Lowest Interfacial Tension Value Research Articles

Study on Emulsification Effect of Crude Oil in Brine Emulsions by Automated Demulsibility Tester

The purpose of the surfactants used is to greatly reduce the interfacial tension between the crude oil and brine, thereby decreasing the capillary number. The resulting oil-in-water emulsions are often grouped according to the Winsor theory. Oil recovery aims to produce Winsor type-III emulsions because they have the lowest interfacial tension values and the most favorable flow properties. The sensitivity of oil–water–surfactant systems to environmental influences (e.g., mixing speed and equilibration time) increases close to the favorable environmental range (temperature, brine total salt concentration, pressure, etc.) of the Winsor III type, the middle microemulsion phase, which is favorable for crude oil recovery. The tests aimed to investigate the quality and quantity of emulsions prepared with surfactants used in enhanced oil recovery (EOR) using an automatic device to characterize and select surfactants for industrial petroleum applications. An essential method for surfactant selection is to study the emulsifying effect and phase behavior. Phase behavior tests and emulsifying effect tests were performed on surfactants and surfactant packages as a function of mixing parameters. The mixing speed and mixing time can influence the results of the phase behavior and emulsifying effect tests, although during the investigations, other parameters were unchanged.

Optimizing Recovery of Fracturing Fluid in Unconventional and Tight Gas Reservoirs Through Innovative Environmentally Friendly Flowback Additives

Hydraulic fracturing, a method used to stimulate oil and gas from shale and tight formations, faces challenges like fluid blockage and fast declining oil or gas production rates due to the significant impact of capillary forces on water retention. To address this, surfactants and microemulsions are commonly employed as flowback additives to reduce surface and interfacial tension, enhancing water recovery during hydraulic fracturing. The effectiveness of flowback additives is highly impacted by harsh subsurface conditions, such as high salinity and high temperature. This study aims to assess the performance and effectiveness of methylimidazolium chloride-based ionic liquids as flowback additives at high salinities and temperatures.Different experimental analysis were conducted to screen different concentrations of methylimidazolium chloride-based ionic liquids (X1, X2, and X3). Surface tension measurements were conducted to estimate the critical micelles concentrations. A spinning drop tensiometer (SDT) was utilized to measure interfacial tension, in addition, contact angle measurements were used to evaluate the impact of the flowback additive on the wettability and the displacing behavior. Seawater was used as the base fracturing fluid with a salinity of 57,000 ppm and temperatures up to 90°c for all experiments. Coreflood experiments were conducted using tight formations to evaluate the regained hydrocarbon permeability and the fracturing fluid recovery in the presence of flowback additives.Various formulations, with surface tension values ranging from 30 to 45 mN/m and CMC values between 0.5 and 1 gallon per thousand units (gpt), were examined. The lowest interfacial tension value, notably 3 mN/m, was achieved with the X3 formulation. Ionic liquids demonstrated favorable surface tension reduction, where longer carbon chains led to lower values. Introducing diverse ions, especially divalent ions, enhanced the performance of ionic liquids. Interfacial tension measurements indicated a significant reduction with the addition of X3 to both 5 wt% KCl and the fracturing base fluid. Contact angle measurements revealed a shift towards greater water-wettability after treating the rock with flowback additives. Moreover, the use of ionic liquids improved permeability by 25%, enhancing fluid recovery to around 56%.According to our results, methylimidazolium chloride-based ionic liquids can be used as environmentally friendly flowback additives, especially in harsh conditions of high temperature and high salinity where the conventional additives are not suitable. This will contribute to the development of more sustainable and environmentally conscious practices in hydraulic fracturing operations. Ultimately, the utilization of these additives can help mitigate water blockage, reduce formation damage, and enhance shale gas production.

