Tertiary Oil Recovery Process Research Articles

Alkane-Strengthened Viscoelasticity in Micellar Solutions of Surface-Active Ionic Liquids and Their Potential Application in Enhanced Oil Recovery.

Wormlike micelles (WLMs) are highly sensitive to alkanes, resulting in structural destruction and loss of viscosity. Therefore, the study of WLMs against alkanes holds great significant importance. Surface-active ionic liquids have shown increasing promise for different situations for customizing molecular structures with the specialty of flexible functional assembly. In this paper, we found that WLMs constructed from the long-chain fatty acid surface-active ionic liquid (N,N-dimethylbenzylamine-oleic acid, abbreviated as BD-OA) exhibit strengthened viscoelasticity with the introduction of alkanes, expanding the resistance range to alkane damage. Here, the rheological behavior, microstructure, and dissipative particle dynamics (DPD) simulations of BD-OA WLMs were investigated at macro-, micro-, and mesoscopic scales, before (and after) the introduction of alkane. Our findings confirm the structural transformation of the micellar system from WLMs to lamellar micelles with higher viscoelasticity after alkane induction. The rearrangement of the micelle configuration may be attributed to the infiltration of alkane molecules into the fence layer formed by the BD-OA WLMs, leading to an increase in the boundary accumulation parameter and ultimately resulting in the formation of lower curvature lamellar micelles. More importantly, the against alkanes BD-OA WLMs have exhibited excellent in enhanced oil recovery, which has a promise for substituting common oil-displacing agents in tertiary oil recovery processes.

Modeling and semi-analytical solution for immiscible and miscible fingers formation during enhanced oil recovery

ABSTRACT The fingering phenomenon arises during the secondary and tertiary oil recovery processes when injected fluid (water, gases, nano/biomaterials, or polymer particles) shoots through a porous medium at a relative speed. Oil recovery is influenced by various factors including the fluid type, capillary pressure, permeability, and porous material structure. All these elements play crucial roles in determining the success and efficiency of the oil recovery process. Many scientists have debated the fingering phenomenon from different perspectives. Here, we developed mathematical models with and without considering mass flow rates of oil and water for an inclined oil layer flowing through a homogenous porous medium to generate immiscible fingers. Furthermore, a mathematical model of miscible viscous finger formation with carbonated water injection (flooding) during the enhanced oil recovery process (EOR) has been analyzed in this paper. To solve each of these mathematical models, we used the recently developed approach known as the Method of Directly Defining the inverse Mapping (MDDiM). We found approximate solutions to the nonlinear partial differential equations (PDEs), which describe each modeling of the fingering phenomenon in a homogeneous porous medium by incorporating gravitational effects for several types of flooding and discussed the effects of the saturation rate.

Simulation of the multiphase molecular effect of polymer flooding oil

Polymers are widely used in the tertiary oil recovery process due to their high stability, light weight and low cost. However, the macroscopic experimental research of polymers is limited by its own hypothetical conditions and cannot obtain good simulation results, which is not enough to reveal the mechanism of polymer flooding. In this paper, combing chemical, computer science and molecular dynamics methods, using non-ionic polyacrylamide, a polymer flooding model is established to simulate the movement of multiphase molecules in the process of polymer flooding from the microscopic level.Studying the diffusion, adsorption and aggregation of multiphase molecules, it was found that the diffusion rate of water molecules and NPAM molecules decreases with the growth of NPAM molecular chains. When NPAM molecules reach the critical concentration of aggregation, the interaction force between NPAM and kaolinite reaches saturation. Shearing can disrupt the length of NPAM molecular chains and accelerate the diffusion of NPAM molecules. The phenomenon of local aggregation of NPAM molecular chains in polymer solution systems occurs. revealing the interaction process of multiphase molecules in the process of polymer flooding, quantifying the diffusion laws of three molecules (polymer, oil and water), and enriching the theoretical system of polymer flooding flow.

