Winsor Type Research Articles

Chemical enhanced oil recovery using carbonized ZIF-67 MOFs and sulfonated copolymers at high reservoir temperatures

Traditional nanoparticle and polymer-based enhanced oil recovery methods face challenges such as nanoparticle agglomeration and polymer adsorption, particularly at elevated reservoir temperatures. This study introduces hybrid polymeric nanofluids, combining carbonized Zeolitic Imidazolate Framework-67 (ZIF-67) with sulfonated copolymers to address these issues. Viscosity tests were conducted at 25 °C, 50 °C, 75 °C, and 90 °C, revealing a 39.67 % increase in viscosity at 90 °C, attributed to electrostatic and hydrogen bond interactions. For subsequent analyses—stability, adsorption, and core flooding—75 °C was selected as the representative high reservoir temperature. Stability assessments, confirmed via UV–Vis spectroscopy, demonstrated nanofluid durability over at least seven days. Carbonized ZIF-67 reduced polymer adsorption on rock surfaces, enhancing oil recovery and reducing environmental impact. Dynamic core flooding experiments showed a 45.8 % improvement in oil recovery by the hybrid nanofluid on carbonate rock samples. The hybrid nanofluid increased RF and RRF, improving the mobility ratio and redirecting flow to lower-permeability zones, reducing unswept oil and enhancing macroscopic sweep efficiency. Winsor Type III emulsification during the post-flooding phase of polymer-nanoparticle injection significantly improved trapped oil mobilization. Reduced contact angles from 170° to 100° altered the wettability, enhancing oil recovery. Carbonized ZIF-67 nanoparticles increased viscous forces, reduced capillary forces, and minimized polymer adsorption. The polymeric nanofluid achieved a capillary number of 1.0 × 10−3, two orders higher than that of polymer alone, resulting in superior performance. Injectivity optimization showed shear rates of 15.9 s−1 in 1700 mD cores and 79.8 s−1 in 80 mD cores, causing pressure drops of 15 psi and 1200 psi, respectively. This highlights injectivity challenges in 80 mD cores, while cores ≥ 290 mD are ideal for our polymer-nanoparticle hybrid applications.

Non-thermal recovery of a viscous oil with a surfactant-polymer process

The goal of this work is to improve recovery of a viscous oil reservoir at 70 °C using a non-thermal process. Polymer floods can improve sweep efficiency, but leave behind a residual oil saturation. A surfactant-polymer flood has the potential to improve both the sweep as well as the displacement efficiency. Phase behavior experiments with the viscous oil, water and surfactants were conducted to identify surfactants. 1D and 2D sandpack displacements were conducted to evaluate the efficacy of the process. Phase behavior experiments showed Winsor type I behavior with a low interfacial tension using a single surfactant, but not ultralow tension. Water flood recovered about 50% OOIP and reduced the oil saturation to about 45% in 1D floods. The subsequent SP flood increased the cumulative oil recovery to 99% in sandpacks when the viscosity of chemical slugs exceeded the oil viscosity. When the permeability decreased (as in a Bentheimer core), the oil recovery decreased to about 86%. Secondary SP floods also recovered most of the oil and faster than tertiary floods. Reduction of polymer concentration (and viscosity to about 1/4th of the oil viscosity) reduced the oil recovery, especially in 2D sandpack floods. Decrease in interfacial tension increased the requirement of polymer concentration to maintain flood front stability. This flood demonstrates the effectiveness of Winsor type I SP formulation for viscous oil, high permeability reservoirs. Such a SP process would reduce the carbon footprint of viscous oil recovery compared to that of thermal processes.

