishment for higher IFT reduction. The present study investigates the effect of EM waves on activating NPs of Fe2O3, ZnO, and SiO2 upon IFT reduction using brine as the base fluids. The results have shown a reasonable reduction for the IFT when NPs were used. But the additional reduction was observed upon introducing the energy to the NPs via EM waves. The significant change was ascribed to the good electrical conductivity of the NPs that encourages the ions to polarize and rapidly absorb the energy propagated from EM waves. Consequently, the IFT (mN/m) was reduced from 12.50 to 4.45, 12.50 to 1.16, and 12.50 to 3.38 for ZnO, Fe2O3, and SiO2 NPs respectively. The present study is significant in proving a vital insight into the impact of EM waves for supporting NPs to reduce the effect of attractive forces between oil and fluids for the achievement of oil mobility.

Role of surfactant-induced Marangoni effects in droplet dynamics on a solid surface in shear flow

We address the dynamics of a surfactant-laden droplet on a solid surface in simple shear flow numerically. Our analysis uses the front-tracking method to take surfactant transport into account. The interfacial tension and the slip coefficient, both of which depend heavily on the surfactant concentration, are fully integrated into the generalized Navier boundary condition to model the moving contact lines. Accurate prediction of droplet motion indicates that the surfactant can change droplet behavior drastically. Surfactant-induced effects, such as interfacial tension reduction, the Marangoni stress, and wettability alternation, are investigated for various capillary numbers, surface wettabilities, elasticity numbers, and surface Péclet numbers. Deformation and motion of a sliding droplet are enhanced by the Marangoni effect, which is associated with an interfacial tension gradient. When the capillary number reaches a critical value, the sliding-to-detachment and detachment-to-pinch-off transitions occur. Both transitions can be triggered and accelerated by a surfactant, especially when convection is dominant. As a result, the critical capillary number decreases, but exhibits a non-monotonic relationship with the elasticity number and Péclet number. The mechanisms that underlie the effect of Marangoni stress are discussed by analyzing the distributions of the surfactant concentration and the hydrodynamic forces exerted on the droplet. Accumulation of surfactants near the receding contact line reverses the local concentration gradient, attempts to change its direction along the interface, and delays droplet detachment. Furthermore, the strong surfactant dilution reduces both the surfactant concentration and the interfacial tension gradient, and thereby increasing the critical value for droplet pinch-off.

Imidazolium based ionic liquids for enhanced oil recovery on the carbonate reservoir

Improving the oil recovery by changing the wettability using chemicals often possess huge challenges in the harsh oil-wet carbonate reservoirs, such as chemical instability, high retention, lack of deliverability in the deep reservoir, etc. In this study, we investigated the adsorptive behavior of imidazolium-based ionic liquids (ILs) on the carbonate reservoir, and also evaluated their performance in the oil recovery using the high temperature and high pressure coreflood setup. The measured adsorption values are well within the limit of field requirements. In which, the ILs with longer alkyl chains had shown less adsorption than the shorter ones. Next, in the coreflood oil recovery studies, the injection of ILs after waterflooding increased the oil recovery by 12–26% additionally. As expected, the lengthier alkyl chain containing ILs work more effectively than the shorter chain ones. For a case of reference, we also studied a few conventional surfactants (anionic, cationic, nonionic, and zwitterionic). We also extracted the unsteady state two-phase relative permeability curves of the SW and ILs flooding coreflood experiments to understand the flow characteristics of oil and water while injecting SW, and ILs. It was observed that the ILs improved the oils’ flowability, kro, and reduced the water’s mobility, krw. All these experiments were performed at the Saudi Arabian reservoir conditions of 100 °C, and at 4500 psi confining pressure, and at high salinity (TDS = 240, 000 ppm). In addition, we also demonstrated the wettability and interfacial tension (IFT) measurements in order to analyze the oil recovery mechanism. It was noted that both the ILs and surfactants alter the rock wettability from strongly oil-wet into intermediate-wet, while in the IFT measurements, the surfactants outperformed the ILs. Hence, it can be conceded that the oil recovery with ILs was dominated by the wettability modification, and for the surfactants, it was the combined effect of both wettability alteration and interfacial tension reduction. The use of dilute concentration of ILs (10–500 ppm) can be considered as the most profitable, and the best alternative over the costlier surfactant flooding.