Synthesis and Enhanced Oil Recovery Potential of the Bio-Nano-Oil Displacement System.

Nanoparticles (NPs) have attracted great attention in the tertiary oil recovery process due to their unique properties. As an economical and efficient green synthesis method, biosynthesized nanoparticles have the advantages of low toxicity, fast preparation, and high yield. In this study, with the theme of biotechnology, for the first time, the bio-nanoparticles reduced by iron-reducing bacteria were compounded with the biosurfactant produced by Bacillus to form a stable bio-nano flooding system, revealing the oil flooding mechanism and enhanced oil recovery (EOR) potential of the bio-nano flooding system. The interfacial properties of the bio-nano-oil displacement system were studied by interfacial tension and wettability change experiments. The enhanced oil recovery potential of the bio-nano-oil displacement agent was measured by microscopic oil displacement experiments and core flooding experiments. The bio-nano-oil displacement system with different nanoparticle concentrations can form a stable dispersion system. The oil-water interfacial tension and contact angle decreased with the increase in concentration of the bio-nano flooding system, which also has a high salt tolerance. Microscopic oil displacement experiments proved the efficient oil displacement of the bio-nano-oil displacement system and revealed its main oil displacement mechanism. The effects of concentration and temperature on the recovery of the nano-biological flooding system were investigated by core displacement experiments. The results showed that the recovery rate increased from 4.53 to 15.26% with the increase of the concentration of the system. The optimum experimental temperature was 60 °C, and the maximum recovery rate was 15.63%.

Microscopic experiment study on mechanisms of oil-gas interaction and CO2 -surfactant flooding with different temperatures and pressures

For secondary and tertiary oil recovery processes, the interfacial interactions between injected gas and crude oil contributes significantly at the pore-scale. We experimentally examine the effect of temperatures, pressures and surfactants on interfacial interaction, contact angle and oil displacement efficiency of CO2 flooding at the pore-scale using microfluidics. Two types of flow channel designs are utilized in this study, blind end of direct channels and curved channels with different diameters. The results indicate that increasing pressure and adding surfactants can promote the contact between oil and gas and reduce the interfacial tension, which has a certain impact on oil displacement efficiency. In the process of gas flooding, CO2 dissolution, expansion and miscibility are the key oil-gas interactions. The results of experiments in curved and direct channels show that the curved channels increase the resistance of fluid flow and limit the contact between CO2 and oil. And with the decrease of the porous medium radius, the capillary action in the pores increases, and the higher the viscous force needed for displacing the oil, which will affect the interaction between oil and gas and the oil recovery in micro pores. Then, two non-ionic alkoxylated surfactants (i.e. ethylene glycol butyl ether and Span 80) were selected to enhance the interaction between CO2 and crude oil. The presence of surfactants increases the solubility of CO2 in crude oil, which reduces the interfacial tension of the system and results in higher oil recovery.

Bacillus subtilis‐based microbial enhanced oil recovery (MEOR) in polymer microfluidic chip

AbstractMicrobial enhanced oil recovery (MEOR) is a tertiary oil recovery process that manipulates the microbial environment inside oil reservoirs to modify the physical/chemical properties of the reservoirs to enhance the oil recovery. Up to now, the detailed MEOR mechanism is still not entirely clear due to the multiple influence factors (e.g., pH, nutrients, temperature, porosity, and permeability) on microbial growth and reproduction, as well as the lack of understanding of microbial's influencing mechanism on the oil recovery process. In this study, a Bacillus subtilis‐based MEOR process was conducted in a polymethyl methacrylate (PMMA)‐based microfluidic device to mimic the MEOR process in the reservoir. The porous microstructure based on real sandstone slice images was fabricated with laser ablation on a PMMA substrate. Two different MEOR approaches were conducted in the PMMA‐based microfluidics devices: the direct injection of displacing reagent (biosurfactant produced by bacteria) into the microfluidic chip for the oil recovery (ex‐situ), and the incubation of bacteria solution inside the chip followed with brine flooding (in‐situ). The result indicates the ex‐situ MEOR process with B. subtilis can reach a recovery rate of 38.56%, while the in‐situ MEOR process with B. subtilis reached a recovery rate of 40.27%. The proposed study provides a new tool for understanding the MEOR process, with advantages in visibility and accurate fluid control during the MEOR process.