A CO2-Modified Surfactant for Chemical Flooding

Summary Carbon dioxide (CO2) modification of a nonionic surfactant alkyl polyglycoside (C-APG) was conducted based on a commercial APG product under mild synthesis conditions, including a low temperature (50°C) and a low pressure (2.5 bar). Using this method, CO2 was incorporated into APG molecules through the formation of carbonyl structures. The effectiveness and performance of C-APG as a novel surfactant for enhanced oil recovery (EOR) application in carbonate reservoirs were investigated and compared with its precursor—the unmodified APG. The key factors in the chemical structure of C-APG were characterized by Fourier transform infrared spectroscopy (FTIR) to confirm successful CO2 modification. The properties, including compatibility, surface tension, wettability alteration, interfacial tension (IFT), phase behavior, and static and dynamic adsorption of both APG and C-APG, were evaluated by various techniques and methods. Crude oil displacement efficiency of the surfactants was investigated via spontaneous imbibition, visualized micromodel, and coreflooding tests, respectively. Both surfactants were compatible with a high-salinity water (HSW), they exhibited a similar critical micelle concentration (CMC) of 8.5 mg/L and 13.5 mg/L for APG and C-APG, respectively, and had the same contact angle of around 135°. Interestingly, C-APG was found more effective in reducing IFT between oil and water phases. The IFT of oil in the C-APG solution was 0.058 ±0.001 mN/m, one order of magnitude lower than the value of 0.47 ±0.02 mN/m obtained from the solution of original APG, suggesting a better performance of C-APG in chemical flooding for oil displacement. A Winsor Type I microemulsion was formed by APG within the salinity range, while a transition of Type I to Type II microemulsion was observed for C-APG. The static adsorption of APG and C-APG at 2 g/L in carbonate were 0.93 mg/g rock and 1.08 mg/g rock, and the adsorption decreased to 0.11 mg/g rock and 0.13 mg/g rock under dynamic conditions for APG and C-APG, respectively. The spontaneous imbibition test demonstrated a higher oil imbibition recovery of 18.0% from C-APG solution compared to the result of 10.2% obtained from APG solution. A micromodel test showed that more crude oil was displaced by injection of APG or C-APG solution after waterflooding, while C-APG injection exhibited a stronger emulsification. The oil displacement by coreflood test showed that C-APG injection led to a lower differential pressure and a higher cumulative oil production (48%) compared to APG chemical flooding with a cumulative oil production of 41%. The produced fluids containing displaced crude oil from C-APG flooding, and subsequent waterflooding demonstrated very strong emulsification compared to the fluids produced after APG injection. This study demonstrates the significant potential of C-APG in two aspects—CO2 reduction and chemical EOR for the upstream petroleum industry.

Rapid design and optimization of complex surfactant microemulsions for high-efficiency oil extraction processes integrating experimental and modeling approaches

Microemulsions have been widely used as a means of high-efficiency oil extraction processes in the field of oil recovery, separation, deposit removal, et al. Phase behavior is considered the most reliable evidence for formulating surfactant systems. There, however, few methods exist that can predict the phase behavior of microemulsions formed by complex surfactant compositions.This work developed a modified model based on the Hydrophilic Lipophilic Deviation-Net Average Curvature (HLD-NAC) model that could rapidly and accurately predict the phase behavior and phase evolution of complex surfactant microemulsions. The phase evolution of the microemulsions with equivalent alkane carbon number (EACN), surfactant concentration, and water–oil ratio (WOR) were explored. The results indicated that the new model successfully delineated the salinity boundaries of Winsor Type III microemulsion and predicted the inversions of phase behavior. A linear correlation between the EACN and the optimal salinity was demonstrated, with a precisely defined predictive range of EACN for Winsor Type III microemulsions. A fish diagram that illustrated the evolution path of the microemulsion phase was established through concentration scanning. The WOR test suggested that Winsor Type III microemulsion could be formed through salinity regulation once the surfactant concentration exceeded the critical micelle concentration (CMC).

