Surfactant Flooding Research Articles

Rapid evaluation model for EOR techniques applicability of gas flooding, foam flooding and surfactant flooding based on modified fractional flow theory

Before a wide range of enhanced oil recovery (EOR) techniques were implemented for an oilfield, the EOR potential and economic evaluation of the techniques should be evaluated in advance for each reservoir to determine which EOR technique was proper. In an oilfield developed with fluvial delta reservoirs, the complicated distribution of scattered small reservoirs in vertical and horizontal directions brought trouble for evaluation work. A rapid and reliable evaluation model for EOR techniques applicability was necessary to deal with the evaluation simulation for many small reservoirs of an oilfield. Combining fraction theory model with auxiliary equations, which describe the effect of formation heterogeneity and mechanism of different EOR technique on fractional flow rate, an evaluation analysis method for EOR techniques applicability of gas flooding, foam flooding and surfactant flooding was proposed. In the gas flooding model, the minimum miscible pressure of impure gas was introduced, and the relative permeability was modified by the minimum miscible factor. In the foam flooding model, changes in the mobility ratio and chemical adsorption were considered and a reduction factor of mobility ratio was introduced. In the surfactant flooding model, calculation formulas of viscosity and interfacial tension as well as the relative permeability were introduced. Finally, the model was simulated for a low permeability reservoir, and the simulation results were compared with that from Eclipse software. The similar results, little calculation time and feasibility of predicting optimal injection parameter had shown the reliability of the rapid evaluation model.

Prediction of the Viscoelastic Properties of a Cetyl Pyridinium Chloride/Sodium Salicylate Micellar Solution: (II) Prediction of the Step Rate Experiments.

The reliable viscoelastic characterization and prediction of micellar solution is still required in industrial applications of the solution, e.g., in surfactant flooding and pharmaceuticals. Based on the recent theoretical characterization of the viscoelastic properties of a cetyl pyridinium chloride/sodium salicylate (CPyCl/NaSal) wormlike micellar solution with a structuralized constitutive model in the work published in 2022, the present work predicted five groups of transient shear viscoelasticities of the solution experimentally obtained in 2010, which include the first normal stress difference (N1) versus time curve in the start-up experiment, the shear stress (τ12) in the start-up experiment, τ12 in the long-term start-up experiment, the stress relaxation upon cessation of steady shear flow, and the transient N1/τ12 in the step strain experiment. The study findings clearly show an improvement in the predictions of the viscoelastic properties of the micellar solution compared with those predicted previously. For example, the experimental N1/τ12 is 9 at the strain of 9 in the step strain experiment, and the corresponding previous and present predictions are 2.47 and 8.45, respectively.

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.

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.

Adsorption of surfactant during chemical enhanced oil recovery

AbstractSurfactant is extensively used as chemicals during chemical enhanced oil recovery (CEOR) process. Effectiveness of surfactant CEOR process depends on several parameters like formation of micro emulsion, ultra‐low interfacial tension (IFT) and adsorption of surfactant. First two parameters enhance the effectiveness while the last parameter reduces the effectiveness. Micro emulsions are highly desirable for CEOR due to its low interfacial tension (IFT) value and higher viscosity. In this research the size of the emulsions were studied with particle size analyzer to study the liquid–liquid absorption process and the entrapment of oil drops inside surfactant drop. Initially, the average surfactant drop size was found to be 100 nm, after mixing the surfactant slug with reservoir crude, the size was increase up to 10 times. It signifies the formation of micro emulsion between surfactant and oil. Another attempt was done in this research to study the adsorption mechanism of surfactant on reservoir rock. The process of adsorption was studied by Langmuir and Freundlich isotherm to understand the adsorption phenomena. In this study, it was found that the adsorption follows Freundlich isotherm and the adsorption phenomena was chemical for surfactant flooding process. In chemical adsorption phenomena, the rate of adsorption is high because, surfactant molecules are adsorbed layer after layer by the rock surface. Use of alkali along with surfactant reduces adsorption of surfactant since, alkali blocked the active clay sites before interacting with surfactant and hence the adsorption isotherm was found to be Langmuir and phenomena was physical adsorption.