Synthesis and performance evaluation of polymeric surfactant from rice husk and polyethylene glycol for the enhanced oil recovery process

A tertiary recovery technique is needed to recover the remained oil in the oil field after primary and secondary recoveries, which can only recover approximately 30–50% of the total oil. This study investigated the synthesized polymeric surfactants from rice husk and polyethylene glycol (PEG) for the enhanced oil recovery (EOR) process as a tertiary recovery technique. The rice husk was used as sodium lignosulfonate (SLS) surfactant production feedstock. SLS-PEG polymer surfactant from rice husk has not been widely studied, especially for the EOR process. This study has comprehensively investigated the effect of PEG concentration on the polymeric surfactant properties. The surfactants were characterized using Fourier transform-Infrared (FT-IR) analysis. Several other tests were also conducted, including surfactant compatibility, viscosity, thermal stability, interfacial tension (IFT), and phase behavior. It was found that the PEG introduction to the SLS surfactant could increase the hydrophilic property of the polymeric surfactant due to the presence of the C−O−C group. In addition, the IFT value decreased with the increase in the PEG concentration due to the increase in the hydrophilic property. However, the IFT value decreased when the PEG concentration was too high. The lowest IFT value was obtained at the SLS to PEG ratio of 1:0.8. It produced the highest increase in the additional recovered oil after brine flooding. The results showed that the rice husk, which is agricultural waste, could be utilized as a feedstock for the surfactant production.

Interfacial tension of acidic heavy crude oil type and dolomite surface wettability: salinity and nanoparticles impact

ABSTRACT Waterflooding is the widespread method for displacing the residual oil toward well production because of its accessibility and low cost. Currently, several oil-rich countries are investigating to untangle the current shortcomings to make waterflooding method efficacious more. On the other side, salinity composition has been considered in enhanced oil recovery (EOR) for better sweep efficiency and has captured great interest for EOR techniques. In this study, oil–water interfacial tension (IFT) was measured between acidic heavy crude oil (AHCO) and brine solutions of MgCl2, CaCl2, KCl, NaCl, and Na2SO4 in various concentrations from 0.1 to 1 M and analyzed to obtain the highest IFT reduction. Moreover, the effects of AHCO and water composition on initial wettability of carbonate rock were investigated. The variations of surface properties of dolomite rock samples were investigated by contact angle (CA) measurements after aging thin sections in oil and brine. In addition, silica nanoparticles (NPs) as the IFT reducer and wettability alteration affordable agent were examined to compare their effects on salinity. The lowest IFT value between AHCO and brine solutions was reported 6.5 mN/m by magnesium chloride at 1 M concentration. Likewise, the highest impact on wettability alteration from oil-wet system (137.37◦) to strongly water-wet system (30.79◦) was obtained by magnesium chloride at 1 M concentration as well. Moreover, the application of silica NPs based on different salinity showed an inconspicuous impact in this study.

Application of ion-engineered Persian Gulf seawater in EOR: effects of different ions on interfacial tension, contact angle, zeta potential, and oil recovery

In this study, we initially performed interfacial tension (IFT) tests to investigate the potential of using the Persian Gulf seawater (PGSW) as smart water with different concentrations of NaCl, KCl, MgCl2, CaCl2, and Na2SO4. Next, for each salt, at the concentration where IFT was minimum, we conducted contact angle, zeta potential, and micromodel flooding tests. The results showed that IFT is minimized if NaCl or KCl is removed from PGSW; thus, for solutions lacking NaCl and KCl, the IFT values were obtained at 26.29 and 26.56 mN/m, respectively. Conversely, in the case of divalent ions, minimum IFT occurred when the concentration of MgCl2, CaCl2, and Na2SO4 in PGSW increased. Specifically, a threefold rise in the concentration of Na2SO4 further reduced IFT as compared to optimal concentrations of MgCl2 or CaCl2. It should be mentioned that eliminating NaCl from PGSW resulted in the lowest IFT value compared to adding or removing other ions. Whereas the removal of NaCl caused the contact angle to decrease from 91.0° to 67.8° relative to PGSW and changed surface wettability to weakly water-wet, eliminating KCl did not considerably change the contact angle, such that it only led to a nine-degree reduction in this angle relative to PGSW and left wettability in the same neutral-wet condition. At optimal concentrations of MgCl2, CaCl2, and Na2SO4, only an increase in Na2SO4 concentration in PGSW could change wettability from neutral-wet to weakly water-wet. For solutions with optimal concentrations, the removal of NaCl or KCl caused the rock surface to have slightly higher negative charges, and increasing the concentration of divalent ions led to a small reduction in the negative charge of the surface. The results of micromodel flooding indicated that NaCl-free PGSW could raise oil recovery by 10.12% relative to PGSW. Furthermore, when the Na2SO4 concentration in PGSW was tripled, the oil recovery increased by 7.34% compared to PGSW. Accordingly, depending on the conditions, it is possible to use PGSW so as to enhance the efficiency of oil recovery by removing NaCl or by increasing the concentration of Na2SO4 three times.