Effect of interfacial composition on the physical stability and co-oxidation of proteins and lipids in a soy protein isolate-(−)-epigallocatechin gallate conjugate emulsion

In this study, oil-in-water emulsions were co-stabilized by a soy protein isolate-(−)-epigallocatechin gallate (SPI-EGCG) conjugate, tea saponin (TS), and hexadecyltrimethylammonium bromide (CTAB) (0.01–1.00%, w/v), and the influence of the mixed SPI-EGCG-conjugate–surfactant interface on the physical stability and protein–lipid co-oxidation properties of each emulsions was investigated. Our results demonstrated that TS exhibits a better emulsifying ability than CTAB by significantly reducing interfacial tension; this emulsion contained the smallest particles at a TS concentration of 1.0% (w/v). In addition, the interfacial protein content revealed the existence of synergistic (CTAB) and competitive (TS) adsorption between the protein and surfactant. The presence of TS displaced protein molecules at the interface and inhibited protein oxidation, which reveals that proteins adsorbed at the oil–water interface are more sensitive to oxidation than unadsorbed proteins. The degrees of protein and lipid oxidation were enhanced in the presence of CTAB. Furthermore, the addition of TS delayed lipid oxidation; this phenomenon was most pronounced at a TS concentration of 1.0% (w/v). Our results indicate that combining SPI-EGCG conjugates with TS provides an optimal design for the development of nutritionally fortified products with longer shelf lives. • Effects of the surfactant concentration and type on the emulsions were investigated. • TS gave the best emulsification ability and effective interfacial tension reduction. • The co-oxidation of proteins and lipids occurred depending on the protein location.

FOAM STABILIZATION AND INTERACTIVE PROPERTIES OF KONO-BOUE CLAY NANOPARTICLES IN OIL RECOVERY

Different materials have been employed in chemical enhanced oil recovery (CEOR) to recover more residual oil from reservoir rock formations. Surfactants have been used though better recovery margin is expected when in conjunction with nanoparticles (NPs) (Silica and more recently clay). This combination reduces surfactant loss to the reservoir formation and enhances foam stability. The interactive properties and foam stability of locally available Kono Boue (KB) clay NPs were studied to establish its suitability for applications in CEOR. The KB clay NPs were synthesized using Sodium Dodecyl Sulphate (SDS) mediated (sol-gel) route and characterized with X-ray Diffraction (XRD), Energy Dispersive X-ray Fluorescence (EDXRF), Scanning Electron Microscopy (SEM), Fourier Transform Infrared (FT-IR) spectroscopy, Wettability alteration, Interfacial Tension (IFT) and Foam stability. The XRD and EDXRF confirmed the clay as Kaolinite (Al > 16 %; Si > 30 %). Surface morphologies showed platy polycrystallites of different sizes on the SEM while characteristic vibrations of Si-O stretching (780 and 1056 cm-1) and Al-OH bending (698 cm-1) vibrations were obtained from the FT-IR. Control of particle sizes (85, 63, 66, 60, 66 and 90 nm) was achieved using different concentrations (0, 2.08, 6.25, 8.33, 10.42 and 14.58 mM) respectively of SDS at constant clay particles (10 g). The samples were calcined at 900 °C for 2 h. IFT reduction between the oil and the aqueous media at constant SDS concentration increased with decrease in particle sizes from 85 to 60 nm. Similarly, wettability alteration also showed changes from nearly neutral-wet towards more water-wet condition with particle size variation. The foam stability experiment confirmed that the clay NPs with the least particle size of 60 nm gave the most stable foam.

THE SYNERGIZATION OF SILICA NANOPARTICLE AND SODIUM DODECYL SULFATE FOR CHEMICAL FLOODING APPLICATION

Nowadays, enhanced oil recovery is vital in improving the oil recovery. However, the oil productions keep depleting due to production problem such as high surface tension and interfacial tension reservoirs. Therefore, chemical flooding is one of the methods used in enhanced oil recovery. The synergy between Silica nanoparticle and Sodium Dodecyl Sulfate has been proposed as a compound for chemical flooding in enhanced oil recovery in this project. The major aim of this study was to measure the effectiveness of synergization between Silica (SiO₂) nanoparticles SDS with different injection ratio by measuring the oil recovery using chemical flooding. After the synergization of surfactant with nanosilica solution take place, the surface tension and interfacial tension test have been conducted to identify the optimum concentration. The results showed that the optimum concentration for SDS is 2000 ppm with surface tension (ST) and interfacial tension (IFT) are 33.5 and 36.0 mN/m respectively. When the SiO₂ nanoparticles were added, it showed that 6000 ppm was the optimum concentration with reduction in surface tension and IFT to 31.0 and 34.5 mN/m respectively. The 20,000 ppm brine and paraffin oil have been injected into the sandpack followed by waterflooding and chemical flooding. The results from the experiment presented that the oil recovery for waterflooding were in between 23% to 28% therefore, more oil left in the sandpack. Then, surfactant with nanosilica solution was injected with 20,000 ppm of brine as a slug with injection ratio in between 0.1 to 0.5 as tertiary recovery. It showed that the oil recovery increases up to 48% for 0.1 of injection ratio and 64% for 0.5 injection ratio. As a conclusion, it is proved that the synergization of SiO₂ nanoparticle and SDS is applicable for chemical flooding as tertiary recovery because in can recover up to 64% of oil production.