Inyección de emulsiones en núcleos empacados de arena Ottawa y arenisca Berea como método de recuperación mejorada de petróleo

Two oil-in-water emulsion systems with drop size less than 6 µm were evaluated to be used as part of an enhanced oil recovery method. Oil recovery tests were run through a forced imbibition study simulating secondary and tertiary oil recovery processes in porous media such as packed cells with Ottawa sand and Berea sandstone cores. The results show that the emulsions exhibited higher recovery percentage in Berea sandstone than the one obtained with Ottawa-sand-packed cores. Crude-oil-based emulsion showed recovery efficiency above 18.1 % in Berea sandstone at a flow rate of 0.16 mL/min at 78 ºC.

Optimization of Enrichment and Isolation Media of Thermophilic Hydrocarbonoclastic Bacteria Isolated from Oil Reservoir of West Java for Microbial Enhanced Oil Recovery (MEOR) Application

Microbial enhanced oil recovery (MEOR) is a tertiary oil recovery process which aims to increase the crude oil recovery uptake to 55% from its original oil in place. In its application, indigenous microorganisms are commonly used as the main biological agents, but the isolation processes become more complicated due to environment’s extreme condition. This study aims to determine the optimum formulation for the enrichment and isolation medium, in order to obtain a highly diverse of indigenous hydrocarbonoclastic bacteria. The isolation process was carried out in two stages; the isolation of mild oil fraction degrading bacteria, and isolation of the heavy oil fraction degrading bacteria which confirmed by the SARA (saturated, aromatic, resinic, and asphaltic) fraction chromatography analysis. Four enrichment and five isolation media were formulated based on the distinction in the macro-and micronutrient composition. Overall, a total of 92 isolates were successfully isolated. The highest bacterial diversities were achieved in the enrichment medium B (crude oil used as carbon source which supplemented with sodium lactate) and isolation medium I (nutrient agar with twice agar concentration), each with 37 and 33% of obtained isolates, respectively. The newly formulated medium can be further utilized to isolate various types of indigenous bacteria from the oil well which were able to degrade SARA fraction from crude oil. The result showed that ABG2-7 as the isolate with the highest activity on SARA degradation. The amount of 15% inoculum of ABG2-7 isolate was able to degrade heavy crude oil, thus might serve as potential bacteria for MEOR application.

Adsorption of Surface Active Ionic Liquids on Different Rock Types under High Salinity Conditions

A new class of surface active ionic liquids (SAIL) have been reported to be a greener alternative to the conventional surfactants in enhanced oil recovery (EOR). These SAILs work efficiently under harsh salinity conditions encountered in the reservoir thereby recovering more additional oil during the tertiary oil recovery process. Adsorption mechanism of SAILs on different rock surface is however, not yet reported in the literature. This article highlights adsorption mechanism of three cationic SAILs having different headgroups, viz., imidazolium, pyridinium, pyrrolidinium, on different rock surfaces (crushed natural carbonate rock and crushed sandstone rock). All the SAILs studied here however had the same tail length and same anion (Br−) attached to it. XRD and XPS characterization techniques reveal that the crushed natural carbonate rock contains a substantial amount of silica, thus rendering it a slight negative charge. Static adsorption tests show that the retention efficiency on the natural carbonate type of rock for all the SAILs was lower than the conventional cationic surfactant, CTAB. The adsorption data obtained thereby was examined using four different adsorption isotherm models (Langmuir, Freundlich, Redlich-Peterson, and Sips). Results suggest that Sips adsorption isotherm model can satisfactorily estimate the adsorption of all the surface active agents on the natural carbonate rock. Factors like mineralogical composition of rock surface, presence of divalents, temperature, and structure of surfactants strongly affect the amount of surfactant adsorbed on reservoir rock. In order to evaluate the simultaneous effect all these factors as well as their interdependence on the retention capability of the three SAILs, a design of experiments approach has been employed further in this study. Statistical analysis of the data obtained after performing the full factorial experiments reveal that at high salinity, imidazoluim based SAIL show minimal adsorption on crushed natural carbonate rock at higher temperature. In general, at a given ionic strength, with increasing temperature as the amount of divalent in the aqueous solution increases, the amount of SAIL adsorbed on both the rock types decreases. Electrostatic attraction is the basic mechanism in governing adsorption of SAILs on the two types of rock surfaces. Results presented in this work can be used for EOR schemes.

