Enhanced oil recovery with nanofluids based on aluminum oxide and 1-dodecyl-3-methylimidazolium chloride ionic liquid

Enhanced oil recovery with nanofluids based on aluminum oxide and 1-dodecyl-3-methylimidazolium chloride ionic liquid Akram Al-Asadi a,b , Alberto Arce c , Eva Rodil a , Ana Soto a, ⇑ a CRETUS. Department of Chemical Engineering, Universidade de Santiago de Compostela, E-15782, Santiago de Compostela, Spain b Chemical and Petrochemical Techniques Eng. Department, Basra Technical Engineering College, Sothern Technical University, Ministry of Higher Education and Scientific Research, Iraq c Campus Industrial de Ferrol, Universidade de A Coruña, E-15403, Ferrol, Spain article info Article history: Received 20 March 2022 Revised 16 June 2022 Accepted 5 July 2022 Available online 8 July 2022 Keywords: Nanoparticles Ionic liquid IFT Adsorption Wettability Flooding abstract Surface-active ionic liquids (SAILs) have multiplied the possibilities of surfactant enhanced oil recovery (EOR) methods. Among their multiple promising features, the possibility of functionalization and their stability at harsh conditions should be highlighted for the application. They have been successfully applied to increase oil recovery by improving crucial parameters such as: formulation stability, reduction of water–oil interfacial tension, and wettability. Recently, nanoparticles have attracted attention for EOR applications due to their capacity to modify the properties of rock surfaces. However, to date no research has been conducted on the combination of SAILs with nanoparticles for EOR. In this work, the combination of the SAIL 1-dodecyl-3-methylimidazolium chloride, [C 12 mim]Cl, with Al 2 O 3 nanoparticles is proposed for EOR. Stable dispersions in brine were achieved, using the polymer polyvinylpyrrolidone (PVP) as a stabilizing agent, and characterized through density and dynamic viscosity measurements. According to stability and interfacial tension studies, a nanofluid consisting of 0.05 wt% [C 12 mim]Cl, 0.05 wt% Al 2 O 3 and 1.0 wt% PVP, in brine (5.0 wt% NaCl) was proposed for EOR in carbonate reservoirs. The presence of nanoparticles reduced the adsorption of the surfactant-polymer formulation on carbonate rocks and changed the aged rock wettability from oil-wet to water-wet. An additional oil recovery of 10.4 %OOIP was achieved with the surfactant-polymer formulation, in comparison with 14.8 %OOIP obtained with the nanofluid. Ó2022 The Author(s). Published by Elsevier B.V. This is an open access article under the CC BY-NC license. (http://creativecommons.org/licenses/by-nc/4.0/). 1. Introduction Worldwide energy consumption keeps growing and, despite the increment of renewable energy sources driven by the global energy transition [1], the demand for oil has not ceased. For this reason, the upstream segment of the oil and gas industry is considering the application of tertiary oil production techniques, aiming to facilitate the extraction of oil left in reservoirs after primary and secondary recovery. Enhanced oil recovery (EOR) techniques seek to reduce oil saturation below that achieved by secondary methods [2]. Capillary forces or high viscosities are responsible for retaining the oil inside the reservoir’s rock pores. Breaking oil-rock interactions or improving sweep efficiency can be achieved by the injection of surfactant formulations. This tertiary EOR method, surfactant or microemulsion flooding, aims to reduce water–oil interfacial tension (IFT) and/or alter the rock wettability from oilwet towards water-wet. Core flooding laboratory tests have proved that surface-active ionic liquids (SAILs) can be of interest for EOR applications. While performing similarly to other surfactants, the additional features of SAILs such as their high thermal stability, and the possibility of tailoring them for target properties or to accommodate any specific reservoir conditions of salinity and temperature, make them attractive chemical agents in EOR [3–5]. Several authors [5–11] have studied the water–oil IFT reduction achieved with SAILs based on imidazolium and pyridinium cations. Among the screened salts, dodecylmethylimidazolium chloride [C 12 mim]Cl emerged as a promising candidate for EOR due to its capacity to reduce the water–oil IFT, highlighting that this effect is more pronounced in the presence of brine [6–11]. In addition, the alteration of the wettability of carbonate rocks with this SAIL has also been proposed as mechanism to improve oil recovery [9–11]. Recently particular attention has been given to the use of nanomaterials in chemical EOR, so different kinds of nanofluids are being proposed as optimized formulations for practical application [12–15]. One of the main mechanisms behind nano-EOR is wettability alteration. The hypothesis of structural disjoining pressure is https://doi.org/10.1016/j.molliq.2022.119798 0167-7322/Ó2022 The Author(s). Published by Elsevier B.V. This is an open access article under the CC BY-NC license. (http://creativecommons.org/licenses/by-nc/4.0/). ⇑ Corresponding author. E-mail address: [email protected] (A. Soto). Journal of Molecular Liquids 363 (2022) 119798 Contents lists available at ScienceDirect Journal of Molecular Liquids journal homepage: www.elsevier.com/locate/molliq gaining acceptance as an explanation for this rock surface modification. According to this notion, the nanoparticles are forced to rearrange near the rock surface, forming a layer that exerts a pressure capable of detaching the oil from the rock [12]. In some cases, a limited reduction of water–oil IFT has