Betaine Surfactant Research Articles

Experimental study of foam stability and interfacial behaviour of cellulose nanocrystals-enhanced C22-tailed zwitterionic betaine surfactant

The intrinsic thermodynamic instability of foam systems significantly constrains their effectiveness in enhancing oil and gas recovery from unconventional reservoirs. This study investigated the foam properties and interfacial rheological characteristics of the EDAB/CNC/APG system, analyzing the influence of various factors including temperature, pH, and inorganic salts. The results indicated that the optimal concentration ratio for CNC-surfactant system consists of 0.3 % EDAB, 1.5 % CNC and 0.5 % APG by mass fraction. In this system, the addition of CNC forms a three-dimensional network structure at the gas–liquid continuous interface, significantly extending the drainage half-life of the system. At elevated temperatures, the intense molecular thermal motion disrupts the interactions between CNC and EDAB. This disruption leads to a decrease in surface tension and the viscoelastic modulus of interfacial expansion, resulting in an increase of foam volume but a decline in foam drainage half-life. Foam performance and interfacial rheological characteristics are optimal under neutral pH conditions and manifest higher stability in alkaline conditions compared to acidic conditions. In highly mineralized reservoirs (≥5.0 % salt concentration), inorganic salt ions shield the attraction between CNC and oppositely charged surfactants. This shielding weakens the cross-linking within CNC-surfactant systems, altering the structure of the liquid film interface and causing a sharp decrease in foam half-life. The C22-tailed zwitterionic betaine surfactant EDAB, enhanced by CNC, provides a novel, environmentally friendly, efficient, and safe approach to the exploitation of complex, low-permeability oil and gas reservoirs.

Factors, Mechanisms, and Kinetics of Spontaneous Emulsification for Heavy Oil-in-Water Emulsions.

In challenging reservoirs where thermal recovery falls short, cold or chemical oil recovery methods are crucial. Spontaneous emulsification (SE), triggered by gentle disturbance, significantly enhances oil recovery. In elucidating SE mechanisms and kinetics, SE processes via direct contact between oil and aqueous phases without stirring were conducted. The effects of temperature, emulsifier concentration, pH, NaCl concentration, and the oil-to-water ratio on SE were investigated through droplet size analysis and turbidity measurements. Furthermore, the emulsification mechanism and derived emulsification kinetics based on turbidity data were obtained. The results underscore the feasibility of SE for oil-water systems, reducing viscous and capillary resistances without agitation. The emulsified oil mass increased with the temperature, pH, and aqueous-to-oil phase volume ratio while decreasing with the NaCl concentration. In this study, for GD-2 crude oil, the optimal emulsified oil amount occurred at a betaine surfactant (BetS-2) emulsifier concentration of 0.45%. Microscopic photo analysis indicated narrow particle size distributions and small droplets, which remained stable over time under various experimental conditions. A combined SE mechanism involving ultralow interfacial tension, interfacial turbulence due to Marangoni effects, and "diffusion and stranding" due to in situ emulsifier hydrophilicity, was speculated. Additionally, an analogous second-order kinetic equation for SE was proposed, indicating exceptional correlation with calculated and experimentally measured values. This study offers theoretical insight for enhancing oil recovery in chemical and cold production of heavy oil in oilfields.

Investigation of a highly efficient foaming mixture compromising cationic Gemini-zwitterionic-anionic surfactants for gas well deliquification

Abstract Foamers with high resistance to condensate, salinity and high temperature play a crucial role in gas well deliquification. In this study, we developed an efficient foaming mixture containing a Gemini surfactant (CAGB), a betaine surfactant (CAPB) and sodium lauroyl glutamate (SLG), which exhibited excellent foaming performance (at a molar ratio of 3:3:4 and a dosage of 20 mmol L−1) with a foam volume of 440 mL and a half-life of 11 min. The optimized CAGB/CAPB/SLG mixture showed exceptional liquid unloading and foaming ability under high methanol (up to 40 vol.%) and condensate (up to 50 vol.%) content conditions. Trisodium aminotriacetate (NTA) facilitated the liquid unloading performance at a salinity of 90 g L−1. With 10 vol.% methanol, the liquid unloading rate of CAGB/CAPB/SLG foam at 90 °C could be increased to 90 %. Furthermore, surface tension and morphology analysis confirmed the presence of synergy within the CAGB/CAPB/SLG mixture in foaming, foam stabilizing and liquid unloading ability.