Influence of the polymer properties and numerical schemes on tertiary oil recovery processes

Chemical Enhanced Oil Recovery (EOR) processes comprise a number of flooding techniques aimed at increasing the operational life of mature oilfields. Among these, polymer flooding is one of the most developed; its functionality is to increment the aqueous viscosity, avoiding the formation of viscous fingering. Reservoir simulators consider this influence as well as other physical properties (e.g., adsorption, permeability reduction). However, the polymer degradation is usually not considered even though it plays a critical role in the viscosity. In this paper this mechanism is analyzed and coupled with the previously mentioned physical phenomena in order to present a complete study of their influence in the EOR process. Moreover, since a fully second-order accuracy scheme is used along with a Total Variation Diminishing (TVD) flux-limiting function, the influence of the latter on the recovery factor is also discussed. Results showed that the negative effect of the polymer adsorption was the most relevant physical phenomenon in terms of the oil recovery. Furthermore, the analysis of the discretization of the differential equations showed that traditional, linear first-order schemes created numerical diffusion affecting negatively the macroscopic sweeping efficiency, which disappeared when TVD techniques were used. Reservoir simulators allow determining the desired designing properties for future polymers in relationship with the characteristics of the oilfield to be exploited.

Effects of the water-oil volume ratio and premixing or pre-equilibration on the interfacial tension and phase behavior of biphasic mixtures

The interfacial tension (IFT) between an aqueous surfactant solution and displaced crude oil in a tertiary oil recovery process is the most important parameter affecting the oil mobilization. The key question, which has not been addressed previously in a systematic way, is which IFT is the most relevant to the oil recovery: the un-pre-equilibrated IFT, or the IFT obtained after the aqueous solution has equilibrated, totally or partially, with the oil. The un-pre-equilibrated IFT values may be close to the IFT values of oil/water during the initial stages of the oil recovery process before phase equilibration. Conversely, the pre-equilibrated IFT values may be close to the IFTs during the later oil recovery stages, because then the phases are closer to equilibrium. Here, we compare the IFT behavior in the laboratory at 24 °C and at 1 atm of un-pre-equilibrated and pre-equilibrated systems of a crude oil, a brine containing eight salts, and a commercial surfactant. The synthetic brine used is similar to the one present in an actual oil reservoir. The surfactant used here is a commercial anionic surfactant, PETROSTEP® S-13D HA, which is the sodium salt of a single-extended-isopropoxylated-chain sulfate. The pre-equilibrated equilibrium IFT (EIFT) values are quite different from the un-pre-equilibrated EIFT values. In addition, the effects of three mixing methods and the water-to-oil volume ratio (WOR) on the pre-equilibrated IFT were evaluated. Of the three methods examined here, (A) mild mixing, (B) magnetic stirring, and (C) shaking vigorously by hand, method C combined with centrifugation is the best method to evaluate the phase behavior and EIFT of premixed systems and produces mixtures that are the closest to the equilibrium state. For method C, the surfactant concentration in the aqueous layer after equilibration was the lowest due to surfactant partitioning into the oil phase. Moreover, the WOR affects the pre-equilibrated EIFT in brine systems significantly because of the different proportions of surfactant components that partition into the oil phase. For the surfactant at an initial concentration of 0.8 g·mL−1 in the aqueous phase, as the WOR decreases from 2.33 to 0.43, or as the oil volume fraction in the mixture, φ, increases from 0.3 to 0.7, the surfactant concentration in the aqueous layer drops to the range from 5.9 g·mL−1 to 2.2 g·mL−1, and the EIFT increases by a factor of ˜70. In addition, the pre-equilibrated EIFTs are different from the un-pre-equilibrated EIFTs at the same surfactant concentration in the aqueous layer evidently because of preferential partitioning of the various surfactant components. This phenomenon can be accounted for with a simple two-phase extraction model, if the more surface-active component partitions preferentially in the oil. Therefore, the effects of the mixing method and centrifugation, the WOR, and the preferential partitioning of surfactant components into the oil phase should be evaluated for general surfactant screenings for uses in EOR applications.

