Nonequilibrium surfactant partitioning into microdroplets generates local phase inversion conditions and interfacial instability.

Enhanced heavy oil recovery through interfacial instability: A study of chemical flooding for Brintnell heavy oil

Micromechanism of partially hydrolyzed polyacrylamide molecule agglomeration morphology and its impact on the stability of crude oil−water interfacial film

The impact of connate water saturation and salinity on oil recovery and CO2 storage capacity during carbonated water injection in carbonate rock

The hydrocarbons (oil and/or gas) volume that can be economically extracted of a field is called reserves.This volume will always be inferior to the existent total volume, once only part of the oil contained in reservoir can be removed.In the studies done for enhanced oil recovery, several methods are used.In some, just pressure is used to increase the recovery, as water injection and, in other, the miscible techniques are more used.The most important factors in enhanced oil recovery are mainly the interference caused by parameters such as capillary forces, interfacial tension between the fluids, permeability, porosity and wettability of solid surface and oil viscosity, where the main objective is to increase the oil recovery with minimum of interference.Conventional oil recovery methods have some disadvantage, getting low displacement efficiencies and, consequently, low recoveries when the injected fluid can not remove the oil from rock pores due to high interfaces tension.The enhanced oil recovery, specially chemical methods, particularly surfactants solution injection, are processes which requires a chemical interaction between reservoir and injected fluids and is considered a good alternative for increasing recovery.These methods become advantageous, because the surfactants have the purpose of reducing the interface tension between water and oil, increasing the displacement efficiency and, consequently, increasing the recovery factor.The surfactants used for recovery may be ionic or non-ionic.The non-ionic have an important property to be assessed during its injection into oil reservoirs that is the cloud point.The solubility of nonionic surfactants decreases with increasing temperature and they may lose their properties above a certain temperature called cloud temperature.This is because, at temperatures above the cloud point, the homogeneous surfactant solution separates into two immiscible phases with well defined composition, one of which contains much of surfactant, called surfactant-rich phase or coacervate phase, whereas the other, called water phase, is almost free of micelles and has a surfactant concentration near its critical micelle concentration (c.m.c.).Based in this, the objective of this study was to determine the cloud points of surfactant solutions (C, D and E) used to increase the oil recovery factor.The solutions showed concentrations of salt (KCl and NaCl), 2, 5, 10 and 15 g mL -1 .The results indicated that cloud temperature decreased with increasing salt concentration and increased with increasing chain of hydrophilic surfactant (number of ethylene oxide).The surfactants D and E were the ones that presented the cloud temperature above the average temperature of oil wells (~70 C), at high concentrations of salt e more number of ethylene oxide in chains.However, the surfactant D obtained a low recovery factor (11.1%), the surfactant E the most suitable for the operations of enhanced oil recovery, with 35.0% of recovery factor. IntroduoOs reservatrios, cujos mecanismos so pouco eficientes, e que, por conseqncia, retm grandes quantidades de hidrocarbonetos aps a exausto da sua energia natural, so fortes candidatos ao emprego de uma srie de processos que visam obteno de uma recuperao adicional.Esses processos so chamados de mtodos de recuperao que, de uma maneira geral, tentam interferir nas caractersticas do reservatrio que favorecem a reteno exagerada de leo. O comportamento dos

The application of Enhanced Oil Recovery (EOR) methods is essential to promoting increase in the oil recovery where the conventional recovery methods unsuccessful. Numerous studies have demonstrated that microemulsion and surfactant systems injection can change the properties of fluids and increase the oil recovery. In this work, flooding tests were carried out combining brine and microemulsion in different proportions and schemes of injection. Microemulsion systems constituted by: Ultramine 200, n-butanol, kerosene and water were obtained and characterized by measurements of droplet diameter, surface tension, interfacial tension (IFT), and viscosity. The surfactant concentration in the microemulsion was evaluated on the oil recovery through flooding experiments. This study also evaluated how surface and interfacial tensions influence crude oil recovery (29° API). Results demonstrate that the oil recovery increases with the increase in surfactant concentration in the microemulsion. However, that increase is significant only up to 9 wt%, reaching an additional 21% oil recovery of the original oil in place (OOIP). This research recommends chemical method to EOR tests by combined injection from microemulsion and brine. The chemical action of microemulsion system results in a miscible phase, promotes oil mobilization, improve brine flooding, and increase the oil recovery.