been also found with the use of nanoparticles. The increase of the viscosity of the aqueous formulation, reduction of oil viscosity, and blocking of pores were also highlighted as possible mechanisms associated to this EOR method [12–15]. In order to improve the possibilities of tertiary oil recovery methods, the synergy of formulations containing surfactants and nanoparticles is being exploited [16–19]. The combination of SAILs and these nanomaterials multiplies the possibilities of the method, thus becoming a research niche area with promising expectations. However, the stability of formulations with nanoparticles is usually a bottleneck in the application, and the addition of a stabilizer is usually required. The hydrophilic polymer polyvinylpyrrolidone (PVP), has been successfully applied to that aim [20,21]. This work proposes a novel combination, SAILs and nanoparticles, for EOR. Different formulations containing: [C 12 min]Cl, due to its high capacity to reduce the water–oil IFT, Al 2 O 3 nanoparticles, due to their abundance and abrasiveness, and PVP, as a stabilizing agent and viscosity enhancer, are prepared in water at different NaCl concentrations. Stable nanofluids are characterized in terms of density and dynamic viscosity. Water-oil IFT reduction is the target parameter to define the optimal formulation. Wettability and adsorption studies are carried out in carbonate rocks. The performance of the optimal formulation to recover residual oil is finally determined by core-flooding tests in carbonate rocks at room temperature. Comparative tests are performed with the corresponding surfactant-polymer (without nanoparticles) method, to assess the efficacy of the use of nanoparticles in the formulation. 2. Materials and methods 2.1. Materials The SAIL 1-dodecyl-3-methylimidazolium chloride [C 12 mim]Cl (CAS 114569–84-5) was synthesized in a single step reaction as described elsewhere [22]. 1-Methylimidazole was directly alkylated with 1-chlorododecane at 343 K under inert atmosphere for 72 h. The product was dissolved in acetonitrile and washed with ethyl acetate to eliminate unreacted starting materials. A rotary evaporator was used to remove this organic phase, and the process was completed by heating the mixture (343 K) while stirring under high vacuum (<0.1 mbar) during 48 h. The purity was checked by 1 H and 13 C NMR analysis and the corresponding spectra have been added to Supporting Information (Figure S1). Polyvinylpyrrolidone (PVP) with an average molecular weight of 40,000 g/mol was purchased from Sigma-Aldrich. Aluminum oxide nanopowder (Al 2 O 3 , CAS 1344–28-1) was purchased from Sigma-Aldrich. The supplier‘s data can be summarized as follows: gamma phase alumina powder, particle size <50 nm, surface area > 40 m 2 /g (BET), relative density 4,000 g/cm 3 , melting point 2,040 °C, and molecular weight 101.96 g/mol. The nanomaterial was structurally and morphologically characterized by X-ray diffraction (XRD) and transmission electron microscopy (TEM). The diffraction patterns were obtained using an X-ray Philips powder diffractometer (PW 1710) with a Cu-k a X-ray source (k= 1.5 4 Å) and TEM images were obtained using a Philips CM-12 microscope (FEI Company, Eidhoven, the Netherlands) with a MegaView docu-II camera and IMAX image analysis Software SIS NT. Figure S2 (a) from SI shows the TEM images taken in a 100 nm scale. Nearly all the particles exhibited irregular shape with size distribution between 20 and 50 nm. Figure S2(b) shows the X-ray diffractograms of nano aluminium oxide that correspond to the standard card JCPD (Joint Committee on Powder Diffraction Standards) number 29–0063 [23], indicating the presence of Alumina gamma (derived from boehmite) ( c -Al 2 O 3 ) with tetragonal crystal characteristics. Synthetic brines were prepared by mixing different amounts of sodium chloride (NaCl) with distillate water (0.5, 1.5 and 5.0 wt%). NaCl was purchased from Sigma-Aldrich with ACS reagent purity (99.0%). Crude oil, kindly supplied by the Repsol refinery plant of A Coruña (Spain), was used in the experiments. Composition is shown in Table 1. Its viscosity is 4.861 cP at 293.15 K and its density is 42.9 °API at 288.15 K (information provided by supplier). Carbonate rock samples were purchased from Kocurek Industries (Houston). The bulk mineral composition of the rocks was measured using X-ray powder diffraction by means of a Bruker D8 Advance (40 kV, 40 mA, theta / theta), equipped with a Cu Xray sealed tube (CuK a 1, k= 1.5406 Å), with a LYNXEYE XE-T type detector. Rock composition was 89% calcite, 2% sodium calcium pentafluoroaluminate fluoride-beta, and 9% diopside. Pore size distribution was determined using X-Ray microtomography. A microCT Skyscan system model 1172 (Bruker, Belgium) 1172, with a Xray tube of 10 W maximum power and a tungsten anode, was operated at 100 kV with target current of 100 l A. For data acquisition, an aluminium-cooper filter was used and the effective pixel size of the detector was fixed to 13.79 l m. The microtomographed images were reconstructed by NRecon. The segmentation, data analysis and pore size distribution of the samples were obtained by CTAn software. Results are shown in Fig. 1. 