Optimization of contact angle and interfacial tension measurements for fluid/rock systems at ambient conditions

Quantification of interfacial tension (IFT) and contact angles is essential to characterize reservoir fluid-fluid and rock-fluid interactions. However, these measurements are highly dependent on chemical structure, surface residues, system conditions, flow dynamics and interface interactions. Interfacial interactions are specifically important for secondary and tertiary oil recovery processes where water or brine is injected to recover residual oil through complex multi-phase - rock/brine/oil- interactions Due to the delicate interactions across the interfaces, these systems are subjected to variations and inconsistencies that might be difficult to eliminate, thus, affecting the reliability, reproducibility, and certainty of the data. Therefore, reliable measurements need to eliminate fundamental sources of error and remove surface contaminants. To optimize these measurements, the presented methods take a holistic approach to carefully and reliably optimize the procedure for interfacial tension and contact angle measurements for fluid-fluid and rock-fluid interaction studies at ambient conditions (22.0 ± 2 °C and atmospheric pressure).•The presented method ensures minimization of impurities that alter interfacial tension measurements;•Enhanced preparation for tested surfaces for contact angle measurements, and;•Optimization of procedure at ambient conditions

Potential of a Novel Surfactant Slug in Recovering Additional Oil from Highly Saline Calcite Cores during the EOR Process: Synergistic Blend of Surface Active Ionic Liquid and Nonionic Surfactant

In the present study, a chemical formulation containing a surface-active ionic liquid (SAIL; tributylhexadecylphosphonium bromide) and a nonionic surfactant (TERGITOL 15-S-9) has been prepared. The composition of the mixed micelle and the interaction parameter between the SAIL and nonionic surfactant at varying concentrations were evaluated by Rubingh theory. The most optimal formulation was then screened through phase behavior tests to determine optimal salinity for the crude/brine/chemical formulation system. The optimal salinity for the oil/water/surfactant system was found to be as high as 9.28 wt %. Dynamic light scattering (DLS) studies and small-angle neutron scattering (SANS) experiments have been performed to provide further insight into the size and structure of the micelles formed by the SAIL and nonionic surfactant, respectively. Traditional laboratory-scale oil displacement experiments were performed to study the effectiveness of the optimized chemical formulation in recovering oil during the surfactant-assisted EOR process. Prolate ellipsoidal-shaped mixed micelles, formation of a WINSOR III phase at high salinities, low equilibration time, and prolonged stability of the ternary phase system facilitate high oil solubilization. It was observed that, after the secondary waterflooding process, during the tertiary oil recovery process, individual nonionic surfactant at the same salinity recovered only 7.28% additional oil, whereas the optimized chemical formulation containing both SAIL and nonionic surfactant in an equimolar ratio recovered 16.68% additional oil.