Screening of Chemicals to Enhance Oil Recovery in a Mature Sandstone Oilfield in Kazakhstan: Overcoming Challenges of High Residual Oil

Chemical flooding, such as alkaline-surfactant (AS) or nanoparticles-surfactant (NS) flooding, is an enhanced oil recovery (EOR) technique that has been increasingly utilized to enhance the oil production rate and recovery factor while reducing chemical adsorption. The AS/NS flooding process involves the injection of a mixture of surfactant and alkali/nanoparticles solutions into an oil reservoir to reduce the interfacial tension between the oil and water phases by surfactant and lower surfactant adsorption by alkali or nanoparticles (NPs) to improve the residual oil recovery. In this study, the AS/NS flooding is evaluated for a Kazakhstani oilfield by systematically screening the chemical constituents involved. Field A in Kazakhstan, one of the oldest fields in the country, has been waterflooded for decades and has not produced even 50% of the original oil in place (OOIP). Currently, the water cut of the field is more than 90%, with a high residual oil saturation. Therefore, besides polymer flooding to control mobility, chemical EOR is proposed as a tertiary recovery method to mobilize residual oil. This study aimed to screen chemicals, including surfactant, alkali, and NPs, to design an effective AS/NS flooding program for the target field. The study focused on conducting laboratory experiments to identify the most effective surfactant and further optimize its performance by screening suitable alkaline and NPs based on their compatibility, stability, and adsorption behavior under reservoir conditions. The performance of the screened chemicals in the porous media was analyzed by a set of coreflood experiments. The findings of the study indicated that alkali agents, particularly sodium carbonate, positively affected surfactant performance by reducing its adsorption by 9–21%. The most effective surfactant combination was found, which gave Winsor type III microemulsion and the lowest interfacial tension (IFT) of 0.2 mN/m. The coreflood tests were conducted with the screened surfactant, alkali, and NPs. Both AS and NS tests demonstrated high residual oil recovery and microemulsion production. However, NS flooding performed better as the incremental oil recovery by NS flooding was 5% higher than standalone surfactant flooding and 9% higher than AS flooding. The results of this screening study helped in designing an efficient chemical formulation to improve the remaining oil recovery from Field A. The findings of this study can be used to design EOR projects for oil fields similar to Field A.

The effects of a novel Bio-based surfactant derived from the Acacia concinna plant on chemical enhanced oil recovery in the presence of various salts and a synthesized HSPAM polymer

In this investigation, a unique idea of using a green surfactant derived from Acacia concinna (AC) plant and a hydrophobically modified copolymer consistingof acrylamide and styrene (HSPAM) for chemical enhanced oil recovery (CEOR) was studied. Firstly, the characteristics of AC green surfactant were comprehensively examined using different standard analyses, such as thermogravimetric analysis (TGA), nuclear magnetic resonance (NMR) spectroscopy, and Fourier-transform infrared spectroscopy (FTIR) techniques. The thermal stability test of the AC green surfactant demonstrated an acceptable 1.93% weight loss at the 80 °C (reservoir temperature). Additionally, 1H NMR and FT-IR investigations proved the structure of the saponin compound as the surfactant agent. Then, the compatibility tests revealed no precipitation at various concentrations of different salts. The efficiency of the AC green surfactant and HSPAM was examined with three different salts, including K2SO4, MgSO4, and NaCl, as three common salts present in the formation brine (FB) with salinities up to 97,000 ppm. Different experiments, including contact angle and interfacial tension (IFT) measurements, zeta potential measurements, emulsion and core flooding experiments were conducted and the efficiency of these materials for CEOR purposes was examined. The IFT results revealed that 1000 ppm is the critical micelle concentration (CMC) of AC green surfactant in deionized water (DIW). Based on the measured IFT and contact angle values, the most effective salt was K2SO4, followed by NaCl, and MgSO4. The addition of 2000 ppm of HSPAM polymer as the optimum concentration of HSPAM was very efficient in improving the performance of AC green surfactant and producing a higher quality of Winsor type III emulsion. The maximum oil recovery factor of 71.17% was achieved when 1000 ppm of AC green surfactant was injected as the tertiary recovery, and the value was further increased to 77.92% when 2000 ppm of HSPAM and 1000 ppm of AC green surfactant were injected as the tertiary recovery.