2.2. Methods 2.2.1. Formulations preparation and characterization In this work, different formulations containing SAIL, Al 2 O 3, PVP and NaCl were prepared by weight using a Mettler Toledo XPE205 analytical balance. To that aim, stock solutions of [C 12 mim]Cl (4.0 wt%), PVP (4.0 wt%), and NaCl (10.0 wt%) were prepared in distilled water. Nanofluids formulated in water were made by dispersing a predetermined quantity of nanoparticles in distilled water. The mixture was vortex mixed to form a stable and homogeneous dispersion. Then the required amount of surfactant stock solution was added to achieve the desired concentration. In the case of nanofluids formulated in brine, after this process, required quantities of stock solutions of PVP and NaCl were subsequently added to achieve the desired composition of the formulation. After preparation, formulations were gently stirred for 10 min with a magnetic stirrer and ultrasonicated for 5 min with an ultrasonic probe (Bandelin Sonopuls). The main drawback in the application of nanoparticles in EOR is the stability of the formulation. Nanoparticles dispersed in solution must be maintained at nanometer size to avoid their aggregation, which could cause excessive plugging of the rock pores and minimization of the recovery factor [24–27]. Direct visualization and zeta potential techniques were used to study the stability of the prepared nanofluids. Nanofluids were prepared in closed transparent vials and monitored for seven days at room temperature. They were considered stable if no precipitation was observed after that Table 1 Crude oil composition. Component wt% Saturates Aromatics Resins Asphaltenes 43.5 41.7 11.6 3.2 A. Al-Asadi, A. Arce, E. Rodil et al. Journal of Molecular Liquids 363 (2022) 119798 2 time. The zeta potential of samples was measured at 298.15 K by Dynamic Laser Scattering (DLS) using a Zetasizer Nano ZS (Malvern). Aqueous formulations were characterized by measuring their density and viscosity at 298.15 K and atmospheric pressure. The equipment used was an Anton Paar DMA 5000 M oscillating Utube density meter with an Anton Paar LOVIS 2000 ME microviscometer module, based on the rolling ball principle, attached. Density and viscosity uncertainties, determined as standard and relative standard uncertainties respectively, were estimated to be 310 -5 g/cm 3 and 1.5%. At least two measurements were performed, ensuring that they were repetitive within the nominal uncertainty, and the average value was recorded. The Newtonian character of the nanofluids was previously confirmed using an Anton Paar MCR102 rheometer. 2.2.2. Dynamic interfacial tension The dynamic IFT between crude oil and aqueous formulations was measured using a spinning drop tensiometer (Krüss SITE100). All the experiments were carried out at 298.15 K (a Julabo thermostatic bath was used to maintain the temperature) and atmospheric pressure. To ensure that no dissolved air was present in the aqueous formulations, they were sonicated prior to measurements with a Branson 5200 sonication bath for 2 h. A drop of 4 l L of crude oil was injected, with a Hamilton Bonaduz Schweiz microliterTM #701 syringe, in the middle of the capillary tube filled with the aqueous phase rotating at a low speed (60 rpm). Then, to obtain a drop length at least 4 times larger than its diameter, rotating velocities between 5000 and 6000 rpm were applied. The IFT was calculated according to the Vonnegut equation: IFT ¼ Dq  x 2 D 3 =32 ð1Þ where D q is the density difference between the dense and light phases, x is the angular velocity and D is the diameter of the oil drop. Equilibrium dynamic interfacial tension uncertainty, determined as relative standard uncertainty, was estimated to be 10%. At least two measurements were performed, ensuring that they were repetitive within the nominal uncertainty, and the average value was recorded. 2.2.3. Adsorption Batch adsorption experiments of the surfactant and polymer used in the formulations, individually and jointly, were carried out according to previous literature works [28–32]. To this end, carbonate rock was crushed into small parts by a jaw crushed and then sieved to obtain a particle size ranging from 100 to 500 l m. 5 mL of the selected aqueous formulation (surfactant, surfactant + PVP, or nanofluid) and 1 g of crushed rock were introduced into various vials. The vials were shaken in a Selecta Boxcult orbital shaker at 298.15 K and samples were taken at different times, from each vial, up to 72 h. The collected samples were centrifuged at 10,000 rpm for 5 min with an OrtoAlresa Digicen 21R centrifuge to separate the solid phase. UV–visible absorption measurements were carried out, to determine the concentration of the chemicals in the formulation before and after the adsorption process, using an Agilent 8543 UV–visible absorption spectrophotometer. Both surfactant and PVP absorbed at a wavelength of 208 nm, so calibration curves (see Figure S3) were prepared separately for both chemicals and then for the mixture. Brine solution (5.0 wt% NaCl) was used as blank. Given the concentrations, the adsorption density (mg Surfactant /g crushed rock in the case of the surfactant formulation, mg PVP /g crushed rock in the case of the polymer formulation, and mg Surfactant+PVP /g crushed rock for surfactant-polymer and nanofluid formulations) was calculated using the following equation: Adsorption ðmg=gÞ¼ C 0 CðÞ V mð2Þ where C 0 is the initial chemical (surfactant, PVP, or surfactant + PVP) concentration (mg/mL), Cis the chemical concentration at a certain time (mg/mL), Vis the total volume of solution (mL), and mis the mass of crushed rock (g). 