Separation of low polarity petroleum sulfonate: Eluant selection, characterization, and theoretical calculation

ABSTRACTPetroleum sulfonate is one of the most important surfactant in tertiary oil recovery process. Among complex components, low polarity petroleum sulfonate account for about 70% of total, but the main contributing components are still unknown, and the accurate evaluation method is imperative. In this work, low polarity petroleum sulfonate was successfully separated into four parts. All the separated samples were characterized by mass spectrometry, infrared spectroscopy, and nuclear magnetic resonance. The average carbon number, average aromatic carbon number, average saturated carbon number, and the average number of methyl were obtained. The results revealed that average relative molecular mass and branched degree are the main factors of varied polarities of petroleum sulfonate. What more, this study provided a reliable evaluation and characterization method of low polarity petroleum sulfonate.

Experimental investigation of efficiency of MEOR process in a carbonate oil reservoir using Alcaligenes faecalis: Impact of interfacial tension reduction and wettability alteration mechanisms

Microbial Enhanced Oil Recovery (MEOR) is a term which is attributed to the process of utilizing bacterial activity for increasing the recovery factor of oil reservoirs. This process relies on several mechanisms especially interfacial tension reduction and wettability alteration mechanisms. The main purpose of this work is to evaluate the impact of these mechanisms during MEOR process for microorganism isolated from formation water of one of the Iranian southwest carbonate oil reservoirs. The isolated microorganism was identified to be Alcaligenes faecalis. The optimum condition for growth of microorganism was found at 28 °C, pH = 7, carbon to nitrogen ratio of 30 and 3% salinity. Results show that the selected microorganism is able to reduce the interfacial tension between formation brine and crude oil from 28.1 mN/m to 8.4 mN/m and alter the wettability of reservoir rock from approximately 156° to 86° which represents a change from oil-wet condition toward intermediate-wet. Results show that the isolated microorganism is able to produce 8.2% and 5.2% additional oil recovery in respective shut in and quick flooding scenarios. This show that the isolated microorganism is efficient in production of additional oil as a part of tertiary oil recovery process.

Synergism, phase behaviour and characterization of ionic liquid-nonionic surfactant mixture in high salinity environment of oil reservoirs

A large number of matured oil reservoirs still have ample quantity of oil trapped in the pores of the reservoir rock. The quest of a reliable tertiary oil recovery process has opened opportunities for chemical enhanced oil recovery processes. Most of the conventional chemicals used in this method lose their efficacy under high salinity conditions of oil reservoirs. In the present work, synergism in reducing interfacial tension between crude oil and aqueous phase has been investigated, between a mixture of long chain imidazolium ionic liquid and a nonionic surfactant. The reservoir fluid has been modelled as a system containing crude oil/kerosene and surfactant brine. Phase behaviour studies of this system at varying salinities have been studied. Formation of a distinct and stable TYPE III microemulsion at ultra-high salinities has been observed. Presence of middle phase microemulsion at very high salinities indicated ultralow interfacial tensions thereby making the mixed surfactant formulation suitable enough to be used in reservoirs having high salinity of formation brine. Characterization of this middle phase microemulsion was carried out using Transmission Electron Microscopy (TEM), Atomic Force Microscopy (AFM), Polarised optical microscopy (POM) and Dynamic light scattering (DLS) techniques. Time required for the modelled reservoir fluid to coalesce into a stable middle phase microemulsion was characterised using Turbiscan. Subsequently, flooding experiments with only ionic liquid (C16mimBr) and mixed system containing ionic liquid (C16mimBr) + nonionic surfactant (Tergitol 15-S-9) at high salinity conditions were performed. The results showed that during surfactant flooding with C16mimBr alone, the amount of oil recovered was 3.7% of the original oil in place whereas for C16mimBr + nonionic surfactant mixture, percentage of oil recovered was 9.79% of the original oil in place.

