Surfactant Flooding Research Articles

Quantitative Characterization of Surfactant Displacement Efficiency by NMR—Take the Tight Oil of Chang 8 Member of Yanchang Formation in Fuxian Area, Ordos Basin, as an Example

Surfactant flooding is a pivotal technique for enhancing oil recovery efficiency. The Chang 8 member of the Yanchang Formation in the Ordos Basin exemplifies a quintessential tight oil reservoir. Specifically, 47.9% of wells yield less than 0.1 t/d, 27.0% produce between 0.1 and 0.2 t/d, and 18.8% generate outputs ranging from 0.2 to 0.3 t/d, while only a mere 6.3% exceed production rates of over 0.3 t/d, indicating minimal efficacy of water flooding development in this context. In this study, we conducted an extensive investigation into the geological characteristics of the Yanchang 8 reservoir within the Ordos Basin, leading to the identification and evaluation of three surfactants based on their interfacial tension properties. The optimal injection concentration was determined through on-line displacement nuclear magnetic resonance imaging analysis that refined surface activity conducive to developing the Chang 8 member, ultimately resulting in increased spread volume and enhanced crude oil production from individual wells. The results indicate the following: (1) The interfacial tension of NP-10, FSD-952, and GPHQ-1 at concentrations of 0.05%, 0.1%, 0.2%, 0.3%, 0.4%, and 0.5% exhibited a pattern of initial decrease followed by an increase. The mass concentration corresponding to the minimum interfacial tension for NP-10 is identified as 0.1%, which is also the case for GPHQ-1; however, for FSD-952, this occurs at a concentration of 0.4%. Among the surface-active agents NP-10, GPHQ-1, and FSD-952, GPHQ-1 demonstrated the lowest interfacial tension value at an impressive measurement of 0.0762 mN/m. (2) When the displacement of the 0.1% GPHQ-1 surfactant reaches 10 PV, the displacement efficiency improves from 69.69% to 76.36%, representing an increase of 6.67%. The minimum pore size observed during GPHQ-1 surfactant displacement is 0.01 μm. In contrast, when the displacement of the NP-10 surfactant at a concentration of 0.1% reaches 10 PV, the efficiency rises from 68.32% to 72.02%, indicating an enhancement of 3.7%. The corresponding minimum pore size for NP-10 surfactant displacement is recorded at 0.02 μm. Furthermore, when the displacement of the FSD-952 surfactant at a concentration of 0.4% achieves 10 PV, its efficiency increases from 69.93% to 74.77%, reflecting an improvement of 4.81%. The minimum pore size associated with the activated portion of FSD-952 is noted as being approximately 0.03 μm.

Slow release of surfactant by smart thermosensitive polymer-functionalized mesoporous silica for enhanced oil recovery: Synthesis and characterization

The efficiency of surfactant flooding can be improved through slow-release technology, which enables stimuli-sensitive and gradual release of surfactant. In this study, we synthesized a novel nanocomposite capsule composed of mesoporous silica functionalized with thermosensitive poly N-vinyl caprolactam (PNVCL). Well-optimized nanocarriers were synthesized by conducting sensitivity analyses on key synthesis parameters such as pH, reaction duration, and hydrophobic phase, resulting in hydrodynamic diameters ranging from 47 to 109 nm. Characterization of the nanocarrier structure was performed using dynamic light scattering (DLS), Brunauer–Emmett–Teller (BET) analysis, and field emission scanning electron microscopy (FESEM), while Fourier-transform infrared spectroscopy (FTIR), thermogravimetric analysis (TGA), and energy-dispersive X-ray spectroscopy (EDS) were employed to analyze the nanocarrier composition. Poly N-vinyl caprolactam (NVCL)-functionalized mesoporous silica exhibited high surfactant loading (approximately 52 % w/w) and a large specific surface area (542.88 m2/g), featuring ink-bottle pores. Additionally, it demonstrated thermosensitive behavior, with the lower critical solution temperature of 39 °C. Gradual release of cetyltrimethylammonium bromide (CTAB) was observed in both deionized water and formation brine, with release rates increasing with temperature. Overall, the synthesized nanocomposite carrier holds significant potential as an ideal candidate for effectively controlling the release of surfactants in reservoirs subjected to high-temperature and high-salinity conditions.