2.2.4. Contact angle The performance of the aqueous formulations (surfactant, surfactant-PVP, and nanofluid) regarding the wettability alteration of the carbonate rock was evaluated by the measurement of the crude oil contact angle on the rock surface. The static sessiledrop technique [21,33–35] was applied. To that aim, a homemade glass cell with a holder to fix the rock sample was used. A crude oil droplet (6 l L) was injected below the carbonate disc submerged in brine, and the images of the drop were recorded by a camera. The contact angles were determined using ImageJ software. The rock samples were cut into small pieces (3.8 cm in diameter and 0.4 cm thick) with a trimming machine, polished to achieve a smooth surface, and finally oven dried for 24 h. Once prepared, the rock discs were saturated in a brine solution (5.0 wt% NaCl) for 24 h and then submerged in crude oil for a period of 10 days. Excess oil was removed from the discs and initial contact angles in brine were measured. Afterwards, different aged rock discs were immersed in surfactant, surfactant-PVP, and nanofluid formulations. The discs were withdrawn and immersed in brine to measure contact angles at different times up to 96 h. To analyze the effect of the temperature on the ageing process, the study was carFig. 1. (a) Micro-CT Skyscan image and (b) Pore size distribution of carbonate rock samples. A. Al-Asadi, A. Arce, E. Rodil et al. Journal of Molecular Liquids 363 (2022) 119798 3 ried out at room temperature and at 348.15 K. All measurements were repeated at least three times to ensure repeatability. 2.2.5. Core flooding The experimental setup for the core flooding tests performed in this study is shown in Fig. 2. It consists of a core holder (Hassler core holder H00-021–0) where a rock sample (carbonate) was introduced into a rubber sleeve, which is pressurized by a hydraulic oil at least 35 bar higher than the flooding pressure. This confining pressure was applied by a manual hydraulic pump (Enerpac P142), its purpose being to prevent hydraulic side flow. Two piston pumps equipped with pressure sensors (floXlab BTSP 500–5, Vince Technologies) were used to inject oil and aqueous formulations. Graduated tubes were used to collect the effluents. All the experiments were carried out at room temperature. The experimental procedure was based on previous literature [4,5,36,37]. First, a dry rock core sample was weighed and measured, then introduced into the core holder and vacuumed for 24 h to remove any air remaining within the pores, thus avoiding pore blocking. The rock was saturated with brine (5.0 wt% NaCl) at a constant injection rate of 2 mL/min. After 24 h, the wet core was removed from the holder, weighed again to calculate the pore volume as the difference between the dry and wet weights. The core was then reintroduced and confined within the holder to carry out a permeability test. The absolute permeability of the rock was calculated using Darcy’s law by recording the pressure difference between the core inlet and outlet at different flow rates of brine injections. As the core sample was saturated with brine after the permeability test, crude oil was then injected until no more brine came out. The Original Oil in Place (OOIP) was calculated as the volume of crude oil retained in the core. The initial oil saturation (S oi ) and the initial water saturation (S wi ) were calculated as the percentage of the pore volume (PV) occupied by brine and crude oil, respectively. Once the rock was saturated with oil, it was aged for seven days at room temperature. Following that, it was flushed with synthetic brine (5.0 wt% NaCl) at a constant injection rate of 2 mL/min until no oil was produced. Oil recovery after water flooding (ORWF) was determined and residual oil saturation (S or ) was calculated as a function of the OOIP, ORWF and PV. Next, the core was ready for EOR (Chemical flooding), so it was flooded with the optimized formulation (surfactant + PVP or nanofluid) at a constant flow rate of 2 mL/min (for practical reasons, a rate higher than the usual in real applications was used) until oil was no longer produced in the effluent. Injected Pore Volumes (PV) of the different chemical slugs were the required until no more oil was extracted. The oil recovery after tertiary flooding (ORTF) was determined. Finally, the AOR was calculated as a function of the OOIP. 3. Results and discussion 3.1. Formulations stability and characterization 3.1.1. Stability Aqueous formulations with [C 12 mim]Cl compositions ranging from 0.01 to 1.0 wt% were prepared with different Al 2 O 3 concentrations. In order to ensure the stability of the samples, those showing precipitation in the monitoring period (7 days) were discarded. Maximum nanoparticle concentration leading to stable dispersions is presented in Table 2. As expected, the concentration of SAIL drastically affected the possible concentration of nanoparticles. A high concentration of nanoparticles (3.0 wt%) was achieved at the lowest concentration of the surfactant (0.01 wt%), however, the increase of the SAIL concentration meant a significant increase in instability. In the case of the highest SAIL concentration (1.0 wt %), only a concentration of 0.01 wt% of nanoparticles allowed a stable dispersion for a week. As previously reported [38,39], the alumina nanofluids with no added surfactant show better dispersion than those with surfactants. This is because alumina in polar liquids is able to develop a significant surface charge that enhances dispersion stability via electrostatic repulsion. When these nanoparticles are combined with the cationic SAIL [C 12 mim]Cl, the head group of the surfactant experiences a natural repulsion to the positively charged alumina surface, generating aggregation of the nanoparticles and destabilizing the nanofluid. Zeta potential measurements were carried out for the visually stable dispersions