Surface free energies parameters in carbonate rock/nonacidic crude oil/brines systems

ABSTRACT Since knowing the effect of salt type is a vital parameter during smart-water injection for enhanced oil recovery (EOR) purposes, surface-free energies on the carbonate surface contacted by crude oil and different aqueous solutions with 0.7 ionic strength (about the ionic strength of seawater) are studied for solutions containing NaCl, Na2SO4, KCl, CaCl2, MgCl2, and MgSO4. For this purpose, the interfacial tension (IFT) of crude oil/aqueous solution and contact angle of oil/rock/brine are measured concomitant with the calculation of works of cohesion (WC) and adhesion (WA) as well as spreading coefficient (SC). Maximum equilibrium IFT reduction was observed for MgSO4 (from 22.7 to 12.71 mN.m−1). Besides, the calculated adsorption times using the exponential decay model reveal that the chloride salts of MgCl2 and KCl has the minimum and maximum adsorption time of 1600 s and 3400 s, respectively. Moreover, the contact angle measurements demonstrate that it is possible to change the wettability condition of rock surface from strongly oil-wet to strongly water-wet (about 20°) using Na2SO4 while the other utilized salts can change the contact angle from 170° to neutral wetness condition of 100°. The obtained results show that the best SC was obtained for DW due to its significant wettability alteration capability (from strongly oil-wet toward neutral state) compared with brine solutions. To sum up, according to the results it can be concluded that solution congaing MgSO4 can introduce the lowest IFT value and the highest wettability alteration from the initial strongly oil-wet state toward a neutral state, while Na2SO4 solution leading the lowest contact angle of about 20° which is the most favorable condition (strongly water-wet).

Experimental investigation of the influence of fluid-fluid interactions on oil recovery during low salinity water flooding

This study aims to investigate the role of fluid-fluid interactions during low salinity water flooding, using crude oil from an Iranian oil reservoir. To minimize the effects of mineral heterogeneity and wettability alteration, a synthetic sintered glass core was utilized and all coreflooding experiments were performed at low temperatures without any aging process. The effect of fluid-fluid interactions were investigated in both secondary and tertiary injection modes. pH measurements as well as UV-Vis spectroscopy and interfacial tension (IFT) analysis were performed on the effluent brine samples. Resultsshow that fluid-fluid interactions, mainly the dissolution of crude oil polar components into the brine, significantly affect brine physical and interfacial properties. In secondary injection scenario, two times diluted seawater (2SW), which has the lowest IFT value, exhibits the highest (81%) oil recovery factor. While the lowest recovery factor (60.75%) was observed for the case of formation water (FW) injection. To explore the effect of contacting time, after 48 h soaking, brine injection was resumed. The effluent pH measurement at this stage showed a reduction, where the UV-Vis spectroscopy and IFT measurements confirmed dissolution of the crude oil polar components into the brine. The results showed that as brine salinity decreases, the amount of dissociated polar components increases. pH value of ten times diluted sea water (10SW) was reduced from its initial value of 7.45 to 4.22, while FW exhibits minor pH variation. Consequently, 10SW, which dissolved highest amount of polar components, depicts the highest recovery factor (6%) after soaking. Contrary to this, in tertiary injection mode, the high amount of saline brine in the core (because of FW injection at secondary stage) hinders the potential for more production for SW, 2SW and 10SW injection as all resulted to lower recovery factor compared to their secondary counterparts.