New insights of further enhanced tight oil recovery after hydraulic fracturing by VES fracturing fluid

In the process of fracturing in tight reservoirs, viscoelastic surfactant (VES) fracturing fluid has many advantages that can significantly increase the recovery of tight oil. However, there is a risk of formation blockage due to heavy emulsification in the formation. In this study, a VES microemulsion (VES-M) system with low reservoir damage and high oil displacement efficiency is constructed using VES fracturing fluid and polyhydroxy alcohol. The average particle size in the fluid is only 3%–10% of the average pore size of the tight reservoir, and the formation damage is 16.00%. The new fluid can achieve ultra-low interfacial tension (IFT) with Winsor type III microemulsion. Compared with slickwater fracturing fluid and formation water, the new fluid can filtrate deeper into the matrix and increase the oil recovery by 7.20%–11.32% during the flowback process. This study provides a possibility for the field application of VES fracturing fluid in tight reservoirs and new insights into the effects and rules of employing the VES-M system to enhance tight oil recovery.

Synergism of a Novel Bio-Based Surfactant Derived from Pisum sativum and Formation Brine for Chemical Enhanced Oil Recovery in Carbonate Oil Reservoirs

The Pisum sativum (PS), known as the green pea, was used in this investigation to produce a novel green surfactant. The performance of the PS green surfactant was also evaluated using various tests, including contact angle, IFT, emulsion, zeta potential, and oil recovery factor measurement in the presence of formation brine (FB) with a total dissolved solid (TDS) of 150,000 ppm. The characterization study using various tests revealed that the PS green surfactant was nonionic. The critical micelle concentration (CMC) measurement results indicated that the PS green surfactant’s CMC value is 1500 ppm. The IFT and contact angle measurements showed that the green surfactant significantly lowered the IFT and contact angles. The lowest IFT value of 3.71 mN/m and the contact angle of 57.37° were achieved at the FB concentration of 12,500 ppm (optimum salinity). The results of the emulsion tests showed that Winsor type III emulsions were achieved using PS green surfactant and crude oil. The core flooding experiments revealed that the tertiary recovery using a solution of 1500 ppm of PS green surfactant and 12,500 ppm of FB resulted in a maximum oil recovery factor of 83.55%.

Microemulsion fuel formulation from used cooking oil with carbinol as the dispersion phase

ABSTRACT The current research work investigated the suitability of utilizing Used Cooking Oil (UCO) as a substitute for diesel by using the microemulsification technique. A microemulsion-based biofuel system was formulated using UCO and carbinol as the continuous and dispersed phases, respectively. Winsor type IV stable microemulsion fuel was developed by adding Butan-2-ol as the co-surfactant. The formulated fuel samples were observed to be stable for 30 days. A Phase behavior study was conducted on the samples to analyze the system’s stability, and single-phase emulsions were identified. The particle size of the distributed alcohol phase in the identified system was explored using Dynamic Light Scattering (DLS) study and was found to be 14.6 nm. The results of this work showed the viscosity variation, droplet size distribution, and Proton Nuclear Magnetic Resonance (1HNMR) spectrum of UCO and microemulsion fuel. The optimum blend exhibiting fuel properties under ASTM D6751 standards for biodiesel was 50% UCO, 25% Carbinol, and 25% Butan-2-ol by volume. It gave a kinematic viscosity of 5.74 cSt, a density of 0.862 gm/cm3, and a calorific value of 31.5 mJ/kg. This study recommends using UCO-carbinol-based microemulsion fuels as an effective and economical alternative for the biofuel industry.