Enhancement of oil recovery by emulsion injection: A pore scale analysis from X-ray micro-tomography measurements

Experimental and numerical investigation of mutual solvents for EOR applications

Migration of fines, and formation of oil emulsion have been independently observed during smart water flooding both have been suggested to play a vital role in enhanced oil recovery (EOR). But, the exact role of fines and the reason of emulsion formation are not well studied for carbonate reservoirs. This study shows that addition of water and crude oil on calcite fines leads to formation of soluble oil emulsions in the water phase. Formation of these emulsions and its implication in EOR has been experimentally analyzed. To characterize the formation of theses emulsions study has been conducted for various water insoluble salts were used as fines (including, Li2CO3, MgCO3, CaCO3, CaSO4, SrSO4, BaSO4 and reservoir CaCO3 fines). Different types of oil and water was added to these fines. To study conditions of oil emulsion formation, design oil was used consisting of hexane and hexadecane. Heptylamine and hexadecylamine were doped in various compositions to mimic the base number of the oil. Experiments were conducted for pure crude oil and doped oil to understand its implications in EOR. Composition of initial and final floating oil was obtained through gas chromatographic (GC) analysis. The two were thereafter compared to obtain the composition of micelles formed. The experiments showed how oil emulsions were formed when polar hydrocarbons are present in the oil. Mixtures of alkanes did not produce emulsions. In oil containing hexadecylamine 95% of the initial hexadecylamine was accumulated in the emulsions and only 5% was found in the floating oil. In oil samples containing heptylamine only 45-50% of its initial amount was accumulated in the emulsions. This indicates heavier amines can form more stable emulsions. Oil emulsions were produced with all the fines used, but the composition of these emulsions were dependent on the salt anions. In all carbonates, lighter amines preferred emulsions formation with lighter alkane. No such selectivity was observed in any of the sulfates. Results obtained with crude, doped and designed oil were consistent for both pure salts and outcrops. These results show that fines of carbonate released during fracturing, or sulfates formed during smart water flooding can form mixed wet water soluble oil emulsions which help to mobilize trapped oil, and increase the sweep efficiency. The results clearly show oils with the same base number can have significantly different amount of emulsion formation with fines, and provides a detailed mechanism of further characterization of the oil. The study highlights the significance of fines during smart water flooding in carbonate reservoirs and shows how its role in EOR can be mistakenly underestimated.

Jatropha curcas contains extractable renewable non-edible oil which can be converted into surfactant suitable for oil recovery due to its hydrophilic property. Chemically, it contains high fatty acid components comprised primarily of oleic acid (44.7%) and linoleic acid (32.8%). In this study, a surfactant based on Jatropha oil was developed and tested against the interface tension reduction in the presence of alkaline, co-solvent and brine. Jatropha fatty acid was extracted via saponification process and neutralized with sodium hydroxide yielding sodium fatty acid. The performance of the synthesized surfactant was studied by measuring the interfacial tension (IFT) between the surfactant solution and crude oil, and its phase behaviour at reservoir temperature. Phase behavior is dependent upon the surfactant, alkaline and brine concentration, which are expressed as viscosity of the microemulsion. In order to mobilize residual oil trapped by capillary forces in oil reservoirs, many enhanced oil recovery (EOR) methods rely on reducing the oil-water IFT to extremely low values by using lowest surfactant concentration. Dulang crude oil used have high contain of wax and low acid value react with surfactant which contains fatty acid and reacts with the alkaline solution to produce in situ surfactant (ionized acid) which be able to lowers the oil-water IFT. The ionized acid is surface active and has a tendency to partition into the aqueous phase where it may form soap with sodium ions present in the surfactant and aqueous phase at a high ionic strength. The soap has a trend to partition into the oil phase. The removal of the ionic acids from the interface can cause low dynamic IFT. The result of this work indicates that the lowest IFT of surfactant concentration are distinctive for the different alkaline concentration. Significantly, the increase of surfactant concentration amplified the microemulsions. This enhanced the viscosity of the aggregated phase. Furthermore, makes the process economical for the best oil recovery.