Digital core on a chip: Surfactant flooding in low-permeability reservoir

The development of hard-to-recover reserves every year requires ever-more-innovative industrial and laboratory approaches for efficient production of hydrocarbons. Oil industry has recently turned to the use of microfluidic technology to investigate the flow paths and interactions of reservoir fluids under high pressures and temperatures. The present study describes elaboration of a digital core on a chip, i.e. a microfluidic chip with the structure that replicates the void space of a selected reservoir and is designed based on the computed tomography images of core samples. Similarity of core samples and 2D generated structure was controlled through average pore diameter and structure morphology. The manufactured micromodels were used for surfactant compositions screening aiming to demonstrate the technology capabilities for further testing of various enhanced oil recovery (EOR) chemicals.Thus, several surfactants were examined in bulk employing standard screening procedures (stability evaluation, interfacial tension (IFT) measurements and phase behavior test with oil), and then were investigated in transparent microfluidic chips. Visualization of fluid flow in the porous structure is a primary advantage of microfluidics application for EOR. Hence, surfactant coreflooding-on-a-chip enabled correlation of IFT behavior of various surfactants with recovery efficiency, fast detection of in-situ emulsification and fluid flow distribution analysis in the porous media. Generally, symbiosis of two advanced technologies, i.e. microfluidics and digital core modeling, facilitated significant speed up of laboratory tests and reduce of their cost.

Self-assembly behavior of BS12 in water for combination flooding potential: Deep eutectic solvent as a component

Deep eutectic solvent (DES) as standalone or mixed with surfactant flooding has been increasingly recognized and has attracted attention in enhanced oil recovery (EOR). However, the association between self-assembly behavior and the EOR potential of zwitterionic surfactants in DES-water systems has not been profoundly studied. In this work, two choline-based DES were prepared preferentially. The self-assembly and micellar growth of dodecyl dimethyl betaine (BS12) in DES-water systems was investigated by particle size analysis, fluorescence spectroscopy, and transmission electron microscopy. In the system containing 60 wt% DES, micelles were stretched ∼100 times via complexation, hydrogen bond, and electrostatic shield. Afterward, the key parameters of EOR were evaluated. The synergy effect of DES and BS12 in water reduced the critical micelle concentration (cmc) and the oil–water interfacial tension (IFT) to below 1 mmol/L and 0.1 mN/m, respectively. DES strengthened the BS12 aqueous solution to transform the oil-wet sandstone into water-wet. Therefore, the forces on the crude oil in the pore throats may favor its removal. In the mixed system, larger micelles exhibited better crude oil solubilization performance. Compared with the surfactant-alone system, the solubilization and low IFT brought by DESs/BS12 systems increased the cumulative crude oil recovery rate to 10.74 % and 7.61 %, thus showing promising potential for EOR.

3-D Modelling and Simulation of a Reservoir for Surfactant-Polymer Flooding Using Eclipse Software