Synthesis of betaine surfactant and its application in microemulsion flushing fluid

In order to effectively remove the oil-based drilling fluid and oil mud cake attached to the wellbore, improve the cementation environment of the second interface and improve the quality of cementing, a betaine-type zwitterionic surfactant (OASB) was synthesized in this study. The structure of OASB was characterized by IR and 1H NMR. The interfacial tension of OASB solution with different concentration was measured. A microemulsion cementing flushing fluid (MFF) was prepared with OASB mixed with Tween 80 as surfactant, n-octanol as cosurfactant, kerosene as oil phase and deionized water as water phase. The stability, particle size, rheology, corrosivity and wettability of MFF were analyzed and tested. The flushing effect of MFF on oil-based drilling fluid and oil mud cake was evaluated, and the changes in bonding strength of the second interface of cementing before and after flushing was compared and analyzed. The results revealed that MFF had good temperature, salt, acid and alkali resistance and low corrosion ability. The apparent viscosity was 25 ∼ 80 mPa·s in 20 ∼ 120 °C and had good rheological properties. The excellent wettability reversal ability of MFF was beneficial for removing oil-based drilling fluid and oil mud cake, with a flushing efficiency of over 90%. After MFF flushing, the bonding strength of the second interface of cementing was significantly improved. The SEM and elemental analysis showed that MFF had a more thorough flushing of oil mud cake, and the bonding structure between the cement stone and the second interface was denser.

Research of a fracturing-oil displacement integrated working fluid based on betaine surfactant

With the increasing attention paid to the treatment of flowback fluid, cost control, and environmental pollution in oil reservoir reconstruction and enhanced oil recovery, transforming fracturing fluid into oil displacement working fluid after fracturing has become a solution. In this paper, an EOS gel system is formulated using erucic acid amidopropyl betaine (EAPB), oleic acid amidopropyl betaine (OAPB), and sodium salicylate (NaSal). The system demonstrates high viscoelasticity and achieves ultra-low interfacial tension at low concentrations with dual purposes in fracturing and oil recovery. The comprehensive performance evaluation demonstrates that the EOS integrated working fluid exhibits excellent salt and temperature resistance. The viscosity of 2.8 wt% EOS remains above 24 mPa·s after 1 h of continuous shearing at 80 °C. The surface and interfacial tension of the gel breaking solution can be reduced to 26.84 mN/m and 4.54 × 10−3 mN/m, respectively. The contact angle on the lipophilic glass can be reduced by 22.3°, 22.4° and 21.0° at 60 °C, 70 °C and 80 °C, respectively. Due to the adsorption of surfactant molecules, which reduces the adhesive force of oil droplets and alters the wettability of the rock surface, the static oil recovery rate reaches 19.4% at 70 °C, and the dynamic water flooding oil recovery rate can be increased by 11.56%. The fracturing-oil displacement integrated working fluid formulations developed in this paper provides a useful reference for reducing cost to increase benefit as well as enhancement of recovery in the latter period of oilfield development.

Evaluation of foaming agents for high‐temperature, high‐pressure, and high‐salinity reservoirs based on a new foam evaluator

AbstractIn this study, a novel high‐temperature and high‐pressure foam evaluator with variable diameters inner cell and cylinder flip function was designed on our own, which can solve the problems such as difficulties in foam generation and inaccurate determination of various foam parameters by the same type of instruments, through which the foaming performance of more than 10 betaine surfactants was evaluated. The results show that: (1) the higher the pressure, the higher the foaming rate of the foaming agent and the more stable the foam, but the foam stability of the foamers at low and high pressures, and low and high temperatures do not correspond exactly, and the foaming agent used needs to be screened under simulated reservoir conditions. (2) The comprehensive foaming performance of different types of foamers with different molecular structures found that hydroxy sulfobetaine with longer carbon chains has a relatively better foaming performance. Therefore, for the reservoir conditions of temperature 130°C, pressure 30 MPa, and salinity 22 × 104 mg/L, hydroxy sulfobetaine, which does not contain an amide group in the molecule, can be considered preferentially as a foaming agent. The results can guide the selection of foaming agents for high‐temperature and high‐salinity reservoirs.

Natural-Origin Betaine Surfactants as Promising Components for the Stabilization of Lipid Carriers.