Smartwater Synergy with Chemical EOR: Studying the Potential Synergy with Surfactants

Summary The potential synergy between smartwater and various enhanced oil recovery (EOR) processes has recently attracted significant attention. In previous work, we demonstrated such favorable synergy for polymer floods not only from a viscosity standpoint but also in terms of wettability. Recent studies suggest that smartwater synergy might even extend to surfactant floods. In this work, we investigate the potential synergy between smartwater and surfactant flooding. Opposed to previous work, the potential synergy is investigated from ground zero. We concurrently developed two surfactant formulations for conventional high-salinity injection water and low-salinity smartwater. To design the optimal surfactant-polymer (SP) formulations, we followed a systematic all-inclusive laboratory workflow. Oil displacement studies were performed in preserved core samples using the two developed formulations with conventional injection water and smartwater. The results demonstrated the promising potential of binary surfactant mixtures of olefin sulfonate (OS) and alkyl glyceryl ether sulfonate (AGES) for both waters. The designed binary formulations were able to form Winsor Type III emulsions besides achieving ultralow interfacial tensions (IFTs). Most importantly, in terms of oil displacement, the developed SP formulations in both injection water and low-salinity smartwater were capable of recovering more than 60% of the remaining oil post waterflooding. A key novelty of this work is that it investigates the potential synergy between smartwater and surfactant-based processes from the initial step of surfactant formulation design. Through well-designed from-scratch evaluation, we demonstrate that surfactant-based processes exhibit limited synergies with smartwater. Comparable processes in terms of performance can be designed for both high-salinity and low-salinity waters. It is also quite possible that the synergistic benefits of smartwater on oil recovery cannot be effective in SP flooding processes, especially with specific surfactant formulations under optimal salinity conditions.

Experimental evaluation of surfactant-stabilized microemulsions for application in reservoir conformance improvement technology

The field of microemulsion-assisted conformance improvement technology (ME-CIT) requires workflow planning in order to effectively decrease the water-to-oil ratio during production operations. This article deals with the implementation of a suitable ME-CIT route via experimental validation. The ternary diagram identified the different Winsor regions to classify phase behavior. The aggregation behavior of micellar structures in ME phase was studied via dynamic light scattering tests. Relative phase behavior experiments depicted the presence of Winsor I phase at low salinity upto 20,000 ppm total dissolved salts (TDS) content. At nearly 25,000ppm, this altered into a Winsor III system. This phase behavior further changed into a Winsor Type III phase at 50,000 ppm. The surfactant-based microemulsion exhibited favorable time-dependent flow attributes, as evident from the observation that the steady-state viscosity did not alter markedly with elapse of time. The pseudoplastic rheology of microemulsion has been explained on a macroscopic level and micelle morphology on a microscopic scale with two phenomena: electro-shielding and micelle deformation. With increasing salinity, the viscosity versus salt concentration plots revealed a unique ‘M’ shape at 7.34 s−1. This describes an initial increase, then a decreasing trend, followed by a increase and eventually a near-constant viscosity as salt content increases further. Porous media flow experiments were conducted for optimized microemulsion slug using a sandstone core model. A favorable pressure drop and reduction in water-cut percentages were recorded during microemulsion flooding stage in the laboratory. In summary, the proposed methodology contributes toward developing potential surfactant-based microemulsions systems for application in conformance improvement technology.

In-Situ Visualization of Imbibition Process Using a Fracture-Matrix Micromodel: Effect of Surfactant Formulations toward Nanoemulsion and Microemulsion