Subsequent CO2 injection can enhance oil recovery and achieve carbon sequestration in shale reservoirs, which is crucial for energy sustainability and environmental protection. However, for continental sedimentary shale oil, the development process must consider the multiscale matrix-fracture structure and the impact of heterogeneous wettability on f luid-solid interactions. Moreover, the mechanisms of CO2 miscibility and interfacial behavior in post-fracturing reservoirs remain unclear. In this study, a laminated shale micro-model with fracture based on scanning electron microscopy observations was designed, and the process of fracturing fluid flowback and subsequent CO2 huff-n-puff were simulated. Results showed that forced imbibition primarily affects limestone layers, while spontaneous imbibition affects mudstone layers, contributing 89.3% and 10.7% to the affected area, respectively. The oil recovery mechanism of CO2 is mainly influenced by pressure, transfer from displacement-carry at low pressure to dissolution-extraction, and eventually to diffusion-extraction in the miscible state. Additionally, before reaching miscibility, Taylor dispersion, Kelvin-Helmholtz instability, Rayleigh-Taylor instability, and Marangoni effects occur at the oil-CO2 interface, leading to interfacial turbulent instability. Lastly, water huff-n-puff produces membrane and isolated droplet residual oil, while immiscible CO2 breaks cluster residual oil into columnar residual oil. Miscible CO2 enhances the recovery of various residual oils, improving oil recovery and facilitating CO2 storage. This study provides insights for post-fracturing CO2 huff-n-puff development of continental sedimentary shale oil and CO2 sequestration, promoting energy utilization and environmental improvement. Document Type: Original article Cited as: Li, L., Zhang, D., Su, Y., Zhang, X., Lu, M., Wang, H. Microfluidic insights into CO2 sequestration and enhanced oil recovery in laminated shale reservoirs: Post-fracturing interface dynamics and micro-scale mechanisms. Advances in Geo-Energy Research, 2024, 13(3): 203-217. https://doi.org/10.46690/ager.2024.09.06

Chapter 7 - Mass transfer by molecular diffusion

Enhanced oil recovery (EOR) is important for extracting the remaining oil from mature reservoirs. Oil Production Companies all over the world are trying to increase oil recovery and decrease water production. Finding new methods for EOR is critical for keeping the oilfield profitable for many. One method that has growing interest is chemical injection with Surfactant. The purpose of this work is to understand the effectiveness of a surfactant on EOR on a mature reservoir. The aim is to find out how different concentrations of surfactants change the wettability of mature reservoirs (Wettability is the tendency of a fluid to adhere to a surface). There are two main types of wettability: oil-wet where oil adheres to the rock, and water-wet where water adheres to the rock. This chemical is used as a cleaning agent and soil penetrant for fertilizers and has the bonus of being nontoxic versus typical chemical flooding. By using the Surfactant, the wettability can be changed in the formation from being oil-wet to water-wet. This is important since if the production oil wells are oil-wet the oil is wanting to stick to the rock and the wells are only pumping salt water to the surface. Salt water can be very corrosive to equipment and if it creates a leak it can critically harm the environment as well as being costly to clean. The approach for this project is to saturate a core sample 100% with oil and then put it into an Amott Cell with a surfactant solution. Several chemical solutions were used with various concentration of surfactants. The core samples are a few different rock types such as shale, limestone, and sandstone. These core samples were baked dry, vacuumed, soaked in crude oil, and then placed into the Surfactant with weights being taken dry, oil wet, and post treatment. These work results show that different densities can also play a role into how you want it to perform and adapt it to the situation. Surfactant can be denser than oil, allowing it to drive it upward aiding water drive, or it can also be miscible, or simply mixed, due to shared or similar densities. The latter would also require separation from the oil and would need to be pumped back into the formation. The last set of tests were completed with some different trials starting as a group and then moving to individual tests. The outcomes of this work shows that as surfactant concentration increases oil recovery also increases logarithmically.