Surfactant-polymer flooding is a tertiary enhanced oil recovery method used to recover oil that remained in the reservoir after the primary and secondary oil recovery mechanisms. Predicting the pressure in the reservoir is important for oil production as pressure changes with time. A suitable approach to achieve this task is to derive fluid flow equation based on the reservoir characteristics and solve them numerically which provide the solution to the mathematical fluid flow model (diffusivity equation). In this study, 3-D reservoir was modelled using Eclipse software. The fluid flow equations in a porous media were derived based on the simulated model and the reservoir conditions. Numerical solution using implicit formulation to solve the mathematical fluid flow model (diffusivity equation) was investigated by developing Python codes using Jupyter library to ascertain the pressure distribution for the reservoir and imported into Eclipse simulator. Simulation was carried out using surfactant-polymer and reservoir properties to determine the oil recovery. The results of the study showed that pressure increases with time as oil production continued, and water saturation decreased for the grid-cells of the reservoir. Waterflooding had oil recovery of 38.0% and water-cut of 59.0%, while surfactant flooding had oil recoveries of 42.0%, 46.5%, 49.0% and water-cut of 57.0%, 51.0%, 46.3%. In addition, polymer flooding had oil recoveries of 44.3%, 48.4%, 54.0% and water-cut of 50.0%, 45.0% and 33.0% respectively at different concentrations of 0.3%wt. 0.4%wt. and 0.5%wt.

Oscillation-free implicit pressure explicit concentration discontinuous Galerkin methods for compressible miscible displacements with applications in viscous fingering

The system of compressible miscible displacements is widely adopted to model surfactant flooding in enhanced oil recovery techniques, where a low-viscosity fluid is injected underground to replace the high-viscosity oil. When the mobility ratio of the injected fluid to oil is high, the waterflood front tends to be unstable and exhibits a finger-like growth pattern, known as viscous fingering. Due to its unstable nature, the viscous fingering phenomenon is sensitive to mesh orientation and numerical discretization. Therefore, high-order numerical methods are preferable to reduce numerical artifacts and mesh dependence. In this paper, we propose a high-order discontinuous Galerkin method for the coupled nonlinear system of compressible miscible displacements to simulate the viscous fingering fluid instability in porous media. We adopt the IMplicit Pressure Explicit Concentration time marching approach based on implicit-explicit Runge-Kutta methods to achieve high-order temporal accuracy. Additionally, we introduce an oscillation-free damping term to control the spurious oscillations encountered in the waterflood front due to the large gradient of saturation. We have conducted ample numerical tests in two space dimensions to demonstrate the effectiveness and robustness of the proposed schemes in recovering viscous fingering.

Experimental study on enhanced oil recovery of acidic heavy oil by in situ O/W emulsion flooding

Heavy oil in this work is typical acidic heavy oil with acid number larger than 1, which is prone to form W/O emulsions with high viscosity and cause low oil recovery factor during water flooding. In order to further improve oil recovery of acidic heavy oil after water flooding, this paper proposed the in situ O/W emulsion flooding to conversely transform W/O emulsions into O/W emulsion with lower viscosity. Firstly, emulsion system compounding (SDS:L5 = 1:1) named ISEMF was comparatively obtained, which could decrease IFT into magnitude of 10−2 mN/m and inversely form stable O/W emulsions with low viscosity. The emulsion evaluation experiment indicated that W/O emulsion would be reversed into O/W emulsions when ISEMF concentration and water content were larger than 0.4% and 30%. Core displacement experiments showed recovery factor increment firstly increased and then decreased with permeability, and there was optimal permeability range for in situ emulsion flooding. The main reason was that much lower or larger permeability was not beneficial to good matching of emulsion droplet and pore throat. In addition, it was found that the displacement efficiency of in situ O/W emulsion flooding was better than that of surfactant flooding under the same conditions, which further validate excellent EOR performance of in situ O/W emulsion flooding for acidic heavy oil.

Effect of permeability on displacement efficiency and dominant oil–displacement mechanism in surfactant flooding