Modeling of High-Pressure and High-Temperature Microemulsion Experiments using HLD-NAC-Based Equation of State

Summary Surfactant flooding is a promising technique that can reduce interfacial tension (IFT) between oil and water to ultralow values, mobilizing previously trapped oil. For reservoirs at moderate to high pressures, understanding and modeling how pressure affects the phase behavior of a surfactant-brine-oil system is important to the design and implementation of an efficient/cost-effective surfactant flooding project. Typically, however, phase behavior experiments and models of that phase behavior are made only at low pressures. The main objective of this paper is to show how to model experimental data in a unified way for a large range of pressure, temperature, and other parameters, using hydrophilic-lipophilic deviation (HLD) and net-average curvature (NAC)-based equation-of-state (EOS). Pressure and temperature scans show that pressure has a significant effect on the surfactant microemulsion phase behavior, shifting it from an optimal three-phase system at low pressure to a nonoptimal two-phase system at high pressure. Further, multiple scans at different water/oil ratios (WORs) show a shift in the optimum indicating that phase behavior partitioning of the various components is changing with oil saturation. We obtained good fits of all experimental data including all two- and three-phase regions using a single tuned HLD-NAC EOS for a wide range of simultaneous variations in pressure, temperature, salinity, and overall composition. Such a simultaneous match and prediction by a single set of model parameters has never been done before. We also demonstrate the type of data needed for an accurate EOS. When input into a numerical simulator, the tuned EOS improves the predictions of the resulting phase behavior (size and shape of the two-phase lobes and three-phase regions) and IFTs with changing pressure, temperature, salinity, WORs, and surfactant/alcohol concentrations.

Laboratory evaluation of red onion skin extract and its derivative as biomass-based enhanced oil recovery agents

The use of natural alternatives as oilfield chemicals is gradually gaining attention among researchers due to their eco-friendly nature. The aim of this study was to determine the efficiency of red onion skin extract (ROSE) at recovering residual oil using the mechanism of surfactant flooding in sandstone reservoirs at reservoir conditions and compare its effectiveness in its pristine and modified state. ROSE was obtained by solvent extraction of the waste biomass (red onion skin) using acetone. The extract was chemically modified using glutaraldehyde. Phase behavior analysis in the presence of divalent ions at high temperatures (80 ˚C) and sandstone core flooding were performed to determine the fluid compatibility and displacement efficiency. Results show high compatibility and solubility of pristine (unmodified) and modified ROSE in soft and hard brine. Core flooding analysis showed a higher recovery of 32.1% and 36.5% original oil in place (OOIP) for 0.3 wt.% modified ROSE as compared to a recovery factor of 31.8% and 35.0 % OOIP for 0.5% unmodified ROSE in soft and hard brine respectively. It further reveals an increase in additional recovery at surfactant concentration in hard brine above critical micelle concentration (CMC). Results of statistical significance test showed that modified ROSE exhibited superior performance and a higher recovery relative to unmodified ROSE especially in hard brine. This is a novel work as red onion skin extract was derivatized with glutaraldehyde and successfully recovered additional residual oil under hard brine and reservoir temperature making them potential surface-active agents for chemical enhanced oil recovery.

Numerical Simulation by STARS (CMG) using Surfactants for Enhanced Oil Recovery in a Reservoir

In Ecuador, heavy crude oil represents 20% of the proven reserves at the national level. However, producing them has been challenging because of their low recovery factor due to their characteristics, high oil viscosities, and low mobility, among others. This makes developing and implementing improved or tertiary recovery methods and technologies necessary; therefore, the aim is to produce the maximum available resources in an environmentally friendly way. New advances in hydrocarbon extraction technologies in recent years have been tested and one of them, on which this research focuses, is using chemical methods in which solvents are injected to modify viscosity in aqueous solutions. Thus, displacing the oil generates very low interfacial tensions between the crude oil and water by adsorption in the liquid-liquid phase. Therefore, the selection of a reservoir that meets the required characteristics for the respective application of this method was carried out. Furthermore, increasing the sweep efficiency will optimize the mobility of the oil bank toward the producing wells, thus improving the recovery factor. Consequently, upon running the simulation, the results show that continuous surfactant flooding resulted in 84.5% recovery, SP flooding 89.4%, and ASP flooding with the highest recovery factor of 90.13%. This is due to the synergistic contribution of the IFT reduction using surfactant and the mobility ratio per polymer reduction, thus improving the overall sweep efficiency by a better margin. At the same time, alkali is responsible for decreasing the amount of the active surfactant used as it is a lower-cost agent [1].