Catanionic Surfactants for Improving Oil Production in Carbonate Reservoirs

Summary This paper presents the development of catanionic surfactants composed of cationic and anionic surfactants to make them high-performance products for chemical flooding in high-temperature and high-salinity carbonate reservoirs. The objective of this study is to optimize the surfactant chemistry by mixing oppositely charged anionic surfactants and cationic surfactants (CASs), which results in significant synergistic effects in interfacial properties due to electrostatic attraction to improve oil production at the given harsh conditions. The optimal mixing surfactant ratios were determined according to the brine-surfactant compatibility, microemulsion phase behavior, and the interfacial tension (IFT) between oil and surfactant solutions in high-salinity brine at 90°C. Comprehensive performance of the catanionic surfactants was evaluated, including adsorption of the surfactants onto the carbonate rocks and the long-term stability at 95°C. The coreflooding displacement experiments were performed using carbonate core plugs at 95°C to evaluate the potential of the optimal catanionic surfactant in improving oil recovery. Three catanionic surfactants with good compatibility were developed in this study. It appeared that the synergistic effect between the mixing surfactants was enhanced with increasing temperature. Although the IFT of the individual surfactants with crude oil was between 10−1 and 100 mN/m, a significant IFT reduction in the magnitude of 10−2 to 10−3 mN/m was observed by mixing the selected anionic surfactants and CASs. A salinity scan showed that the IFT values maintained a value of 10−2 mN/m in a wide salinity range, which demonstrated the effectiveness of the catanionic surfactant. In microemulsion phase behavior studies, the developed catanionic surfactant solution in the presence of crude oil exhibited Winsor Type III emulsions. The static adsorption quantities of the catanionic surfactants were lower than the values of the individual surfactants. All these indicated the feasibility of catanionic surfactants for their applications in the harsh reservoir conditions. The results of coreflooding displacement tests demonstrated significant oil recovery improvement beyond waterflooding. This work provides an efficient way to get surfactant formulations by mixing oppositely charged surfactants to obtain high performance in improving oil production under harsh conditions.

The effect of hydroxyapatite nanoparticles on wettability and brine-oil interfacial tension as enhance oil recovery mechanisms

A novel concept of utilizing nanoparticles (NPs) to boost oil recovery and reduce entrapped oil in hydrocarbon reservoirs is being explored. The use of nanofluids (NFs) flooding to change wettability and reduce interfacial tension (IFT) between oil and water has been shown to be highly effective in experiments. Preparation and modification methods influence the performance of NPs. The application of hydroxyapatite NPs (HAP) in EOR has yet to be investigated. HAP was synthesized in this study using the co-precipitation method and in-situ surface functionalization with Sodium Dodecyl Sulphate SDS to visualize it effect on IFT reduction and wettability alteration under different salinity and temperature settings. To confirm the synthesis of HAP, zeta potential (ZP), Fourier transform infrared spectroscopy (FTIR), Particle size analysis (PSA), Transmission electron microscopy (TEM), and Energy dispersive X–ray (EDX) spectra were used respectively. According to the results, HAP was produced, and the particles were finely distributed and stable in aqueous solution. When the pH was altered from 1 to 13, the particles' surface charge rose from -5mV to −27mV, showing long-term stability in EOR processes. At salinity range from 5000 ppm to 30,000 ppm, and under temperature range from 25ᵒC to 80ᵒC, the HAP NFs changed the wettability of sandstone core from oil–wet at 111.7° to water–wet at 9.0°. In addition, at 0.1 wt% HAP concentration, the IFT was lowered to 3 mN/m. As a result, the HAP NF proved very effective in reducing IFT and altering wettability under both low and high salinity environments, and it is thus suggested for EOR operations.