Investigating the effect of nano-silica on efficiency of the foam in enhanced oil recovery

Due to the vast production of crude oil and consequent pressure drops through the reservoirs, secondary and tertiary oil recovery processes are highly necessary to recover the trapped oil. Among the different tertiary oil recovery processes, foam injection is one of the most newly proposed methods. In this regard, in the current investigation, foam solution is prepared using formation brine, C19TAB surfactant and air concomitant with nano-silica (SiO2) as foam stabilizer and mobility controller. The measurements revealed that using the surfactant-nano SiO2 foam solution not only leads to formation of stable foam, but also can reduce the interfacial tension mostly considered as an effective parameter for higher oil recovery. Finally, the results demonstrate that there is a good chance of reducing the mobility ratio from 1.12 for formation brine and reservoir oil to 0.845 for foam solution prepared by nanoparticles.

Influence of hydrophobic groups on thickening and emulsification properties of hydrophobically modified polyacrylamides

Hydrophobically modified polyacrylamides can be used to enhance oil recovery in tertiary oil recovery process because they have good thickening and emulsification properties. Hydrophobically modified polyacrylamides with different hydrophobic groups were synthesized using micellar polymerization. Above CAC, elastic polymer gel is formed by the aggregation of hydrophobic groups. Hydrophobicity of hydrophobic groups plays a substantially important role in properties of HMPAMs solutions. Higher hydrophobicity of hydrophobic groups leads to more intensive intermolecular association and thus helps to enhance the apparent viscosity of HMPAMs solutions and form stronger elastic polymer gel network structures in HMPAMs solutions which can enhance the stability of the O/W crude oil emulsions stabilized by HMPAMs.

Application of different novel and newly designed commercial ionic liquids and surfactants for more oil recovery from an Iranian oil field

Abstract This investigation is conducted on one of the southern Iranian oil fields, which experiences a fault on its gas cap. Therefore, no traditional gas injection and normal water injection for pressure maintenance is suggested. The target is set to inject special compatible and proper type of chemicals in each single well to avoid the pressure increase for the risk of oil and gas spill. Two different sources of aqueous phases, namely formation brine and sea water were used to find the effects of different brine composition on the main mechanisms of releasing the trapped oil, interfacial tension (IFT) and wettability alteration. The obtained results reveal that both the ionic liquid (IL) based surfactants and new synthesized commercial surfactants are not only able to tolerate harsh conditions (250,000 ppm) of salinity but also have the ability to reduce the IFT more effectively (from 19 to 0.07 mN m− 1). As the salinity is increased, ionic liquid ([C12mim] [Cl]) showed lower critical micelle concentration (CMC) of about 50 ppm, which shows that the IL use for EOR is economically feasible. The contact angle measurements also indicate the possibility of activating wettability alteration mechanism. Consequently, the core flooding tests revealed more oil recovery efficiency of 8% and 22% based on original oil in place (OOIP) and residual oil in place, respectively for the solely IFT reduction cases. The oil recovery efficiency for the tertiary oil recovery process was increase up to 12% and 35%, based on OOIP and residual oil in place, respectively, which clearly clarifies the effectiveness of soaking to exploit the wettability alteration mechanism.

Polymeric nanospheres as a displacement fluid in enhanced oil recovery

This paper presents the investigation of using nanoscale polyacrylamide-based spheres (nanospheres) as a displacement fluid in enhanced oil recovery (EOR). Coreflood experiments were conducted to evaluate the impact of nanospheres and its concentration dispersed in model formation water on oil recovery during a tertiary oil recovery process. The coreflood results showed that nanospheres can enhance residual oil recovery in the sandstone rock samples and its concentration showed a significant impact into incremental oil. By evaluating the contact angle, it was observed that wettability alteration also might be involved in the possible oil displacement mechanism in this process together with fluid behavior and permeability to water that might divert injected fluid into unswept oil areas and enhance the residual oil recovery. These investigations promote nanospheres aqueous disperse solution as a potential displacement fluid in EOR.