Summary Spontaneous imbibition can help to improve the oil recovery of unconventional reservoirs owing to the significant capillarity. Although the dependence of imbibition dynamics of surfactants on wettability and interfacial tension (IFT) is understood, the mechanisms of nanoemulsion and microemulsion forming surfactants for higher imbibition recovery are not as clear. Herein, we conducted a series of imbibition experiments on a visual fracture-matrix micromodel, aiming to directly observe the imbibition processes of these surfactant formulations. Four surfactant-based fluids, including a common surfactant [fatty alcohol polyoxyethylene ether, sodium sulfate (AES)], a surfactant composition of nanoemulsion (nE-S), an ex-situ nanoemulsion (nE), and a situ microemulsion forming surfactant (mE-FS), were designed and used in this work for comparison with brine. The results suggested that AES, nE-S, nE, and mE-FS could substantially stimulate the imbibition invasion, and mE-FS generated the greatest imbibition depth and sweeping area followed by nE. The imbibition dynamics were governed by the interfacial interactions among oil, aqueous phase, and solid surface, leading to different imbibition patterns for these five fluids. AES and nE-S could reduce the oil-aqueous IFT to 10−1 mN/m and alter the wettability to a weak water-wet state as a result of surfactant adsorption, leading to a slightly higher imbibition invasion compared with brine. AES imbibition produced large oil droplets mainly because of the snap-off effect at the nozzle to the fracture, whereas nE-S produced smaller oil droplets due to the weak in-situ emulsification. nE as a formed nanoemulsion with an internal oil phase demonstrated a lower IFT of 10−2 mN/m and superior capacity in changing surface wettability mainly through the adsorption and spreading of nanosized oil droplets on the surface. The oil phase was heavily emulsified forming dense droplets on the oil-aqueous interface. mE-FS readily formed Winsor Type III microemulsion and produced an IFT of 10−3 mN/m magnitude. The wettability was changed mainly because of the peeling oil film and formation of microemulsion on the surface induced by solubilization. The dynamic increase of the oil-aqueous IFT at the imbibition front caused by the adsorption loss of surfactant to the surface and partitioning to the oil phase promoted capillary-driven imbibition for nE and mE-FS. We modified an imbibition model to incorporate the solubilization effect, leading to a much better fitting with the experimental data.

Remediation of oily soil using acidic sophorolipids micro-emulsion

A sophorolipids (SLs) micro-emulsion in Winsor type I form was used for crude oil contaminated soil washing treatment. The micro-emulsion shows higher oil removal rate than SLs aqueous solution and diesel oil. The type I micro-emulsion with w(SLs) = 6%, w(NaCl) = 1%, w(diesel) = 13.36% gave a high oil removal rate of 95.6% and the eluate remained in type I state. The recovered oil showed lower viscosity, mainly caused by the entering of diesel from the micro-emulsion phase into the oil phase and the lower removal rate of the heavier components, such as the resin and asphaltene. The initial heavily saline-alkaline soil changed into mildly saline-alkaline state after washing treatment, favoring the germination and growth of plants, with ryegrass showing better germination and growth effect than alfalfa. The ryegrass showed good phytoremediation effect on the contaminated soil after SLs micro-emulsion washing. The combination process of SL micro-emulsion washing and ryegrass phytoremediation is prospective for oily soil treatment.

Impact of the molecular structural variation of alkyl ether carboxylate surfactant on IFT reduction and wettability alteration capabilities in carbonates

This paper features an experimental investigation of the effect of single and mixed alkyl ether carboxylate (AEC) surfactants having different molecular structure in altering the wettability of oil-wet carbonate and reducing the interfacial tension (IFT) between oil and brine. All tests were performed at a representative carbonate reservoir conditions; at brine salinity of 196 g/L and temperature of 75 °C. Preliminary compatibility tests revealed that only AEC surfactants having high hydrophilicity; molecular weight ratio of hydrophilic to hydrophobic groups ≥1, were compatible at reservoir harsh conditions and were considered for further analysis. IFT measurements showed that better IFT reduction could be achieved with surfactants having longer branched alkyl chain. Interestingly, inclusion of polypropylene oxide (PO) groups was found to reduce the IFT reduction performances. Only AEC surfactant with branched alkyl chain was able to generate microemulsion Winsor type III. Contact angle measurements using calcite surfaces showed that wettability alteration from strong oil-wet state toward strong water-wet state was obtained with surfactant having the shortest alkyl chain and, correspondingly, highest hydrophilicity. Moreover, this surfactant exhibited the lowest adsorption level on calcite. Adsorption results were further confirmed with thermogravimetric analysis (TGA). Mixing of AEC surfactants resulted in synergistic effect and ultra-low IFT in the order of 10−4 mN/m was obtained. While, no improvement in wettability alteration was observed for the mixed surfactants system. Overall, selection of proper surfactant type is crucial to maximize oil recovery. The novelty of this work resides in quantifying the effect that a particular structural difference could have on the surfactant capabilities in IFT reduction and wettability alteration, which could provide flexibility of tailoring the structure of the surfactant to meet the different reservoir conditions.