in water shown in Table 2. Values were, in all cases, greater than + 30 ± 5 mV, with no significant decrease in zeta potential values observed over 7 days. It has been previously reported that nanofluids with zeta potential values greater than + 30 mV or less than 30 mV show a high stability [38–41], thus confirming the stability of the prepared formulations. Fig. 2. Schematic core flooding experimental set-up. A. Al-Asadi, A. Arce, E. Rodil et al. Journal of Molecular Liquids 363 (2022) 119798 4 The maximum concentration of nanoparticles in SAIL formulations with NaCl was also studied. It is well known that small amounts of salt, even trace amounts, can break the stability of nanoparticles [42,43]. The presence of a stabilizing agent (1.0 wt % of PVP) was required to achieve stable formulations. Table 2 shows the maximum concentration of nanoparticles leading to stable dispersions in aqueous formulations containing [C 12 mim] Cl (concentrations ranging from 0.01 to 1.0 wt%) and NaCl (concentrations ranging from 0.5 to 5.0 wt%) and PVP (1.0 wt%). Fixing the concentration of surfactant, an increase of NaCl concentration reduces the wt% of nanoparticles that can be dispersed. However, at a fixed concentration of NaCl, the increase of the surfactant concentration allowed a higher nanoparticle concentration, except in the case of 5.0 wt% NaCl, in which the surfactant concentration did not affect the stability of the nano-dispersion. The maximum concentration of nanoparticles in brine solutions (0.15 wt%) was achieved at the highest concentration of SAIL (1.0 %wt) and the lowest concentration of NaCl (0.5 wt%). Zeta potential measurements were also carried out for these formulations, obtaining values of 1 ± 0.5 mV in all cases. These values are obtained because this method only accounts for electrostatic repulsive interactions and not for the steric hindrance effect of the coating assembly [40]. 3.1.2. Characterization Several nanofluids were prepared in water and brine with [C 12 mim]Cl compositions ranging from 0.01 to 1.0 wt% and different Al 2 O 3 concentrations up to maximum values indicated in Table 2. The characterization of these nanofluids was carried out through the measurement of their densities and viscosities at 298.15 K and atmospheric pressure. The results obtained are shown in Table 3. As shown, in the concentration range studied, density slightly increases as the concentration of nanoparticles increases. However, no variation is appreciated with the increase of the surfactant concentration. As expected, viscosity (Table 3 and Fig. 3) increases significantly with increases of nanoparticle concentration and to a lesser extent with increases in surfactant concentration. The presence of PVP (1.0 wt%) in brine formulations led to a further increase of viscosity. In fact, the addition of this polymer not only allows the stabilization of the nanoparticles, but also the combination of methods for EOR: reduction of the IFT with a surfactant and increase of the viscosity with a polymer. Increasing the viscosity of the displacement fluid avoids adverse mobility ratios and improves displacement efficiency. Combining PVP, nanoparticles and surfactant, viscosity values up to 1.60 mPas were achieved. 3.2. Dynamic interfacial tension The ability of the SAIL [C 12 mim]Cl to reduce water–oil IFT is well established in the literature [6–11]. However, the combination of this SAIL with nanoparticles for EOR has not been previously proposed. Aiming to analyze the effect of Al 2 O 3 nanoparticles in the IFT between aqueous formulations containing this surfactant and crude oil, several nanofluids containing different concentrations of [C 12 mim]Cl (0.05, 0.10, 0.50 and 1.00 wt%) and Al 2 O 3 nanoparticles (from 0 to 0.05 wt%) were prepared in distilled water and the water–oil IFT was measured at 298.15 K and atmospheric pressure. Figure S4 (SI) presents all the dynamic IFT tests and equilibrium values are shown in Fig. 4. As previously reported [6–11], IFT Table 2 Maximum concentration of nanoparticles leading to stable nanofluids as a function of [C 12 mim]Cl and NaCl concentrations. [C 12 mim]Cl (wt%) Al 2 O 3 (wt%) 0 wt% NaCl 0.5 wt% NaCl*1.5 wt% NaCl*5.0 wt% NaCl* 0.01 3.00 0.10 0.075 0.05 0.05 0.50 0.10 0.10 0.05 0.10 0.05 0.10 0.10 0.05 0.50 0.02 0.10 0.10 0.05 1.00 0.01 0.15 0.125 0.05 * 1.0 wt% PVP was used as stabilizing agent. Table 3 Density and viscosity of nanofluids at 298.15 K and atmospheric pressure. Nanofluids formulated in water Nanofluids formulated in brine [C 12 mim]Cl (wt%) Al 2 O 3 (wt%) q (kg/m 3 ) g (mPas) [C 12 mim]Cl (wt %) Al 2 O 3 (wt%) PVP (wt%) NaCl (wt%) q (kg/m 3 ) g (mPas) 0.011 0.000 997.4 0.88 0.010 0.000 1.000 5.002 1035.1 1.19 0.010 0.010 997.5 0.94 0.011 0.010 0.998 4.999 1035.2 1.40 0.011 0.027 997.6 1.00 0.011 0.025 0.999 4.997 1035.4 1.50 0.010 0.040 997.6 1.08 0.011 0.040 0.998 4.989 1035.4 1.54 0.011 0.050 997.8 1.13 0.010 0.050 1.001 4.999 1035.5 1.57 0.010 0.100 998.1 1.14 – – – – – – 0.011 1.001 1004.5 2.84 – – – – – – 0.051 0.000 997.4 0.88 0.051 0.000 1.000 4.997 1034.9 1.19 0.050 0.011 997.4 0.96 0.052 0.011 0.998 4.945 1035.0 1.43 0.053 0.025 997.6 1.05 0.051 0.025 1.000 4.998 1035.2 1.52 0.051 0.040 997.6 1.09 0.051 0.038 0.995 5.005 1035.3 1.55 0.051 0.051 997.8 1.13 0.051 0.051 1.000 4.998 1035.4 1.58 0.101 0.000 997.4 0.88 0.100 0.000 1.000 4.999 1035.0 1.19 0.100 0.010 997.5 0.99 0.103 0.010 1.005 5.003 1035.1 145 0.102 0.025 997.6 1.09 0.100 0.025 1.000 5.000 1035.4 1.54 0.100 0.040 997.7 1.12 0.104 0.038 1.003 5.004 1035.4 1.56 0.102 0.052 997.8 1.14 0.101 0.050 1.000 4.998 