Effects of brine valency and concentration on oil displacement by spontaneous imbibition: An interplay between wettability alteration and reduction in the oil-brine interfacial tension

Brine fluids have recently been of high interest to enhanced oil recovery process in both academia and industry. Both diluted formation brines and specifically formulated brines were reported to improve crude oil displacement in porous rock, owing to either their bulk salinity or brine-type. Mechanisms for such an improvement were widely proposed, including microscopic interfacial phenomena: wettability alteration and reduction in the oil-brine interfacial tension (σ), although their synergistic or interlinked contributions were vaguely clarified. To elucidate insights into this “low-salinity” enhanced oil recovery, crude oil displacement by spontaneous imbibition was conducted in the current research with focus on the effects of brine valency and concentration. Monovalent (NaCl) and divalent (CaCl2) brines at elevated concentrations (10, 100, and 1000 mM) were examined as imbibing fluids. Changes in the three-phase contact angle and the crude oil-brine interfacial tension were also investigated. Imbibition results showed that NaCl brine at ‘suitable’ concentration (100 mM) displaced greater oil (95.8 %) than too-low (10 mM) or too-high (1000 mM) concentrations, and these monovalent brines displaced more effective than those of divalent CaCl2 due to an oil-wetting as a result of divalent ion bridging phenomenon. This echoes crucial influences of both brine valency and concentration. Since no direct individual contribution from either the contact angle or σ on the oil displacement was obtained, an interplay between these two parameters were thought to control. The imbibition results were a capillary-dominated process (capillary number < 2.1 × 10−6), re-confirmed by their correlations with the calculated capillary pressures and inverse Bond numbers. The findings revealed that in a given imbibition system a required σ is a wettability-dependent: water-wet system needs high σ to enhance a driving capillarity while oil-wet system prefers lower σ to weaken a resisting capillary force. Brine formula directly attributed to wettability and σ: NaCl brines secure water-wetting with high σ while CaCl2 brines reduced σ more effectively with an assured oil-wetting. Low-salinity enhanced oil recovery mechanism was thus found to be contributed from capillary effect, which was an interplay between the interfacial tension and wettability. Paring these two parameters by formulating imbibing brine to anticipate high oil recovery is crucial and of challenge.

Investigation on novel redox-responsive ferrocenyl surfactants with reversible interfacial behavior and their recycling application for enhanced oil recovery

Stimuli responsive surfactants with reversible properties may effectively solve the problems of traditional surfactants (the switching of interfacial activity and the demulsification difficulty of emulsions) in enhanced oil recovery (EOR). In the present study, we fabricate brand-new redox-responsive double-tailed ferrocenyl surfactants 1,1′-ferrocenedicarboxylic acid-(N,N-dimethyldodecylamine)2 (FDA-(DMDA)2) via the dynamic supramolecular assembly. The reversible redox-responsive interfacial behaviors of ferrocenyl surfactants are estimated by measuring the interfacial tension reduction capacity, emulsifying performance, and wettability reversal ability. Compared with oxidized single-tailed ferrocenyl surfactant (FA-DMDA-Ox), oxidized double-tailed ferrocenyl surfactant (FDA-(DMDA)2-Ox) displays higher interfacial activity, which can be accurately switched by redox trigger. Cyclic micromodel flooding tests show that the FDA-(DMDA)2-Ox can in-situ emulsify the kerosene in pore media, and the addition of Na2SO3 to the produced fluid can achieve the recycle of the surfactants. Oil displacement tests demonstrate that the developed double-tailed ferrocenyl surfactants possess the potential in EOR and recycling.

A stabilized foam formulation using FTP‐SDS surfactants for wettability alteration and flow diversion in carbonate fractured oil reservoirs

AbstractFoam injection contributes to improved oil recovery through flow diversion, reduction of interfacial tension (IFT), and wettability alteration of the rock while its stability is an issue. In this article, nitrogen‐foam was optimally formulated using fluorocarbon tubiguard protect (FTP) surfactant stabilized with sodium dodecyl sulfate (SDS) co‐surfactant that was later experimentally considered for oil recovery in a fractured carbonate rock taken from an oil field in the Middle East. The results showed that the 5:1 volume ratio of fluorocarbon surfactant and SDS (FS51) generates a stable foaming agent with ability of changing the wettability of the carbonate rock surfaces to an intermediate gas‐wet state. A series of core‐flood experiments at HPHT conditions were also carried out and designed to properly represent matrix‐fracture media using both a horizontally and vertically oriented setup. The oil saturated cores were flooded with nitrogen gas first followed by foam injection. It was concluded that foam can divert the gas to flow from fractures to the matrix blocks and result in a significant oil recovery. The contact angle tests that performed after core‐flood experiments revealed the wettability changes of fracture surfaces from an oil‐wet to a gas‐wet state. This allows gas to be imbibed into the matrix blocks by capillary force and results in enhancement of ultimate oil recovery. This study revealed that trapped oil in matrixes blocks that had not been drained during the gas injection process could be produced by designing a stable foam that sustainably diverts injected fluid from fractures to matrix zone.