Optimization of Low Salinity Water/Surfactant Flooding Design for Oil-Wet Carbonate Reservoirs by Introducing a Negative Salinity Gradient

Engineered water surfactant flooding (EWSF) is a novel EOR technique to reduce residual oil saturation; however, it becomes quite challenging to obtain Winsor Type III microemulsion and the lowest IFT under actual reservoir conditions if only low salinity water is used. The main objective of this study was to design a negative salinity gradient to optimize the performance of the hybrid method. Three corefloods were performed on carbonate outcrop samples. The injection sequence in the first test was conventional waterflooding followed by optimum engineered water injection (2900 ppm) and finally an EWSF stage. The second and third tests were conducted using a varying negative salinity gradient. Engineered water for this study was designed by 10 times dilution of Caspian Sea water and spiking with key active ions. A higher salinity gradient was used for the first negative salinity gradient test. A total of 4300 ppm brine with 1 wt% surfactant was injected as a pre-flush after waterflooding followed by a further reduced salinity brine (~1400 ppm). The second negative salinity gradient test consisted of three post-waterflooding injection stages with salinities of 4600, 3700, and 290 ppm, respectively. Up to 8% and 16% more incremental oil recovery after waterflooding was obtained in the second and third tests, respectively, as compared to the first test. The descending order of brine salinity helped to create an optimum salinity environment for the surfactant despite surfactant adsorption. This study provided an optimum design for a successful LSSF test by adjusting the brine salinity and creating a negative salinity gradient during surfactant flooding. A higher reduction in residual oil saturation can be achieved by carefully designing an LSSF test, improving project economics.

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.

Evaluation of surfactant blends for enhanced oil recovery through activity maps

Better use of already exploited oil reservoirs using Enhanced Oil Recovery techniques is becoming essential. The use of surfactant blends is a common approach when individual surfactants are not effective. However, defining the optimum conditions for application becomes very challenging due to the number of variables involved in specific cases. In this work, blends of dioctyl sulfosuccinate sodium salt with Akypo LF2 and two surfactant ionic liquids (1-decyl-3-methylimidazolium chloride and 1-dodecyl-3-methylimidazolium bromide) were evaluated for oil recovery. Activity maps, representations of the phase behavior of the surfactants as a function of blend ratio, salinity and temperature, were found to be useful tools to describe conditions leading to Winsor type III systems. Among the blends studied, mixtures with Akypo LF2 were found of interest for application at low temperatures, showing interfacial tensions close to 0.01 mN/m in a wide range of salinity concentrations. In the case of blends with ionic liquids, even though they led to more promising solubilization parameters, the high sensitivity of these mixtures to blend ratio changes discourages, in principle, their use for practical applications.

Experimental study on the imbibition mechanism of the Winsor type Ⅰ surfactant system with ultra-low IFT in oil-wet shale oil reservoirs by NMR

Surfactants enhanced spontaneous imbibition is an effective method to improve the oil recovery of shale reservoirs. The popular perspective believes that the wettability alteration and the capillary force are the primary mechanisms. Thus a water-wet condition and a relatively high interfacial tension (IFT) are required. However, in this work, we found that the Winsor type I surfactant solution with ultra-low IFT performed better than other relatively higher-IFT solutions with the capillary effect in oil-wet shale reservoirs. The contact angle, spontaneous imbibition recovery and phase behavior of the Winsor type I surfactant solutions were measured and compared with the solutions with relatively high IFT, including water, nonionic, and anionic surfactant solutions. The results demonstrated that anionic surfactants and Winsor type I surfactant solutions could alter the wettability to a water-wet condition, while the nonionic surfactants could only change to an intermediate-wet state. Both the anionic surfactants and Winsor type I surfactant solutions could displace the oil from micropores and mesopores. Still, the Winsor type I surfactant solutions with ultra-low IFT showed a better performance than the anionic surfactants with relatively high IFT. The interfacial micrographs of the Winsor type I surfactant solutions in contact with the oil phase manifested that the Winsor type I surfactant solutions changed the recovery patterns from two-phase flow driven by capillary force to the migration of microemulsions and emulsions driven by diffusion and gravity. The over-equilibrium Winsor type Ⅲ microemulsions and emulsions are rapidly formed near the oil-water interface. After that, the over-equilibrium Winsor type Ⅲ microemulsions are gradually diluted to Winsor type Ⅰ microemulsions and dissolved in a fresh surfactant solution. At the same time, the emulsions diffuse firstly, then coalesce and migrate out of the pore mediums driven by buoyancy. The water-wet condition and capillary force are not significant for this flow pattern, thus the Winsor type I surfactant solutions with ultra-low IFT are especially effective in recovering the oil of oil-wet micropores and mesopores. This work provides a new way of exploiting the oil in organic matter pores that can barely change to water-wet conditions.