Interfacial tension (IFT) reduction and emulsification are two important mechanisms of surfactant flooding. However, for light oil reservoirs with different permeabilities, whether which mechanism is more important in improving displacement efficiency remains unclear. In this study, surfactants with strong emulsifying properties and ultralow IFT were screened using an interfacial tensiometer and a self-developed emulsification performance tester. The ability of the two surfactants to improve displacement efficiency was compared through a series of core flooding experiments. Experimental results showed that the surfactant with ultralow IFT did not have strong emulsifying properties. With the decrease in permeability, the oil displacement efficiency improved by emulsification increased first and then decreased, whilst that improved by IFT reduction declined. Moreover, IFT reduction was the dominant mechanism to improve oil displacement efficiency in medium-high and ultralow permeability reservoirs, whilst emulsification was dominant in low permeability reservoirs. The comprehensive utilization of multiple mechanisms and the combination of technologies should be considered when surfactant flooding is used in reservoirs with ultralow permeability. This work advances our current understanding of surfactant flooding and provides a reference for the formulation of plans to enhance oil recovery in light oil reservoirs.

Nanofluid flooding as a method of enhancing oil recovery: mechanism, advantages

Relevance. The fact that with the help of modern methods of increasing oil recovery, it is possible to extract no more than 34 % of oil from the initial recoverable reserves. Therefore, modernization of technologies for tertiary impact on the reservoir as one of the possible ways of developing this area is required. It is possible to use nanoparticles in order to increase the oil recovery coefficient by displacing residual and hard-to-recover oil. Technologies with the use of nanoparticles have a number of significant advantages over the already traditional polymer, alkaline and surfactant flooding. Nanofluidic flooding allows increasing the oil recovery coefficient. The paper considers the mechanisms of action of nanoparticles contributing to oil recovery, the relationship of the effectiveness of flooding from the reservoir temperature, pH, water mineralization and wettability of the reservoir rock surface. These mechanisms are required for identifying limitations of the applicability of nanofluids, the possibility of their modification, in order to improve the properties and eliminate the disadvantages of nanofluid flooding. The effect of the chemical nature of nanoparticles, their size, surface charge, isoelectric point and concentration on rock, reservoir fluids and the efficiency of hydrocarbon extraction is considered in detail. Attention is also focused on the latest modern trends in the development of nanofluidic flooding technology. Aim. To conduct a comprehensive analysis of nanofluidic flooding as a method of increasing oil recovery. Objects. Chemical methods of enhancing oil recovery, nanofluidic flooding. Methods. Analysis of current publications on the research topic. Results. The factors influencing the effectiveness of the use of nanofluids as a method of increasing oil recovery and the mechanisms of the impact of nanoparticles on oil reservoirs are formed, promising directions for the development of nanoparticle technology are identified.

Experimental Investigation of the Effect of Surfactant–Polymer Flooding on Enhanced Oil Recovery for Medium Crude Oil

High technical and financial risks are involved in exploring and exploiting new fields; hence, greater focus has placed on the development of environmentally friendly, cost-effective, and enhanced oil recovery (EOR) options for existing fields. For reservoirs producing high-density crudes and those with high interfacial tensions, water flooding is usually less effective due to density differences—hence the advent of polymer and surfactant flooding. For cost-effective and eco-friendly EOR solutions, a biopolymer and a surfactant synthesized from Jatropha seeds are used in this study to determine their effectiveness in increasing the oil recovery during core flooding analysis. The experiment involved an initial water flooding that served as the base cases of three weight percentages of polymers and polymeric surfactant solutions. The results for the polymer flooding of 1 wt%, 1.5 wt%, and 2 wt% showed an incremental oil recovery in comparison to water flooding of 16.8%, 17%, and 26%, while the polymeric surfactant mixtures of 5 wt% of surfactant and 1 wt%, 1.5 wt%, and 2 wt% of a polymer recorded 16.5%, 22.3%, and 28.8%, and 10 wt% of surfactant and 1 wt%, 1.5 wt%, and 2 wt% of a polymer recorded incremental oil recoveries of 20%, 32.9%, and 38.8%, respectively.

Molecular Dynamics Computational Study of Sustainable Green Surfactant for Application in Chemical Enhanced Oil Recovery.