Technology Focus: EOR Operations (November 2022)

Among the different enhanced-oil-recover techniques, waterflooding is still commonly practiced in part because of its economic potential. During the past 2 years, many papers presented at SPE meetings have dealt with different aspects of waterflooding design, optimization, monitoring, and low-salinity applications. Understanding the injected-water preferential paths is a key aspect of waterflood optimization in reservoirs characterized by strong vertical and areal heterogeneities. Devising specific work flows for such applications is important. These can be easy but powerful tools for visualizing the complex dynamic connections between injectors/producers and aquifer influence areas. They can enable improving the business-time decision-making cycle, resulting in increased operational performance and lower waterflood operating costs by consolidating end-to-end optimization work flows in one platform. Using artificial intelligence (AI) and machine-learning (ML) approaches with reduced-physics models can reduce the time required for this task. Also, ML allows for fast screening of waterflood performance at diverse levels (e.g., reservoir, sector, pattern, and well), enabling prompt identification of opportunities for immediate uptake into an opportunity-management process and for evaluation in AI-driven production forecasting or in a reservoir simulator. As part of waterflood optimization, changing the chemistry of the injected water has been under investigation since early 2000. This process has been named differently in different laboratories (e.g., smart water and low-salinity waterflooding, or LoSal). The new studies are related to its field application. It is interesting that new hybrid applications such as low-salinity water with surfactant flooding and carbonated smart water injection are showing up in the literature. As we move forward, it is expected that the waterflooding recovery factor will increase with additional technology advancements. Recommended additional reading at OnePetro: www.onepetro.org SPE 209426 - Impact of Brine Chemistry on Waterflood Oil Recovery: Experimental Evaluation and Recovery Mechanisms by Behdad Aminzadeh, Chevron, et al. SPE 205426 - Pump Up the Volume—Massive Water-Injection Increase Through Open-Water Stimulations by Alistair Roy, BP, et al. SPE 210154 - Middle East Giant Carbonate Field: Integrated Water-Injection-Optimization Work Flow by Stefano Del Fraro, Eni, et al.

Oil Recovery Performance by Surfactant Flooding: A Perspective on Multiscale Evaluation Methods

Chemical-enhanced oil recovery (cEOR) is a class of techniques commonly used to extract hydrocarbon fluids from reservoir rocks beyond conventional waterflooding. Surfactants are among the chemical agents employed in a cEOR process, as they aid in enhancing oil recovery by lowering the oil–water interfacial tension (IFT) and altering the rock wettability toward less oil-wet conditions. Understanding the flow characteristics and mechanisms involved during surfactant flooding helps improve the performance of injected surfactants and results in higher oil recovery. The objective of this review is to outline the recent applications of the different methods employed to understand the behavior and mechanisms involved during surfactant-enhanced oil recovery. The review begins with a general background highlighting the basic characteristics of surfactants and the main mechanisms by which they exert their influence. Recent studies conducted to investigate the oil recovery performance through different methods are then presented, including traditional coreflooding experiments, microfluidics studies, and oil recovery through sand packs. The methodology of the analysis and the interpretation of the data obtained from the different oil recovery tests, including oil recovery factor, pressure data, and relative permeability, are also described. Pore-scale analysis and imaging methods including nuclear magnetic resonance (NMR), magnetic resonance imaging (MRI), and X-ray medical and microcomputed tomography (μCT) scanning and their applicability in assessing the recovery performance are described. Finally, a few examples of field monitoring methods for surfactant flooding are highlighted. This review provides knowledge of the different multiscale evaluation methods and their applicability during surfactant flooding.