High-Performance Polymeric Surfactant of Sodium Lignosulfonate-Polyethylene Glycol 4000 (SLS-PEG) for Enhanced Oil Recovery (EOR) Process

Recently, the increase in fuel oil demand was not supported by petroleum production due to the low productivity of old wells. Furthermore, an appropriate technology, such as Enhanced Oil Recovery (EOR) technology, is needed to maximize the productivity of the old well. Therefore, the purpose of this study was to synthesize a polymeric surfactant for the EOR process from sodium lignosulfonate (SLS) and polyethylene glycol (PEG) in various SLS to PEG ratios, namely 1:1 (PS1), 1:0.8 (PS2), and 1:0.5 (PS3). The surfactants were characterized using several methods, such as Fourier Transform-Infrared spectroscopy (FT-IR), compatibility, stability, viscosity, and phase behavior tests. The performance of the surfactants for the EOR process in different brine solution concentrations (16,000 ppm and 20,000 ppm) was also studied. The result showed that the introduction of the PEG molecule to the surfactant had been successfully conducted as FT-IR analysis confirmed. The surfactant's hydrophilicity increased with the introduction of PEG due to the increase of the ether group. A Winsor Type I or lower phase microemulsion was formed due to the high hydrophilicity. The highest oil yield (79 %) was obtained by PS1 surfactant, which has the highest PEG dosage, in a brine solution of 1,600 ppm. Therefore, it was concluded that the introduction of PEG could increase the hydrophilicity, viscosity, and EOR performance.

Non‐linearchanges in phase inversion temperature for oil and water emulsions of nonionic surfactant mixtures

AbstractHydrophilic–lipophilic deviation (HLD) is a semiempirical framework for surfactant‐oil–water (SOW) formulation that has effectively assimilated SOW properties such as phase inversion temperature (PIT) and Winsor Type I ↔ II ↔ III ↔ IV microemulsion behavior. The HLD system's reliance on surfactant and oil parameters necessitates their experimental determination when relevant and accurate values are not available. In this study, experiments have been of the type commonly used to generate test surfactant HLD parameters based on perturbation of a well‐defined SOW reference system and assumption of linear mixing behavior for PIT versus component mole fractions. The reference SOW compositions comprisedn‐octane, 0.01 M aqueous NaCl, and puren‐decyl tetraethylene glycol ether (C10E4) reference surfactant. Test surfactants were primary alcohol ethoxylates and nonylphenol ethoxylates comprising disperse PEG (polyethylene glycol) chain lengths that are inherent to commercial production of nonionic ethoxylate surfactants. We observe non‐linear behavior of PIT versus test surfactant mole fraction, even when accounting for surfactant concentration effects, so the desired linear correlation that could otherwise be used to assign an HLD parameter has not been obtained. Since an objective of this study has been to improve the predictive utility of the HLD framework for commercial nonionic surfactants, relevant terms in the HLD equation have been assessed in terms of their potential contributions to non‐linear behavior. One current working‐explanation relates substantial non‐linear PIT contribution to oil‐like surfactant components in disperse commercial ethoxylates.