Synthesis, surface/interfacial properties, and biological activity of amide-based Gemini cationic surfactants with hydroxyl in the spacer group

Three amide-based Gemini cationic surfactants, 1, 3-2 (alkyl amide propyl dimethyl ammonium chloride) isopropyl alcohol (abbreviated to ADQ-n, where n represents the carbon number in the raw fatty acid of 8, 12 and 16) were synthesized by a facile synthetic route. The effect of hydrophobic chain length on surface/interfacial activities, electrolytes tolerance, wettability, foaming properties were investigated. The effect of electrolytes (NaCl and CaCl2) on the interfacial tension at the oil/water interface were discussed, and the biological activity was also tested. The results showed that ADQ-n have the higher surface activities than conventional monomeric surfactant. The critical micelle concentration (cmc) decreases with the increase of hydrophobic chain length, however, the surface tension at the cmc (γcmc) shows the opposite trend. There are few differences for maximum surface excess concentration (Гmax) and minimum area per molecule (Amin). ADQ-12 has the lowest interfacial tension value (4.1 × 10−3 mN/m) than other synthesized Gemini surfactants, this is attributed to the better compatibility between hydrophobic tail of ADQ-12 and kerosene. In addition, the addition of electrolytes is favorable to decrease interfacial tension at oil/water interface. ADQ-n demonstrated readily biodegradation (>97%) in comparison with conventional alkyl chain Gemini surfactants (<37%) after seven days and could be classified as biodegradable.

The impact of monovalent and divalent ions on wettability alteration in oil/low salinity brine/limestone systems

Waterflooding is applied worldwide to improve oil recovery. Due to the complexity of the crude oil-brine-rock interactions, the mechanism behind the low saline enhanced oil recovery (EOR) process has been debated in the literature for the last decade. Both physical and chemical mechanisms have been proposed, but it appears that none of the suggested mechanisms have got a general acceptance in the scientific literature so far. The main objective of this paper is to investigate the affinity of ions toward the surface during low and high salinity injection by measuring the contact angle (CA) and interfacial tension (IFT) in a carbonate rock substrate/oil/brine system, in different salinity and pH levels. The brines were original sea and formation water, brine solutions containing single component salt such as; MgSO4, KCl, Na2SO4, CaCl2, MgCl2, NaCl, and multicomponent mixtures of them at different concentrations. Three different stock-tank crude oils are utilized in this study. Results showed that the asphaltenic-acidic crude oils have a positive impact to wettability alteration of carbonate rocks during low salinity water injection. Also we observed that the low salinity waterflooding possibly behaving similar to alkaline flooding due to increase in pH. The IFT results show that the lowest IFT value is obtained at 5000ppm smart water containing divalent ions, Mg2+ and SO42−.

Low salinity injection into asphaltenic-carbonate oil reservoir, mechanistical study

The impacts of salinity adjustment of displacing fluid have recently gained special attention to enhanced oil recovery (EOR). Different mechanisms have been studied widely in the literature while some of them are still subjugated to more scrutiny. The effects of diluted sea water on the interfacial properties of brine and asphaltenic-acidic crude oil and the wettability alteration of carbonate reservoir rock are investigated in this experimental observational work. The measurements of interfacial tension (IFT) and contact angle (CA) as two main parameters are studied. Besides, the effects of asphaltene and resin in the crude oil on the IFT values between the crude oil and aqueous solution are investigated.The experimental results show that the lowest IFT values are obtained at high salinity conditions, while the surface rock wettability alterations are observed at low salinity conditions. Based on the obtained results, a combined mechanism is proposed to describe the wettability alteration towards more water wet at low salt conditions.