Green surfactant (GS) flooding, an environmentally friendly chemical Enhanced Oil Recovery (cEOR) method, is explored in this molecular dynamics (MD) simulation study. This study evaluates the ability of (S)-2-dodecanamido-aminobutanedioic as a GS for cEOR, assessing its performance with hexane (C6), dodecane (C12), and eicosane (C20) as representative oils. In the case of the bulk system, a comprehensive molecular-level investigation provides structural details such as the radial distribution function, solvent-accessible surface area, GS adsorption dynamics, diffusivity, and emulsion stability of the GS, oil, and water systems. Also the impact of the three distinct oils on interfacial tension was examined in the existence of GS molecules. The findings reveal rapid GS molecule aggregation and adsorption on oil droplets, with various impacts on emulsion stability depending on the oil type. Additionally, GS enhances the aggregation of heavy C20 oil molecules in a water medium. The study demonstrates GS's role as an effective emulsifier, facilitating oil droplet recovery, with electrostatic interactions governing micelle formation and van der Waals interactions influencing oil droplet emulsification. These results align with prior experimental data, affirming GS's promising application potential in cEOR while prioritizing environmental sustainability.

Nanoparticle-stabilized CO2 foam flooding for enhanced heavy oil recovery: A micro-optical analysis

Surfactant flooding is a well-known chemical approach for enhancing oil recovery. Surfactant flooding has the disadvantage that it cannot withstand the harsh reservoir conditions. Improvements in oil recovery and release are made possible by the use of nanoparticles and surfactants and CO2 co-injection because they generate stable foam, reduce the interfacial tension (IFT) between water and oil, cause emulsions to spontaneously form, change the wettability of porous media, and change the characteristics of flow. In the current work, the simultaneous injection of SiO2, Al2O3 nanoparticles, anionic surfactant SDS, and CO2 in various scenarios were evaluated to determine the microscopic and macroscopic efficacy of heavy oil recovery. IFT (interfacial tension) was reduced by 44% when the nanoparticles and SDS (2000 ppm) were added, compared to a reduction of roughly 57% with SDS only. SDS-stabilized CO2 foam flooding, however, is unstable due to the adsorption of SDS in the rock surfaces as well as in heavy oil. To assess foam's potential to shift CO2 from the high permeability zone (the thief zone) into the low permeability zone, directly visualizing micromodel flooding was successfully executed (upswept oil-rich zone). Based on typical reservoir permeability fluctuations, the permeability contrast (defined as the ratio of high permeability to low permeability) for the micromodel flooding was selected. However, the results of the experiment demonstrated that by utilizing SDS and nanoparticles, minimal IFT was reached. The addition of nanoparticles to surfactant solutions, however, greatly boosted oil recovery, according to the findings of flooding studies. The ultimate oil recovery was generally improved more by the anionic surfactant (SDS) solution including nanoparticles than by the anionic surfactant (SDS) alone.

Effects of block and random copolymerization on the properties of fatty alcohol polyoxypropylene‐polyoxyethylene ether sulfates for enhanced oil recovery

AbstractEnhanced oil recovery (EOR) by surfactant flooding has been attractive. Among the surfactants developed alcohol polyoxypropylene (PO)‐polyoxyethylene (EO) ether sulfates (APES), also named extended surfactants, have been proved efficient. However, the arrangement of the PO and EO chains as well as the hydrocarbon structure in the molecules may significantly affect their performances. In this paper three APES, C18−16PO25EO10SO4Na (I), C18−16(PO/EO)25+10SO4Na (II), and C16GA(PO/EO)25+10SO4Na (III) were prepared and investigated, in which APES (I) and APES (II) were designed to have same PO and EO numbers but block and randomly copolymerized respectively with linear C18−16 fatty alcohols as starting agent, whereas the APES (III) was derived from double chain C16 Guerbet alcohol (C16GA) with PO and EO randomly copolymerized. The results show that the block copolymerized APES (I) gives much better brine solubility and counterion tolerance than the randomly copolymerized APES (II) and (III). Although all APES synthesized are highly surface‐active and can reduce Daqing crude oil/simulated brine interfacial tension (IFT) to ultralow by mixing with more hydrophobic surfactants in presence or absence of alkali, the APES (III) gives the lowest IFT due to with double hydrocarbon chains. In addition, it is found that for APES (I) gelation occurs in neutralization process and the corresponding nonionic intermediate is highly viscous, whereas the randomly copolymerized two intermediates are liquid‐like with low viscosity, which may be feasible to apply SO3/air falling film sulfation. This study provided useful information for arrangement of embedded nonionic moiety and hydrocarbon structure in designing extended surfactants for EOR.