1035.5 1.60 0.500 0.000 997.3 0.90 0.500 0.000 1.001 4.997 1035.0 1.21 0.500 0.011 997.4 1.03 0.499 0.010 1.000 5.021 1035.0 1.51 0.500 0.020 997.5 1.07 0.500 0.025 1.000 4.999 1035.1 1.56 – – – – 0.498 0.039 0.994 5.030 1035.2 1.57 – – – – 0.500 0.050 1.000 4.993 1035.2 1.60 1.000 0.000 997.2 0.96 1.000 0.000 1.000 5.001 1034.9 1.25 0.999 0.005 997.3 1.08 1.009 0.010 1.009 5.010 1034.9 1.53 1.000 0.010 997.3 1.09 1.000 0.025 1.001 5.000 1035.0 1.58 – – – – 1.008 0.040 1.008 5.009 1035.1 1.59 – – – – 0.999 0.050 1.000 4.997 1035.1 1.60 A. Al-Asadi, A. Arce, E. Rodil et al. Journal of Molecular Liquids 363 (2022) 119798 5 significantly decreases with surfactant concentration. In the case of the specific crude oil used in this work (crude oil components, especially resins and asphaltenes have significant influence on the IFT [44]) and in absence of nanoparticles, achieved equilibrium values were 7.14, 5.40, 1.62, and 1.24 mNm 1 for SAIL concentrations of 0.05, 0.10, 0.50 and 1.00 wt%, respectively. The addition of a low quantity of nanoparticles also helps the reduction of the IFT, this phenomenon being more noticeable at low surfactant concentrations. Further increases of the nanomaterial did not result in appreciable changes. This effect has previously been reported for the combination of traditional surfactants with nanoparticles [25–27,45–47]. It has been previously reported that [C 12 mim]Cl is able to tolerate harsh salinity conditions [9]. As SAILs have demonstrated good performance at high salt concentrations, water salinity was set to 5.0 wt% NaCl to approach the seawater salinity (5 wt% TDS), and the effect of SAIL and nanoparticle concentration on brine-oil IFT was studied. It is worth mentioning here that in the case of solutions with nanoparticles, a concentration of 1.0 wt% PVP was used to stabilize the formulations. Figure S5 (SI) presents all the dynamic IFT tests and equilibrium values are shown in Fig. 5.As in the case of the measurements with water, the influence of SAIL concentration is significant, in this case the presence of nanoparticles having little influence on the reduction of the IFT. Achieved equilibrium values were 3.8, 1.4, 1.0, 0.8 and 0.6 mNm 1 for SAIL concentrations of 0.01, 0.05, 0.10, 0.50, and 1.00 wt%, respectively, in absence of nanoparticles. Values clearly lower than those previously obtained without NaCl. As previously demonstrated [6–11], the presence of salt helps the reduction of the IFT. The greatest reduction of the IFT was found increasing SAIL concentration up to 0.05 wt%, further increase led to less significant reductions that could likely not be justified due to the cost of the chemical. The addition of a low quantity of nanoparticles only had effect at the lowest SAIL concentration (0.01 wt%). Focusing on a seawater environment, an aqueous formulation with 0.05 wt% [C 12 mim]Cl (according to IFT results), 0.05 wt% Al 2 O 3 and 1.0 wt% PVP (according to stability results), and 5.0 wt % NaCl, was defined as optimal for EOR studies. The average particle size in the nanofluid obtained by the DLS method is 164.9 nm (Fig. 6). 3.3. Adsorption One of the important parameters to evaluate before applying a formulation to EOR is adsorption on the rock surface. So, the adsorption of the proposed formulation (0.05 wt% [C 12 mim]Cl, 0.05 wt% Al 2 O 3 , 1.0 wt% PVP and 5.0 wt% NaCl) in carbonate rocks was analyzed. Firstly, the adsorption of an aqueous solution with 0.05 wt% SAIL was studied. Results are shown in Fig. 7. In approximately 5 h, an equilibrium adsorption value of 0.65 mg/g was achieved. This low value is justified due to the low concentration of the surfactant used, and the repulsive interactions between the positive charge of the cationic SAIL and carbonate rocks (due to the presence of calcite and other minerals [48–50]). Secondly, the adsorption of an aqueous solution with 1.0 wt% PVP was studied. As shown in Fig. 7, a higher adsorption of this chemical was found, namely 2.64 mg/g, and 25 h were required to achieve equilibrium. This is due to the higher proportion of polymer than surfactant in the formulation, and the presence of a carbonyl group Fig. 3. Viscosity at 298.15 K and atmospheric pressure of stable nanofluids (see Table 3). (a) Formulations in water (b) Formulations in brine. The lines are only drawn to facilitate visualization. Fig. 4. Effect of [C 12 mim]Cl and Al 2 O 3 nanoparticles on equilibrated IFT between water and crude oil at 298.15 K and atmospheric pressure. The lines are only drawn to facilitate visualization. Fig. 5. Effect of [C 12 mim]Cl and Al 2 O 3 nanoparticles on the equilibrated IFT between brine (5.0 wt% NaCl, 1.0 wt% PVP) and crude oil at 298.15 K and atmospheric pressure. The lines are only drawn to facilitate visualization. A. Al-Asadi, A. Arce, E. Rodil et al. Journal of Molecular Liquids 363 (2022) 119798 6 that may interact with the positively charged surface of the rock. Third, the adsorption of the surfactant-PVP formulation was studied and the results (Fig. 7) showed a similar trend to that observed for the polymeric solution, increasing very slightly (2.74 mg/g) due to the presence of the SAIL. It has been previously reported that nanoparticles are capable of reducing surfactant or polymer adsorption on the rock surface [12,14,45,51], so finally, the adsorption behavior of surfactant and polymer of the optimal formulation was studied and an equilibrium value of 2.51 mg/g was found. As in the case of the studies mentioned above, the presence of nanoparticles slightly reduced the adsorption of the surfactantpolymer formulation. However, since the adsorption of the formulation is low, it is undoubtedly suitable for application in EOR on carbonate rocks. 