Effects of Surfactant-Polymer Formulation and Salinities Variation Towards Oil Recovery

Surfactant-Polymer (SP) formulation is a crucial part when dealing with SP flooding. Different formulations using different types and concentrations of combination of surfactant and polymer result in different interfacial tension (IFT) and viscosity obtained and it will affect the amount of oil recovered. Salinity also affects the efficiency of SP flooding. High salinity causes polymer viscosity reduction and optimal salinity results in low IFT. This research is conducted to design SP formulation, select an optimum SP formulation by core flooding tests and to determine the effect of salinity (NaCl) variations towards optimum SP formulation. Nine different SP formulations in constant salinity are designed by using different concentrations of Hydrolized Polyacrylamide (HPAM) and anionic surfactant (Alpha Olefin Sulfonate-AOS). The formulations were characterized in terms of viscosity and IFT. Artificial heterogeneous porous media were used in core flooding tests and only six SP formulations with lowest IFT value were tested. Three different salinities were used for optimum SP formulation with maximum incremental oil recovery after water flood to determine the effects of salinities on polymer viscosity, surfactant IFT, incremental oil recovery after water-flood and also phase behavior. For combination of HPAM and AOS in SP flooding, IFT was only affected by the concentration of surfactant used whereas viscosity is solely dependent on polymer concentration. Core flooding tests performed in heterogeneous porous media shows that there exist an optimum polymer viscosity and surfactant IFT in SP flooding which can maximize incremental oil recovery and increasing in salinity also results in poor incremental oil recovery.

Effectiveness test of alginate-derived polymeric surfactants

A series of alginate-derived polymeric surfactants (APSs) with a linear alkyl group (C8, C12, C16) was synthesized by oxidation followed by reductive amination of 2,3-dialdehydic alginate. The products were characterized by measuring IR spectra, NMR spectra, surface tension and critical micelle concentration (cmc). They were also tested for the solubilization of azobenzene and adsorption of heavy metal. In the case of 40% CHO-C8 APSs, the lowest interfacial tension value (31.5 m Nm−1) was obtained at the cmc value of 1.35 g dm−3. The dissolving capacity of 40% CHO-C8 APS towards azobenzene was 27 times greater than that of alginate. The overall cobalt (Co2+) removal efficiency by adsorption using APSs was high compared with that of sodium alginate at pH 3, 5 and 7. Equilibrium aspects of cobalt adsorption onto 10% CHO-APSs were studied, and the results show that APSs had high equilibrium capacities for cobalt uptake, 115.5 mgg−1. © 2002 Society of Chemical Industry

Effectiveness test of alginate‐derived polymeric surfactants

AbstractA series of alginate‐derived polymeric surfactants (APSs) with a linear alkyl group (C8, C12, C16) was synthesized by oxidation followed by reductive amination of 2,3‐dialdehydic alginate. The products were characterized by measuring IR spectra, NMR spectra, surface tension and critical micelle concentration (cmc). They were also tested for the solubilization of azobenzene and adsorption of heavy metal. In the case of 40% CHO‐C8 APSs, the lowest interfacial tension value (31.5 m Nm−1) was obtained at the cmc value of 1.35 g dm−3. The dissolving capacity of 40% CHO‐C8 APS towards azobenzene was 27 times greater than that of alginate. The overall cobalt (Co2+) removal efficiency by adsorption using APSs was high compared with that of sodium alginate at pH 3, 5 and 7. Equilibrium aspects of cobalt adsorption onto 10% CHO‐APSs were studied, and the results show that APSs had high equilibrium capacities for cobalt uptake, 115.5 mgg−1.© 2002 Society of Chemical Industry