Early warning methods of chemical agent channeling in polymer–surfactant flooding reservoirs

AbstractIn the chemical flooding process, the premature breakthrough of chemical agents in production wells results in a large waste of chemical agents and increases the volume and processing difficulty of the produced fluids. The early warning method of chemical agent channeling can predict the strength of agent channeling in advance. The practice of chemical flooding shows that the production performance can be used for early warning of chemical agent channeling. In this paper, we analyze the relationship between cumulative oil production and cumulative polymer production of production wells in polymer–surfactant flooding. Three types of curves according to the enhanced oil production characteristics of chemical flooding, including convex type, S‐type, and concave type. We use the drop speed of the water–oil ratio and the rapid‐decline speed of water cut as early warning indicators to predict the channeling coefficient. A Latin hypercube experimental design method is used to design a polymer–surfactant flooding scheme with the main control factors of the channeling coefficient and early warning indicators. Numerical simulation is used to calculate samples of the channeling coefficient and early warning indicators under various conditions. The drop speed of the water–oil ratio reference value model and the rapid‐decline speed of the water cut reference value model are determined with a multiple regression method. A prediction model for the chemical agent channeling coefficient is established using the deviation coefficient of an early warning index. The method is applied in the Ng54‐61 polymer–surfactant flooding pilot area in the west of the Gudong Seventh District, Shengli Oilfield, China, and the error between the predicted result and the actual value is less than 10%. This research is helpful in taking effective antichanneling measures and improving the oil recovery degree of chemical flooding reservoirs.

Effect of surfactant adsorption on the efficiency of drainage displacement at different viscosity ratios: A lattice Boltzmann study

Surfactant flooding is an effective method for enhanced oil recovery, accompanied by the adsorption of surfactant molecules during their transport in porous media. This paper studies the effects of surfactant adsorption on immiscible two-phase flows in porous media and focuses on two primary objectives. The first is to identify the influence of the water/oil viscosity ratio on the maximum adsorbed amount of surfactant. The second scope involves establishing a relationship between the viscosity ratio and the effect of surfactant adsorption on the displacement efficiency during drainage displacement. The novelty lies in the identification of new patterns characterizing the adsorption effect on the displacement efficiency depending on the viscosity ratio. The main results are based on statistical data collected from numerical simulations performed on various synthetic 2D micromodels. The lattice Boltzmann method was used as a mathematical model. It has been established that the adsorbed amount is influenced by the viscosity ratio as follows: the higher the oil viscosity, the less the adsorbed amount. However, the effect is not strong. An increase in oil viscosity leads to a decrease in the adsorption effect on displacement efficiency. This finding is determined by two factors: the maximum adsorbed amount and the adsorbed amount at the moment of surfactant breakthrough. It has been found that if surfactant adsorption is neglected, the viscosity ratio does not affect the increment in oil recovery compared to the injection of pure water. However, if adsorption is taken into account, an increase in oil viscosity enhances the effect of surfactant flooding on displacement efficiency. The dependence of the viscosity ratio on the adsorption effect on oil recovery obeys linear law. This trend was confirmed in a digital 3D model of natural sandstone obtained using X-ray computed tomography.