In the present work, we demonstrate studies involving the influence of the formulation composition on the physicochemical properties of nanocarriers: solid lipid nanoparticles (SLNs) and nanostructured lipid carriers (NLCs). Novel lipid-origin platforms were prepared using two "green" betaine-based surfactants, cocamidopropyl betaine (ROKAmina K30) and coco betaine (ROKAmina K30B), in combination with three different solid lipids, cetyl palmitate (CRODAMOL CP), trimyristin (Dynasan 114), and tristearin (Dynasan 118). Extensive optimization studies included the selection of the most appropriate lipid and surfactant concentration for effective SLN and NLC stabilization. The control parameters involving the hydrodynamic diameters of the obtained nanocarriers along with the size distribution (polydispersity index) were determined by dynamic light scattering (DLS), while shape and morphology were evaluated by atomic force microscopy (AFM) and transmission electron microscopy (TEM). Electrophoretic light scattering (ELS) and turbidimetric method (backscattering profiles) were used to assess colloidal stability. The studied results revealed that both betaine-stabilized SLN and NLC formulations containing CRODAMOL CP as lipid matrix are the most monodisperse and colloidally stable regardless of the other components and their concentrations used, indicating them as the most promising candidates for drug delivery nanosystems with a diverse range of potential uses.

Molecular dynamics study on BS12/SDS stabilized CO2 foam: Evaluation of surfactant monolayer structure and interfacial properties

CO2 foam flooding holds great potential for enhanced oil recovery and geological storage. However, ensuring the stability of supercritical CO2 foam systems under high temperature and pressure reservoir conditions remains a challenge. Note that the term "supercritical CO2 foam" specifically denotes a foam system created by combining an aqueous solution containing chemical additives with CO2 in a supercritical state under high-temperature and high-pressure conditions. Surfactants can reduce the surface Gibbs free energy by adsorbing onto the CO2-water interface to form a monolayer structure, which hinders CO2 diffusion and improves foam stability. In this study, molecular dynamics simulations were employed to analyze the adsorption behavior and interfacial performance of betaine surfactant BS12 and the anionic surfactant SDS at the CO2-water interface. The results indicate that BS12 can reduce interfacial tension more effectively at near-saturated concentrations. Moreover, the monolayer formed by BS12 has a lower voidage and wider interfacial thickness. The carboxyl-nitrogen interaction among BS12 molecules impedes their further aggregation, thereby maintaining the mutually perpendicular "L" orientation of the headgroup and hydrophobic tail thus forming a rigid and stable monolayer structure. Additionally, the spatial distribution function, radial distribution function, and hydrogen bond statistics indicate that although BS12 exhibits slightly weaker hydrophobicity than SDS, its hydrophobicity is less affected by concentration. Specifically, the first hydration shell of the carboxyl group remains stable even at high concentrations. Besides, the steered simulations show that the rate-limiting step in the CO2 permeation process is the dense region of the surfactant headgroups. Besides, the permeation of CO2 molecules in the BS12 monolayer is characterized by a lower diffusion coefficient and higher energy barrier to overcome. In summary, BS12 forms a thicker and more uniform monolayer structure, effectively hindering the contact between CO2 and water molecules at the interface and further enhancing foam stability. Our findings further reveal the relationship between surfactant molecular architecture and interfacial properties, providing references for the screening and structural design of surfactants used in CO2 foam flooding.

Performance of extended surfactant and its mixture with betaine surfactant for enhanced oil recovery in sandstone reservoirs with low permeability

Carboxy betaines CnZC (where n represents the carbon number of the alkyl chain, n = 12,14 and 16) and extended surfactant C16P3E6S were combined to assess their potential application for enhanced oil recovery (EOR) by investigating the surface properties, interfacial properties and emulsifications of the single and compounded surfactants. The results demonstrated that four surfactants with favorable water solubility exhibited better surface properties. Among them, the mixture of betaine surfactant C14ZC and sulfonate surfactant C16P3E6S displayed a synergistic effect in reducing interfacial tension (IFT). The solution with C14ZC mole fractions of 60 % and 50 % possessed an ultra-low IFT (10-3 mN/m order of magnitude) at 10 % NaCl whose emulsification rates of oil in brine for mixtures exceeded 90 % at 4 % NaCl. Notably, the emulsion droplet diameter was smaller compared to other salinity conditions, indicating that the combination of C16P3E6S and C14ZC enhanced emulsion stability, correspondingly ultra-low IFTs at both the oil-emulsion and emulsion-water interfaces. Coreflooding experiments revealed that the depressurization rate for the optimized surfactant system (with a molar fraction of C16P3E6S/C14ZC = 2:3) with superior emulsification properties, effectively abilities of reduced IFT, increased capillary number and lower adsorption loss was 26.7 % and its EOR was 20.4 %, confirming its favorable displacement performance and potential application in medium to high salinity reservoirs.