Interfacial tension test analysis as injection fluid on reservoir core


 In the petroleum industry, Enhanced Oil Recovery (EOR) technology has been developed to obtain increased oil recovery from reservoirs. One of the EOR methods is chemical EOR using a surfactant known as the surfactant flooding method. Surfactants have the ability to reduce the interfacial tension between oil and water in the rock matrix so that residual oil can be produced. There are several parameters that affect the performance of surfactants, among which will be discussed in this discussion, namely the middle phase emulsion obtained from the phase behavior test and the results from the Interfacial Tension (IFT) test. Based on the literature review, the method used in IFT uses the spinning drop method. Compatibility test of Fir wood SLS surfactant solution used with a concentration of 0.5% - 3% and a salinity of 4,000 - 110,000 ppm.

Molecular dynamics simulation of enhancing surfactant flooding performance by using SiO2 nanoparticles

In this study, four kinds of commonly used surfactants in oil fields, namely anionic surfactant sodium dodecyl sulfate (SDS), cationic surfactant hexadecyl trimethyl ammonium bromide (CTAB), nonionic surfactant primary alcobol ethoxylate (AEO-9) and zwitterionic surfactant dodecyl dimethyl carboxyl betaine (BS-12), were used as the research objects. The oil–water interfacial behaviors at different concentrations were studied by molecular dynamics simulation. Then, silica (SiO2) nanoparticles were combined with surfactant to observe the influence of nanoparticles on the configuration of surfactant monolayer, and to explore the optimal conditions for the synergistic flooding scheme of these nanoparticles and surfactant. The thickness and density of the oil–water interface layer, the radial distribution function (RDF) between the surfactant head group and water molecules, the mean square displacement (MSD) of water molecules around the surfactant head group, the oil–water interfacial tension (IFT) and the surfactant interface formation energy (IFE) were investigated. Surfactant flooding performance of different types and the effect of nanoparticles on surfactants were discussed. The results show that the surfactant with different ionic types have the best concentration in reducing the oil–water interfacial tension, and the interfacial tension is significantly reduced to 7.33 mN/m after adding nano-SiO2 particles in BS-12. After kinetic equilibrium, SDS and CTAB are arranged in an approximately regular manner, non-polar groups are inserted into the oil phase, polar groups extend into the aqueous phase, the long-chain head groups of AEO-9 molecules spread and stack at the interface, and BS-12 is irregularly distributed and some molecules are immersed in the oil phase. After adding nano-SiO2 particles, SDS, BS-12 and nano-SiO2 particles can be observed mutually repulsive in the interface morphology, while CTAB, AEO-9 and nano-SiO2 particles exhibit mutual attraction.

A comprehensive study on the application of a natural plant-based surfactant as a chemical enhanced oil recovery (CEOR) agent in the presence of different ions in carbonate reservoirs

Surfactant flooding is a promising CEOR approach in carbonate reservoirs and its efficiency has been verified. Commercial surfactants may impose various health and environmental issues. Therefore, utilizing a natural biodegradable surfactant at a low cost is a valuable option for the petroleum industry. In this research, a non-ionic surfactant derived from Acanthophyllum Plant Root Extract (APRE) was used as a bio-surfactant. The EOR potential of this surfactant was evaluated through various tests. Oil-water system interfacial tension (IFT) measurement, contact angle test for carbonate rock wettability alteration assessment, emulsion stability, compatibility, and surfactant flooding test were conducted. The effect of different ions of various salts on the IFT, carbonate rock wettability and the chemical interactions were also studied. The emulsion stability created by the surfactant was assessed through observational tests. The compatibility test (at 25 °C) showed that negligible sediment below the salinity of 50,000 ppm was formed. The IFT at CMC in formation water (optimum concentration of 12000 ppm) was reduced to 1.06 mN/m from an initial value of 2.16 mN/m. The optimum IFT value at different salinities was also determined. The wettability of the carbonate rock from a strongly oil-wet state (168°) was altered to water-wet (60.3°) in the presence of surfactant and FW with a concertation of 10,000 ppm. In the core flood test, the effect of different slug sizes and soaking time was also determined. It was observed that increasing slug size results in a lower mobility ratio and consequently higher oil recovery.