Enhanced oil recovery (EOR) is the process of residual oil production in the tertiary stage. It requires the injection of external energy sources such as gases, chemicals, and thermal energy in the reservoirs. Chemical enhanced oil recovery (CEOR) can boost the oil recovery significantly by improving the microscopic displacement of oil trapped in the pore spaces of the reservoir rock. Each type of chemical flooding depends on different mechanisms to enhance the oil recovery. Surfactant flooding aims to reduce interfacial tension, alter the wettability of rock to more water wet, and promote the displacement of oil in porous media. The surfactant performance can be affected by temperature, salinity, pH, surfactant concentration, and adsorption. Hence, a comprehensive study of fluid–fluid and rock–fluid interactions is required before any surfactant flooding process. This characterization study aims to evaluate the cationic surfactants, tetramethylammonium chloride (TMAC) and hexadecyltrimethylammonium chloride (HTMAC), which have the potential to be EOR fluids for carbonate reservoirs in harsh conditions. The surfactant solutions were prepared in seawater. TGA, FTIR, solubility and compatibility, IFT, contact angle, and zeta potential tests have been carried out to characterize these surfactants. The obtained results revealed that the cationic surfactants are stably compatible under harsh conditions. Moreover, the results demonstrated that HTMAC has high potential to be used as an EOR fluid by lowering the IFT from 21.4 to 0.16 mN/m and shifting the contact angle from 159.6 to 40° within 24 h of aging at a low concentration (100 ppm). In contrast, TMAC has little effect on IFT; it reduced IFT from 21.4 to 10.2 mN/m and could not alter the wettability to a water-wet condition. Further investigation has been done using a cosurfactant (SS-885) with TMAC to evaluate the effect of this mixture on IFT and contact angle. Using a low concentration (100 ppm) of the mixture reduced the IFT to an ultralow value (0.03) mN/m but had little effect on the contact angle.

Enhanced Oil Recovery (EOR) operations in complex reservoirs frequently contend with persistent crude oil-water emulsions, necessitating the use of chemical breakers to separate phases and improve hydrocarbon recovery. Traditional emulsion breaker technologies often suffer from limited efficacy under reservoir-specific conditions such as high salinity, extreme temperatures, and heterogeneous fluid compositions. This paper presents a comprehensive technical review of next-generation microemulsion breaker technologies, emphasizing their chemical architectures, performance mechanisms, and field-reported capabilities. Building upon the theoretical principles of microemulsion systems—comprising surfactants, co-surfactants, oil, and water phases—the study explores classification schemes (Winsor types), interfacial phenomena, and thermodynamic stability factors that influence efficacy in EOR applications. The review further evaluates emerging trends in high-performance surfactants, nano-enhanced systems, and stimuli-responsive formulations that exhibit superior emulsion breaking efficiency and environmental compatibility. By analyzing laboratory-to-field transition metrics and published field performance indicators, the study identifies critical enablers and deployment barriers. Finally, it outlines future research pathways, including AI-guided formulation development and multifunctional chemical design, that hold promise for scalable, efficient, and sustainable EOR implementations.

One major drawback in the implementation of CO2/surfactant enhanced oil recovery is the high cost of the surfactant volume needed and the extrapolated amount of surfactant required for use in the field. Therefore, there exists a need for a methodology to evaluate the most economic surfactant volume that will lead to optimum oil production. This paper presents the results of laboratory experiments that were designed to study the performance of foam injection and to obtain information on the parameters that will be utilized in a future modeling study to determine the minimum but most effective volume of surfactant needed for optimum foam generation and hence oil recovery in a porous medium. The effect of reservoir pressure and surfactant concentration is studied. Carbon dioxide and surfactant solution were co-injected into Berea sandstone core that was saturated with brine and oil after a waterflood process. Some of the values of parameters utilized in the experiments include surfactant concentrations of 0.1 wt % and 0.5 wt %, average back pressure of 2350 psi and total flowrate of 0.4 cm3/min, with CO2 injected at 0.3 cm3/min and surfactant concentration at 0.1 cm3/min, which results in a volumetric flow ratio of 3:1 and foam quality of 75%. Results show that at a higher surfactant concentration, more oil was recovered, and a steady increase in pressure difference was observed. This indicates that foam was formed, which was also seen at the production end of the system. The foam created during the experiments with the 0.1 wt % surfactant concentration, on visual inspection, appeared to be weaker than that formed in the case of the 0.5 wt % concentration.