Exploratory insight into the contribution of chemical components of photo galvanic electrolyte towards potential, power and current of photo galvanic cells

Photo-galvanic cells are based on the diffusion of ions in the electrolyte (a mixture of sensitizer, reductant, alkali, surfactant, and solvent). The photogalvanics is characterized by the abrupt jump in the photo-potential during charging of the cell. Photo-galvanic cells have been widely studied using the complete electrolyte. The migration of current by ions gives impression that any of the ionic species individually (like sensitizer/reductant/etc.) may show current, potential, and photogalvanics. This aspect of photogalvanics of individual chemical components is missing in the literature. Therefore, the photogalvanics of the individual chemicals, mixtures of the chemicals, and complete electrolyte have been studied in present research to have insight into (i) the genesis of the current and potential generated from the cell in non-illuminated state (dark conditions), and (ii) the necessary chemical conditions required for the photogalvanics.The average open-circuit potential (Voc) and short-circuit current (Isc) in dark conditions for water, Lactic acid reductant, Cocamidopropyl betaine surfactant, Carmoisine-A dye, NaOH alkali, complete electrolyte (at low pH), and complete electrolyte (at very high pH) is 286 mV, 4 µA; 214 mV, 3 µA; 278 mV, 4 µA; 268 mV, 9 µA; 295 mV, 8 µA; 278 mV, 8 µA; and 463 mV, 253 µA, respectively. The average Voc and Isc from illuminated water, Lactic acid reductant, Cocamidopropyl betaine surfactant, Carmoisine-A dye, NaOH alkali, complete electrolyte (at low pH), and complete electrolyte (at very high pH) is 296 mV, 3 µA; 182 mV, 4 µA; 218 mV, 4 µA; 135 mV, 3 µA; 275 mV, 9 µA; 167 mV, 6 µA; and 731 mV, 2500 µA, respectively. Thus, no photogalvanics has been observed for individual chemical components, and mixtures of two or more chemical components of the electrolyte. The photogalvanics is observed only for complete electrolyte at high pH.

Influence of tail group length, amide functionality and added salt ion identity on the behaviour of betaine surfactants

HypothesisThe behaviour of surfactants in solution and at interfaces is governed by a combination of steric and electrostatic effects experienced by surfactant molecules as they interact with solvent, other species in solution, and each other. It would therefore be anticipated that highly interacting groups would significantly influence surfactant behaviour. The widely used amide functionality has polar H-bond donor/acceptor properties, and therefore its inclusion into a surfactant structure should have a profound effect on surface activity and self-assembly of that surfactant when compared to the equivalent molecule without an amide linker. Further, chaotropic or kosmotropic salt ions that affect water structuring and hydrogen bonding may provide opportunities for further tuning surfactant interactions in such cases.ExperimentsA library of betaine surfactant with tail lengths n=14−22 both with and without an amidopropyl linker were synthesised to study the effect of the amide functionality on surfactant properties. Characterisation of the molecules interfacial properties were performed using pendant drop tensiometry and their solution state formulation properties were probed using small-angle neutron scattering (SANS) and rheological measurements.FindingsPresence of an amidopropyl linker had little effect on aggregation propensity (as evidenced by critical micelle concentration) and aggregate morphology of betaine surfactants, but did increase the Krafft temperature of these surfactants. SANS analysis indicated that aggregate morphology of alkyl betaine surfactants could be influenced by the addition of sodium salts with chaotropic counterions (I− and SCN−), but they were insensitive to more kosmotropic anions (SO42−, F− and Cl−), providing unique and novel solution control methods for this (supposedly salt-insensitive) class of surfactants.