Improvement of oil recovery factor in tight reservoirs: A laboratory approach based on carbon dioxide enhanced oil recovery methods

Production from unconventional oil reservoirs has always been a critical issue for the oil industry. In this regard, we implemented a set of experimental scenarios containing CO2/N2 cyclic injection, the foams generated by nitrogen and carbon dioxide, cyclic carbon dioxide injection, and a combined effect of carbon dioxide and surfactant enhanced oil recovery methods. As water injection has reached a plateau around two pore volume injection, we continued the tests from two pore volume injection for different scenarios. It was observed that CO2/N2-foam has the highest oil recovery factor of 34.9%; however, CO2-foam, regarding more feasibility than N2, witnessed the highest oil recovery factor after CO2/N2-foam. On the other hand, the incremental oil recovery factor for surfactant flooding, carbonated water flooding, and carbonated water with surfactant flooding is measured at 4.9, 8.5, and 10.6%, respectively.

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

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

Application of Surfactant-based enhanced oil recovery in carbonate Reservoirs: A critical review of the opportunities and challenges

The oil productionfromcarbonate formations is low because of complicatedcompositions, formation heterogeneity, oil-wet/mixed wet conditions, etc. Primary recovery depends on the reservoir's natural resources for production and is often supplemented by secondary recovery methods such as water flooding or immiscible gas injection to generate an artificial drive and complement reservoir energy. Tertiary recovery strategies should be used to mobilize residual oil saturation and increase oil recoveries from these reservoirs using various chemical flooding and chemical agent systems. Polymer flooding, surfactant flooding, alkali flooding, and combinations of these flooding methods are different types of Chemical floodingEOR (C-EOR) technology. Surfactant flooding procedures have been regarded as reliable EOR methodsfor field utilization because they minimize interfacial tensions and modify reservoir rock wetting characteristics, reducedcapillary forces and thus promote oil recovery. This paper provides a review of field projects and large-scale operations of surfactantfloodingin carbonate reservoirs. The fundamentalprocesses of various chemical systems, as well as the interactions of various compoundswith reservoir rocks and fluids, have been examined. After a sequence of assessment steps, the required surfactant flooding for a range of specific reservoir conditions is determined. The properties of a surfactant such as formulation and characteristics of reservoirs such as temperature, salinity, pH, rock permeability, formation type, wettability and other considerations are discussed. Moreover, since carbonate reservoirs are distinguished with a considerableheterogeneity, high temperature, and high salinity conditions, surfactant and polymer choosingfor these kind of reservoirs is a difficult process that requires experimental test to obtain the best quantity and composition of chemicals. Field project design and technical insights can be used to generate innovative strategies that will have a direct effect on the internationaloil supply in the immediate future.

Experimental studies of surfactant-polymer flooding: An application case investigation

A great deal of oil field is currently produced using water flooding and the water cut has reached a high level, which requires enhanced oil recovery (EOR) techniques to improve the recovery. Surfactant-polymer (SP) flooding is the combination of surfactant flooding and polymer flooding. The polymer is added to increase the viscosity and viscoelasticity of the fluid while the surfactant is included to decrease the oil–water interfacial tension and change the wettability. Although the mechanism of SP flooding has been deeply investigated, the application of SP flooding on a specific oil field requires the selection of optimal SP system. Therefore, for the first time, we performed a series of experiments to determine the optimal SP system for high water-cut oil field. In the injection capability experiment, we observe that the SP system is injected into the core with less resistance compared with single polymer solution. In the flooding experiment, regardless of the polymer types, the improvement of recovery becomes significant when the injected PVs increases. SP flooding shows the higher improvement of recovery compared with single polymer flooding or surfactant flooding. Based on the performance of recovery improvement, we recommend the optimal SP system for the studied case is the combination of DQ-TSRP01 polymer and surfactant. The optimal injection parameters of this SP system are 1500 mg/L polymer concentration, 0.3 injection PV and the injection timing of 96% water cut. The finding of this study can help for better understanding of the application of SP flooding in high water-cut oil field production.