3.4. Wettability The wettability of the reservoir rock has a crucial influence on oil recovery due to its impact on the displacement efficiency in the porous medium [9,46,52]. One of the most promising features of nanoparticles is likely their ability to change rock wettability towards water-wet [21,27,40,52–54]. Wettability studies were carried out with surfactant (0.05 wt% [C 12 mim]Cl, 5.0 wt% NaCl), surfactant-polymer (0.05 wt% [C 12 mim]Cl, 1.0 wt% PVP, 5.0 wt% NaCl), and nanofluid (0.05 wt% [C 12 mim]Cl, 0.05 wt% Al 2 O 3 , 1.0 wt% PVP) formulations. Fig. 8 shows the initial oil contact angle on carbonate rock surface (38.3°) and contact angles after treating the rock pieces with the different formulations for 3 days at room conditions. As shown, the contact angle was reduced to 33.3, 29.3 and 25.6°when treatment was carried with surfactant, surfactantpolymer and nanofluid, respectively. Wettability of the rock was classified as water-wet for contact angles from 0°to 75° intermediate-wet from 75°to 105°, and oil -wet from 105°to 180°[55]. So, rocks were water-wet in all cases, improving the property in presence of nanoparticles. Wettability measurements were repeated by ageing the polished rock discs in crude oil at 348.15 K as previously explained Fig. 6. Particle size distribution in the nanofluid. Fig. 7. Adsorption with time of different brine (5.0 wt% NaCl) formulations in carbonate rocks: surfactant (0.05 wt%); polymer (1.0 wt%); surfactant-polymer (0.05 wt% [C 12 mim]Cl, 1.0 wt% PVP); and nanofluid (0.05 wt% [C 12 mim]Cl, 0.05 wt% Al 2 O 3 , 1.0 wt% PVP). Fig. 8. Initial oil contact angle on carbonate rock surface, and contact angles after treating the rock pieces with the different formulations during 3 days at room conditions. A. Al-Asadi, A. Arce, E. Rodil et al. Journal of Molecular Liquids 363 (2022) 119798 7 in section 2.2.4. In this case, as shown in Fig. 9, the original contact angle was 143.5°, so the wettability of the rock was successfully changed to oil–water. Contact angles after treating the rock pieces with the different formulations during 3 days at 348.15 K were 109.1, 105 and 40.9°when treatment was carried with surfactant, surfactant-polymer and nanofluid, respectively. Whereas the two first formulations were not able to change the wettability of the rock surface, oil-wet, the nanofluid was able to change it to water-wet. To ensure that longer treatment periods of the rocks with the formulations did not alter results shown in Fig. 9, the variation of the different contact angles with time was presented in Fig. 10. As shown, contact angles initially decreased sharply within the first 24 h of exposure time, and the variation rate then later decreased. After 3 days (72 h) of contact time, no changes were observed in contact angles. 3.5. Core flooding In order to check the performance of the proposed formulation (0.05 wt% [C 12 mim]Cl, 0.05 wt% Al 2 O 3 , 1.0 wt% PVP and 5.0 wt% NaCl) for EOR purposes, a core flooding test was carried out at Fig. 9. Initial oil contact angle on aged carbonate rock surface, and contact angles after treating the rock pieces with the different formulations during 3 days at 343.15 K. Fig. 10. Evolution with time of oil contact angles on aged carbonate rock surfaces after treating the rock pieces with the different formulations at 343.15 K. Table 4 Summary of core flooding experiments. Injected Fluid Test 1 Surfactant + PVP Test 2 Nanofluid Characterization Pore volume, PV (mL) 9.54 12.54 Porosity of the core (%) 11.12 14.57 Permeability (mD) 19.49 13.97 Original oil in Place, OOIP (mL) 4.8 7.35 Initial oil saturation, S oi (%) 50.33 59.42 Initial water saturation, S wi (%) 49.67 40.58 Water flooding Oil recovered after water flood, ORWF (function of %OOIP) 62.50 76.28 Residual oil saturation, S or (%) 18.87 14.09 Chemical flooding Chemical slug injected 4.1 PV of 0.05 wt% IL + 1.0 wt% PVP 3.4 PV of 0.05 wt% IL + 1.0 wt% PVP + 0.05 wt% NP Additional Oil Recovered, AOR (function of %OOIP) 10.4 14.8 A. Al-Asadi, A. Arce, E. Rodil et al. Journal of Molecular Liquids 363 (2022) 119798 8 room temperature in carbonate cores. For comparative purposes, another test was carried out with the same formulation but without nanoparticles. Results are summarized in Table 4. After secondary flooding with brine, the injection of 4.1 PV of the surfactant-polymer formulation yielded an additional oil recovery (AOR) of 10.4 %OOIP. In the case of the nanofluid, 3.4 PV of injection allowed an AOR of 14.8 % OOIP. The nanofluid formulation led to the highest oil recovery. According to the studies presented in this work, it can be confirmed that IFT reduction and viscosity increase are mechanisms involved in EOR with the proposed nanofluid. According to literature studies [12–15,53], blocking of pores and a weakened mobility of the polymer molecules due to the presence of the nanoparticles could explain the high recovery attained. Moreover, due to limitations in the experimental configuration of the core flooding equipment, tests were carried out at water-wet rock conditions. So, in the case of real reservoirs with oil-wet rocks, the change of wettability mechanism would also help to recover oil. 4. Conclusions In this work, the use of Al 2 O 3 nanoparticles to improve the already promising properties of the SAIL [C 12 mim]Cl for EOR was assessed. To that aim, several nanofluids containing both components in water or brine were prepared. Stability was found to be a