The synergism of improving interfacial properties between betaine and crude oil for enhanced oil recovery

Betaine, an emerging surfactant for enhanced oil recovery (EOR), has garnered increased attention and recognition. This study focuses on linear alkylbenzene sulfonate betaine (ASB) as the research subject, and different crude oils were utilized to prepare two types of oil–water formulations with high interfacial film strengths but differed interfacial tensions. The interfacial properties were characterized and explored using interfacial dilational rheology, droplet squeeze coalescence, interfacial tension, emulsification, microscopic visualization, and other measuring methods. The actual emphasis in interfacial film properties of betaine as a standalone chemical EOR formulation was clarified. The results indicated that betaine had generally high interfacial film strength with selected crude oils, at this time, the slight difference in film strength had a negligible effect on enhancing the recovery. The main contributing factor was the difference in interfacial tension between the oil and water. Ultra-low interfacial tension could increase the stripping efficiency of oil in pore, reduce the energy required to emulsification or oil droplets initiation, and ensure that droplets were displaced and collected in smaller sizes, thereby avoiding large oil droplets trapped in the pore throat and unable to pass. Making good use of the advantages of improving sweep efficiency brought by high interfacial film strength, at the same time giving the system ultra-low oil–water interfacial tension, ensuring the start-up and migration of porous crude oil, is the core construction principle of betaine surfactant applied to EOR.

Zero CO2 emission preliminary plant design of cocamidopropyl betaine (CAPB) surfactant from hydrogenated palm kernel oil (HPKO)

Cocamidopropyl betaine (CAPB) is major raw material to generate surfactant and there is only one plant in Indonesia producing CAPB. It is predicted the demand of CAPB in Indonesia reach 53,000 ton annually. Following this journal, a surfactant plant with zero CO2 emission is designed which located at Special Economic Region (KEK) Sei Mangkei, North Sumatra with 70,000 TPA capacity production. Based on the analysis of mass and heat balance need 14,500 TPA HPKO, 81,500 TPA CWS, 6,000 TPA LPS, 2,650 TPA MPS. According to equipment specification, 49,564.34 kJ/hr electricity is needed for this plant. Processing HPKO into CAPB has 2 main reactions, amidation and quaternization. Amidation is reaction to create intermediate product, amidoamine from reaction of HPKO with DMAPA using batch stirred reactor with 96% conversion at 3.5 barg and 140°C. Quaternization is reaction between amidoamine and sodium monochloroacetic acid (SMCA) using 2 series plug flow reactor to reach 96% conversion. The result of reaction is CAPB 30% which cooled first, then distribute to the consumers. Total Capital Investment required is $37,359,880.75 where consists of 3 years construction and 20 years production with IRR 39.64%, Pay Out Time 5.65 years, and WACC 13%.

Studies on the Synthesis and Application Properties of a Betaine Surfactant with a Benzene Ring Structure

Two novel betaine surfactants with distinct hydrophilic headgroups were synthesized, including carboxybetaine surfactant (DCB) and sulfobetaine surfactant (DSB). Their properties of reducing the interfacial tension (IFT) of Xinjiang crude oil/water were studied under alkaline-free conditions, as were their thermal stability, wettability, and emulsification properties. The chemical structures of the target products were characterized and analyzed by using 1H-NMR and 13C-NMR. The experimental results indicate that the introduction of a benzene ring to the hydrophobic group can improve the solubility and high-temperature resistance of the betaine surfactant. Thermogravimetric analysis showed that the degradation temperature of the synthesized betaine was above 190 °C. As the concentration of the betaine solution increased, DSB (0.0750 mmol/L) showed a lower critical micelle concentration (CMC) than DCB (0.1852 mmol/L). The wetting ability of DCB was significantly higher than that of DSB, and their contact angles on paraffin film decreased to 28.36° and 35.26°. In addition, both DCB and DSB can reduce the IFT of Xinjiang crude oil/water to ultra-low levels (10−3 mN/m) in the absence of alkali. The appropriate ion concentration has a synergistic effect on the surfactant to reduce the interfacial tension of oil/water and the effect of the three ions on the interfacial tension was as follows: Na+ < Ca2+ < Mg2+.