A novel hybrid nano-smart water with soluble chlorides and sulphates and silica-montmorilant-xanthan nanocomposite for EOR: Insights from IFT and contact angle measurements and core flooding tests

Injection of smart water mixed with various oil-water interfacial tension (IFT) reduction agents such as nanoparticles (NPs) into oil reservoirs is a proven enhanced oil recovery (EOR) method. A novel silica-montmorilant-xanthan was used to formulate novel hybrid nano-smart water solutions for EOR. Performance of the hybrid nano-smart water solutions as dispersion media at optimum salinity and NC concentrations was assessed. Stability, IFT, zeta potential, and wettability alteration of the solutions were assessed to find the optimum concentrations. Two groups of single and binary salts were used in the smart waters. Smart waters with individual NaCl, KCl, MgCl2, CaCl2, Na2SO4, MgSO4, CaSO4, and K2SO4 salts at concentrations of 1000, 2000, 4000, and 10,000 ppm in one group. Smart waters with a combination of each of the chlorates with various sulphates with equal ratios (1000/1000, 2000/2000, 4000/4000, and 10,000/10,000 ppm) in distilled water in another group. Smart waters with a combination of each of chlorates with various sulphates with equal ratios in distilled water in another group. Then the effects of the solution of these salts on IFT and contact angle in water-oil-sandstone and water-oil-carbonate systems were investigated. The optimum concentration of K2SO4+MgCl2 for the sandstone sample was determined as 1000/1000 ppm with 1000 ppm of the NC. The optimum concentration of MgSO4 for the carbonate sample obtained was 10,000 ppm with 250 ppm of the NC. The lowest IFT (15.42 mN/m) was obtained for the nanofluid with an NC concentration of 250 ppm. The results suggest that the salt-in effect and nano-film formation are behind the IFT reduction. Contact angle at the same NP concentration decreased from 109° (preferentially oil wet) to 33° (strongly water-wet) in the carbonate sample. For sandstone, the contact angle at the same NC concentration increased from 77° (preferentially water-wet to 117° - preferentially oil wet). Finally, we used the optimum formulas for core flooding to examine the performance of the prepared hybrid nano-smart water solutions. Using these novel hybrid nano-smart waters yields oil recoveries of up to 54% and 60% of the Oil Originally in Place (OOIP) in carbonate and sandstone samples, respectively.

Performance evaluation and mechanism study of a functionalized silica nanofluid for enhanced oil recovery in carbonate reservoirs

In this investigation, a functionalized SiO2 nanofluid was developed by integrating sodium oleate to mercapto-terminated nano-SiO2 via the thiol-ene “click” reaction. The developed nanofluid in the presence of higher concentrations (> 40,000 ppm) of NaCl at 70 °C was confirmed to be more stable than the original SiO2 nanofluid based on the outcomes obtained from precipitate observation, particle dimension, and zeta potential measurements. Successful integration of sodium oleate on the target nanoparticles was corroborated by a series of characterization approaches. Furthermore, the viscosity, contact angle, and interfacial tension (IFT) determinations were conducted to investigate nanofluids' potential for enhanced oil recovery (EOR). The results indicated that the viscosity of the functionalized SiO2 nanofluid (labeled FF-4) accounted for 3.48 cp after adding 40,000 ppm NaCl, while that of the original SiO2 nanofluid (labeled OF-4) was 1.15 cp. From the contact angle values, the carbonate rock surface was transformed from oil-wet (135°) to water-wet (72° and 38°) after being treated with the OF-4 and FF-4. The wettability alteration was attributed to the formation of the wedge film in the contact line area between the rock and fluids (oil sample and nanofluid). The functionalized nano-SiO2 helped to reduce IFT because of the simultaneous presence of the alkane chain (oleophilic) and carboxylate group (oleophobic) on the particle surface, making the functionalized nano-SiO2 have an amphiphilic structure. However, the original nano-SiO2 hardly changed IFT. Micro-model experiments showed that the OF-4 had a prominent oil displacement effect by changing wettability to a water-wet state and reducing the viscous fingering phenomenon. Core flooding tests demonstrated that the oil recovery factor of the FF-4 was almost 2.5 times that of the OF-4. Viscosity improvement was considered as a new oil recovery mechanism after wettability alteration and IFT reduction. This paper revealed the important properties of the functionalized nano-SiO2 and provided a novel efficient nanofluid for EOR in carbonate reservoirs.