Application of alkalis, polyelectrolytes, and nanoparticles for reducing adsorption loss of novel anionic surfactant in carbonate rocks at high salinity and temperature conditions

Surfactant and alkaline/surfactant/polymer (ASP) flooding are commonly used chemical enhanced oil recovery (EOR) methods. However, they are traditionally carried out in sandstone reservoirs and not in carbonates due to high adsorption of surfactant onto carbonate rock and, therefore, economic expenses. One of the strategies to reduce surfactant adsorption is the application of adsorption inhibitors. Therefore, this work evaluates the performance of a novel nonionic-anionic surfactant composition designed for a carbonate field with high temperature (70 °C) and salinity (201 g/L). The study focuses on the adsorption behaviour of surfactant onto the rock surface through a static adsorption test using high-performance liquid chromatography (HPLC) and interfacial tension (IFT) measurements for surfactant concentrations determination. The adsorption data obtained were analyzed with equilibrium models (Langmuir, Freundlich). In order to find the chemicals able to decrease the adsorption loss, a list of alkalis, polyelectrolytes, and nanoparticles was tested for compatibility and thermal stability, pH and interfacial performance in mixture with the surfactant. Then, the effectiveness of agents that passed the screening criteria was examined. It was found that the selected adsorption inhibitors decreased the adsorption significantly and reached a value lower by one order of magnitude in comparison with the surfactant. To the best of our knowledge, this is the first work that compares the effectiveness of all types of adsorption inhibitors that are mainly applied in EOR, namely alkalis, polyelectrolytes, and nanoparticles. The outcomes of this study contribute to the future design of surfactant flooding in carbonates even in harsh reservoir conditions.

Literature Review of Nanotechnology in the Enhanced Oil Recovery.

In recent studies, there has been an increasing focus on Nanoparticles Enhanced Oil Recovery (NPEOR). NPEOR is a method that was initially developed to improve microscopic and macroscopic displacement efficiency. In some recent applications NP have been assisted the conventional EOR methods such as a polymer, surfactant, and Co2 flooding, with the purpose of increasing the oil recovery. In this literature, the abilities to use NP in EOR are investigated. The function of different types of NP, different types of Dispersing agents, availability of nanomaterials in the lab, the effect of nanoparticles to change the properties, future challenges and concerns about the NP, are reviewed. However, the stability of suspensions of NP is still the most barrier to use NP in EOR. Upcoming studies are necessary to focus on the outcome of the appropriate techniques of NP to improve their stability under the worst conditions of reservoirs and investigate new types of nanoparticles.

How does phase behavior of surfactant/fluid/fluid systems affect fluid-fluid displacement in porous media?

Surfactant flooding is widely used in subsurface applications where high displacement efficiency is needed, such as nonaqueous phase liquid (NAPL) remediation and enhanced oil recovery (EOR). For surfactant/water/oil systems, the partitioning of surfactants in each phase is controlled by external factors, such as salinity. The third phase, microemulsions, which locates between water and oil, can be formed spontaneously at certain salinities. Therefore, the transfer of surfactants from water to other phases, which depends on salinity, can occur during surfactant flooding, resulting in spatially non-homogeneous surfactant concentrations. The critical parameters governing the displacement dynamics, such as contact angle and interfacial tension (IFT), can vary considerably due to spatially non-homogeneous surfactant concentrations. However, the influence of spatially non-homogeneous contact angle and IFT on the displacement in porous media has not been sufficiently explored. In this work, we visualized the surfactant flooding at different salinities in 2D micromodels. Our results suggest that the displacement patterns vary considerably with salinity. One displacement front was observed at low salinity, while displacement front separation occurred at intermediate and high salinity, forming two different displacement fronts. At intermediate and high salinity, we noticed that the downstream displacement was imbibition, while the upstream displacement was drainage. We suggest that the separation of displacement fronts was capillary-driven, arising from spatially non-homogeneous contact angle and IFT. Our study provides new insights into the effect of the phase behavior of surfactant/water/oil systems on displacement patterns.