Optimization Study of Polymer-Surfactant Binary Flooding Parameters in Maling Jurassic Low Permeability Reservoir

The low-permeability Jurassic reservoir in Changqing Maling has been in the middle and high water cut stage after long-term development of water injection. In order to improve development efficiency and further explore a new way to enhance oil recovery of the reservoir, a significant development test and a polymer-surfactant flooding study were carried out in the Maling Beisan area in 2011. Compared with other polymer-surfactant flooding reservoir of PetroChina, Jurassic reservoir in Beisan area had relatively low permeability and high salinity of formation water and injected water, which puts forward higher requirements on the injectivity and salt resistance of the binary system. At the same time, the viscosity of the formation crude oil was low, and the viscosity of the polymer required to achieve the optimum fluidity ratio was relatively low, which is an important advantage of implementing the binary flooding in the reservoir. In this paper, hydrophobic associating polymer and betaine surfactant were selected through laboratory experiments. According to the experimental data, numerical simulation technology was used to analyze and optimize the influence factors, including injection speed, injection-production ratio, slug size, slug polymer, and surfactant concentration. Finally, the development index of binary flooding was predicted. The results show that the optimized polymer-surface system had good injectivity and high formation compatibility. Through on-site differential control measurement of injection and production, the recovery was enhanced significantly. This study had guiding significance for the production of polymer-surface flooding in the similar reservoirs.

Synthesis, characterization and performance of lignin carboxyl betaine zwitterionic surfactants for application in enhanced oil recovery.

The objective of this study was to synthesize lignin carboxyl betaine zwitterionic surfactants (LCBS) from alkali lignin through a three-step reaction involving epoxidation, amination, and quaternization. The synthesized LCBS were characterized using infrared spectroscopy (IR) and thermogravimetric (TG) analysis. To assess their potential for enhanced oil recovery (EOR), the physicochemical properties of the LCBS surfactants, such as surface tension, emulsification, temperature resistance, salt resistance, and interfacial properties, were evaluated using standard experimental methods for surfactants applied in oil displacement. The LCBS surfactants exhibited higher surface activity, with low surface tension values ranging from 29.65 mN m-1 to 31.85 mN m-1 at the corresponding critical micelle concentration (cmc), also the significant emulsifying performance of LCBS surfactants was proved in the emulsifying experiments. Moreover, the synthesized LCBS surfactants were found to be suitable for use in harsh reservoirs of high-salinity and high-temperature, as confirmed by the temperature and salt resistance measurements. The interfacial tension (IFT) tests between Huabei crude oil and LCBS surfactants suggested that these surfactants could effectively extract the crude oil containing heavy components such as colloid and asphaltene, and ultra-low IFT values could be achieved with the addition of weak alkali.

Experimental Evaluation of Zwitterionic and Cationic Surfactants to Optimize Bulk Foam Properties for Gas Mobility Control in High-Salinity Carbonates

Foam injection has been acknowledged as a promising technology to control gas mobility by establishing the flow resistance during gas enhanced oil recovery (EOR) processes. For applications in challenging carbonate formations, the development of well-matched foaming agents is required. In this paper, the foam performance established by different switchable and zwitterionic surfactants along with their combinations in controlling gas mobility and displacing the residual oil is investigated. The stable solutions of commercial amine-based and/or zwitterionic surfactants were prepared in 20 wt % salinity. A series of foamability and foam stability tests were conducted as initial screening at high temperatures in the presence and absence of crude oil. Foam texture and foam stability were also investigated at different gas/liquid fractions under high-temperature and high-pressure conditions. The best-performing formulation at optimum foam quality was evaluated in coreflooding experiments in terms of mobility reduction factor (MRF) and residual oil recovery. Bulk foam results demonstrated the superior foamability and foam stability of a betaine (B1235) surfactant. Foam endurance of B1235 was found comparable to the diamine (DTTM) produced foam; however, the DTTM surfactant showed insignificant foamability. Among all tested surfactants and their mixtures, B1235 was found most effective in maintaining foam properties in a crude oil environment, and no synergistic effect was observed in the use of surfactant mixtures. The optimum concentrations for B1235 with and without crude oil were 0.25 and 0.5 wt %, respectively. The results obtained from the experiments in a pressurized view cell indicated a prolonged decay profile at 90% gas fraction in bulk. During dynamic flow in carbonate rocks, the optimum quality of foam stabilized by the selected surfactant was found at 70%. At this quality, the pregenerated foam injection pronouncedly increased the MRF to 48. The cumulative oil recovery after foam injection was 67%, providing 25% incremental recovery. The overall performance of the betaine-based surfactant-stabilized foam in high-salinity carbonates was found effective in controlling the gas mobility during the foam EOR process.