An Overview of Oil Recovery Techniques: From Primary to Enhanced Oil Recovery Methods

As we all know, numerous methods have been invented for better managing of the reservoirs to recover the trapped oil from them as much as possible. These techniques included primary techniques that were implemented primarily at the beginning of this industry. As these techniques were not effective enough, secondary techniques, like; water flooding and gas injection methods were created and the amount of recovered oil were increased, as well. On the contrary, the demand for more oil was raised up and it was felt that much more effective techniques are necessary. It resulted to creation of Enhanced Oil Recovery Techniques and these techniques are included; thermal methods (steam injection, steam assisted gravity drainage and in-situ combustion), Chemical methods (alkali flooding, surfactant flooding, polymer flooding, foam flooding, and combination of alkali-surfactant-polymer flooding), and microbial EOR. The most promising technique is microbial EOR because of being cost-effective and ecofriendly. GEMEOR (Genetically Engineered MEOR) and EEOR (Enzyme Enhanced Oil Recovery) are two new trends of MEOR that own potential hopes in petroleum industry.

Experimental study of adsorption/desorption and enhanced recovery of shale oil and gas by zwitterionic surfactants

Shale reservoirs have the characteristics of low permeability and low porosity. In order to enhance the recovery of shale oil and gas, surfactant flooding is a mature reservoir oil recovery method. However, the adsorption of different surfactants on the reservoir rock surface is restricted, depending on the type of surfactant. Therefore, a zwitterionic surfactant (OPHS) was synthesized from oleic acid, 3-dimethylaminopropylamine and sodium 3-chloro-2hydroxypropanesulfonate, and characterized by FTIR, 1H NMR, and TGA, and the mechanism of the OPHS for enhancing oil and gas recovery on shale surfaces was investigated. The results showed that the critical micelle concentration (CMC) of OPHS surfactant solution is 7.9 × 10-4 mol/L and the γCMC is 27.5 mN/m; the concentration of 0.1 % OPHS surfactant solution could reduce the contact angle of the cores from 127.2° to 38.8°, which resulted in spontaneous imbibition; The absolute Zeta potential of shale particles in the OPHS surfactant solution was measured at 39 mV, whereas in deionized water at 15.3 mV. This difference can be attributed to the formation of a stable hydration film on the surface of shale particles induced by the wetting reversal effect. Spontaneous imbibition experiments showed that a 0.1 % solution of OPHS surfactant was able to increase the recovery rate by more than four times compared to the imbibition solution without added surfactant; In high-pressure gas adsorption/desorption experiments, the OPHS surfactant solution demonstrated a higher affinity for adsorption onto the shale surface. It effectively occupied adsorption sites, ultimately facilitating methane gas desorption from the shale. In summary, OPHS zwitterionic surfactants exhibit the capability to desorb hydrocarbons from shale pores through mechanisms such as wetting reversal and competitive adsorption. This research holds significant potential for advancing the field of shale oil and gas recovery, providing valuable insights for enhancing recovery processes.

A Laboratory Experimental Study on Enhancing the Oil Recovery Mechanisms of Polymeric Surfactants.

In order to evaluate the physical and chemical properties of polymer surfactants and analyze their oil displacement mechanisms, three types of poly-surfactant used in the Daqing oil field were chosen to be researched, and the oil displacement effects were studied using poly-surfactants of different viscosity, dehydrating rate, and core permeability. The main purpose is to determine the reasonable range of different characteristic indexes of polymeric surfactant flooding. The oil displacement effect of 15 cores was analyzed, and the effects of viscosity, the dehydrating rate of emulsion, and permeability on EOR (Enhanced Oil Recovery) were analyzed. The oil displacement mechanisms of polymeric surfactants were researched using a photolithographic glass core. This paper explores the mechanism underlying production enhancement as an EOR target, while simultaneously conducting laboratory tests to assess the physical and chemical properties of polymeric surfactants. The poly-surfactant agents exhibit a notable increase in viscosity, with the optimal displacement effect observed at a core effective permeability exceeding 400 mD, resulting in a potential EOR of 15% or higher. Moreover, at a viscosity ranging between 40 and 70 mPa·s, the total EOR can reach 73%, with the peak efficiency occurring at a viscosity of 60 mPa·s. The water loss rate of the emulsion, ranging between 30% and 70%, achieves optimal performance at 50%. The poly-surfactants' higher viscosity extends the oil sweep area, enhancing recovery efficiency, and noticeably reducing residual oil compared to water flooding. During poly-surfactant flooding, a substantial amount of residual oil is extracted and transformed into droplets. The rapid emulsification of the polymeric surfactant solution with crude oil forms a stable emulsion, contributing to its significant oil recovery effect. This research provides valuable technical support for EOR in thin and low-quality reservoirs of onshore multi-layered sandstone reservoirs.

Interfacial Behaviors and Oil Detachment Mechanisms by Modified Silica Nanoparticles: Insights from Molecular Simulations.

Surfactant flooding has been considered as a promising approach for chemically enhanced oil recovery (EOR). However, this technique encounters several limitations, such as high costs, environmental concerns, and reduced efficiency under high-temperature and high-salinity reservoir conditions. Recently, nanoparticles have also been proposed as an alternative for EOR due to their superior properties compared with surfactants. This research employs molecular dynamics simulations to explore the impact of modified SiO2 nanoparticles on oil-water interfacial behaviors and the detachment of oil droplets from an oil-wet surface. The simulation results reveal that modified nanoparticles, featuring hydrophilic and hydrophobic functional groups, have slight impacts on interfacial tension reduction of the oil-water interface. Nanoparticles with varying degrees of modification exhibit distinct positions within the interface, consequently influencing the thickness of the interfacial layer. Notably, the interactions among the nanoparticles, oil molecules, and surface facilitate the formation of a water channel, thereby enhancing the process of oil detachment. Comparative analysis indicates that in terms of oil displacement efficiency, the thickness of the interfacial layer has a more significant impact than interfacial tension reduction. Furthermore, to elucidate the mechanisms of modified nanoparticles enhancing the oil recovery rate, the interaction energies among the oil droplet, nanoparticles, water, and surface are analyzed. The molecular-level insights derived from this investigation could provide valuable guidance for the design of modified nanoparticles tailored to EOR applications.

Chemical enhanced oil recovery under Harsh conditions: Investigation of rock permeability and insights from NMR measurements

Injecting surfactant into a hydrocarbon reservoir stands out as a highly effective method for EOR due to its ability to reduce water/oil IFT and alter rock wettability in certain cases. However, the efficiency of this process is compromised in heterogeneous reservoirs, especially carbonates, characterized by significant permeability variations. This study presents findings from three core flooding experiments on heterogeneous carbonate core samples with different permeabilities. The experiments were conducted under representative reservoir conditions of 100 °C, pressures higher than 3000 psi, and seawater salinities and formation water of 57,745 ppm and 213,768 ppm, respectively. In each experiment, seawater was continuously injected followed by continuously injecting a 2500-ppm solution of in-house synthesized Gemini surfactant. Results revealed that the recovery factor was highest in low-permeability rocks and lowest in high-permeability rocks for both seawater and surfactant floods. Surfactant floods yielded additional recoveries of 31%, 23%, and 19% for low, medium, and high-permeability samples, respectively. Nuclear magnetic resonance (NMR) analysis on short analogous core plugs at different flooding stages confirmed these results. Effluent analysis on the produced aqueous phase indicated that dynamic retention was highest (0.467 mg/gm-rock) in the lowest permeability and lowest (0.146 mg/gm-rock) in the highest permeability rock. NMR analysis suggested that the surfactant's recovery performance and dynamic retention were influenced by the larger surface area of low-permeability rocks, facilitating increased contact with the surfactant. Utilizing NMR monitoring in this work enhances EOR insights through integrated studies and coreflooding experiments and establishes a novel framework for complex reservoir conditions.