Progress in research of sulfobetaine surfactants used in tertiary oil recovery

AbstractThe synthesis of sulfobetaine surfactants and their application in tertiary oil recovery (TOR) are summarized in this paper. The synthesis of sulfobetaine surfactants was classified into three categories of single hydrophobic chain sulfobetaine surfactants, double hydrophobic chain sulfobetaine surfactants and Gemini sulfobetaine surfactants for review. Their application in TOR was classified into surfactant flooding, microemulsion flooding, surfactant/polymer (SP) flooding and foam flooding for review. The sulfonated betaine surfactants have good temperature resistance and salt tolerance, low critical micelle concentration (cmc) and surface tension corresponding to critical micelle concentration (γcmc), good foaming properties and wettability, low absorption, ultralow interfacial tension of oil/water, and excellent compatibility with other surfactants and polymers. Sulfobetaine surfactants with ethoxyl structures, hydroxyl and unsaturated bonds, and Gemini sulfobetaine surfactants will become an important direction for tertiary oil recovery because they have better interfacial activity in high‐temperature (≥90°C) and high‐salinity (≥104 mg/L) reservoirs. Some problems existing in the synthesis and practical application were also reviewed.

Research Progress on the Synthesis of Different Types of Gemini Surfactants with a Functionalized Hydrophobic Moiety and Spacer

AbstractGemini surfactants are advantageous over conventional surfactants as they find applications as antimicrobial agents, corrosion inhibitors, enhanced oil recovery, capping agents for nanoparticle synthesis, drug delivery agents, etc. This article provides a detailed overview of synthetic procedures for various types of geminis and the fundamental physicochemical parameters of these systems. This includes a discussion on the cationic geminis based on various groups such as biphenyl, amide (with/without alkane tail), binol, quaternary ammonium (with/without hydroxyl group as a spacer), morpholinium, pyridinium, amide (with/without alkane tail), ester quaternary ammonium, and imidazolium (spacer with/without hydroxyl group and thioether/ester) types. Further, it is focused on anionic geminis with carboxylate, borate, and sulfonate head groups. Zwitterionic geminis such as betaine surfactants, cocogem surfactants based on dodecylisopropylol amine and dicarboxylic acid, diester type, sulphobetaine gemini based on S‐triazine, zwitterionic hetero gemini containing ammonium and carboxylate head groups, zwitterionic gemini containing quaternary ammonium and a sulfate group, gemini containing phosphodiester anion and quaternary ammonium salt are also reviewed. Lastly, synthesis of nonionic geminis from sunflower oil, amide‐based nonionic, sulfonamide nonionic, N,N’‐diethylaminedialkyldiamide nonionic gemini, sugar‐based gemini, and nonionic gemini with sulfonate spacer have been discussed.

Effects of different gases on the performance of foams stabilized by Cocamidopropyl betaine surfactant and silica nanoparticles: A comparative experimental study

Application of CO 2 gas in foam enhanced oil recovery (EOR) processes has emerged as a win-win strategy for achieving higher oil recovery factor and reducing greenhouse gas emission, which can significantly help the protection of the ozone layer from depletion. However, lower stability of CO 2 -foam, as compared to the N 2 - and CH 4 -foams, has tempted us to examine combinations of CO 2 with these gases to not only improve the stability of the produced foam but also have CO 2 as the gaseous phase of the foam. In this study, we investigated the effect of different gases and the mixture thereof on the performance of foams in EOR while the aqueous phase of foams is a constant mixture of Cocamidopropyl betaine surfactant (0.03 wt %) and silica nanoparticle (0.1 wt%). To this end, seven different gases, including N 2 , CO 2 , CH 4 , 80% N 2 + 20% CO 2 , 80% CH 4 + 20% CO 2 , 50% CH 4 + 50% CO 2 , 50% N 2 + 50% CO 2 were used as the gases phase for foam generation, and the performance of the produced foams were examined through the following experiments: bulk foam stability tests, apparent foam viscosity measurements, and core flooding tests. The results of foam stability tests showed that half-life time for the CO 2 -, CH 4 -, and N 2 -foams are 13.5, 17.0, and 44.0 min, respectively. Also, as revealed from apparent viscosity measurements, the N 2 - and 80% N 2 +20% CO 2 foams have higher apparent foam viscosity values followed by 50% N 2 +50% CO 2 foam. Furthermore, we showed that a combination of 80% N 2 + 20% CO 2 as the gaseous phase for foam generation could not only improve CO 2 -foam stability, as compared to other foams, but also can substantially increase ultimate oil recovery (56.6 %OOIP), even more than that for N 2 foam (48.6 %OOIP), obtained from core flooding experiments.