critical issue, especially in the case of formulations containing NaCl where the use of 1 wt% PVP was required to achieve dispersions that were stable for at least one week. Due to the relevance of density and viscosity for any application of these nanofluids, these properties were measured for stable solutions at 298.15 K and atmospheric pressure. It was found that nanoparticles slightly and significantly increase the density and viscosity, respectively, of the aqueous formulations. The use of PVP as stabilizing agent led to a further increase of viscosity of high interest for EOR applications. Dynamic IFT between aqueous formulations and crude oil was determined. Findings from previous studies on the ability of the SAIL to reduce IFT were confirmed. Measurements with brine (5.0 wt% NaCl) solutions showed that the use of 0.05 wt% SAIL significantly reduced IFT, the effect of higher concentrations being limited. At this SAIL concentration, nanoparticles did not affect IFT. According to stability and IFT studies, a nanofluid consisting of 0.05 wt% [C 12 mim]Cl, 0.05 wt% Al 2 O 3 and 1.0 wt% PVP, in brine (5.0 wt% NaCl), was proposed for EOR in carbonate reservoirs. The presence of nanoparticles reduced the adsorption of the surfactant-polymer formulation on carbonate rocks. The adsorption value obtained (2.5 mg/g) was low and promising for practical applications. Moreover, the nanofluid formulation was able to change the aged rock wettability from oil-wet to water-wet. Core flooding tests indicate that, from the point of view of performance, the addition of nanoparticles to the formulation is worthwhile. An AOR of 10.4 %OOIP achieved with the surfactantpolymer formulation was increased to 14.8 obtained with the nanofluid. This work shows the interest of the proposed formulation for EOR. Future work involves an improvement of the method to approach field-scale applications. Essays with lower injection flow rates, and the optimization of the quantity of chemical to be used using a postflux with brine would be the required next stages. Author contributions A. Al-Asadi: experimental, original draft preparation. A. Arce: flooding tests experimental, editing; E. Rodil: experimental supervision, formal analysis, editing; A. Soto: conceptualization, supervision, writing, funding. All authors have read and agreed to the published version of the manuscript. Funding Ministry of Science and Innovation and State Research Agency (AEI, https://doi.org/10.13039/501100011033) throughout project PGC2018-097342-B-I00, including European Regional Development Fund. Declaration of Competing Interest The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper. Acknowledgements A. Al-Asadi acknowledges Sothern Technical University for financial support. We would also like to thank Repsol (A Coruña) for providing us with the crude oil used for the experiments. Appendix A. Supplementary data Supplementary data to this article can be found online at https://doi.org/10.1016/j.molliq.2022.119798. References [1] Energy Information Administration, Outlook 0484 (July) (2019) 70. doi: https://www.eia.gov/outlooks/ieo/pdf/ieo2019.pdf. [2] S. Thomas, Oil & Gas Science and Technology – Rev, IFP 63 (1) (2008) 9–19, https://doi.org/10.2516/ogst:2007060. [3] A. Bera, H. Belhaj, Ionic liquids as alternatives of surfactants in enhanced oil recovery—A state-of-the-art review, J. Mol. Liq. 224 (2016) 177–188, https:// doi.org/10.1016/j.molliq.2016.09.105. [4] M. Bin Dahbag, A. AlQuraishi, M. Benzagouta, Efficiency of ionic liquids for chemical enhanced oil recovery, J. Petrol. Explor. Prod. Technol. 5 (2015) 353– 361, https://doi.org/10.1007/s13202-014-0147-5. [5] A. Somoza, A. Arce, A. Soto, Oil recovery tests with ionic liquids: a review and evaluation of 1-decyl-3-methylimidazolium triflate, Petrol. Sci. (2021), https:// doi.org/10.1016/j.petsci.2021.10.025. [6] A.Z. Hezave, S. Dorostkar, S. Ayatollahi, M. Nabipour, B. Hemmateenejad, Dynamic interfacial tension behavior between heavy crude oil and ionic liquid solution (1-dodecyl-3-methylimidazolium chloride ([C 12 mim][Cl]+distilled or saline water/heavy crude oil)) as a new surfactant, J. Mol. Liq. 187 (2013) 83– 89, https://doi.org/10.1016/j.molliq.2013.05.007. [7] A.Z. Hezave, S. Dorostkar, S. Ayatollahi, M. Nabipour, B. Hemmateenejad, Effect of different families (imidazolium and pyridinium) of ionic liquids-based surfactants on interfacial tension of water/crude oil system, Fluid Phase Equilibr. 360 (2013) 139–145, https://doi.org/10.1016/j.fluid.2013.09.025. [8] A.Z. Hezave, S. Dorostkar, S. Ayatollahi, M. Nabipour, B. Hemmateenejad, Investigating the effect of ionic liquid (1-dodecyl-3-methylimidazolium chloride ([C 12 mim][Cl])) on the water/oil interfacial tension as a novel surfactant, Colloid Surface A 421 (2013) 63–71, https://doi.org/10.1016/ j.colsurfa.2012.12.008. [9] M. Nabipour, S. Ayatollahi, P. Keshavarz, Application of different novel and newly designed commercial ionic liquids and surfactants for more oil recovery from an Iranian oil field, J. Mol. Liq. 230 (2017) 579–588, https://doi.org/ 10.1016/j.molliq.2017.01.062. [10] A.K. Manshad, M. Rezaei, S. Moradi, I. Nowrouzi, A.H. Mohammadi, Wettability alteration and interfacial tension (IFT) reduction in enhanced oil recovery (EOR) process by ionic liquid flooding, J. Mol. Liq. 248 (2017) 153–162, https:// doi.org/10.1016/j.molliq.2017.10.009. [11] S. Zabihi, D. Faraji, Y. Rahnama, A.Z. Hezave, S. Ayatollahi, Relative permeability measurement in carbonate rocks, the effects of conventional surfactants vs. Ionic liquid-based surfactants, J. Disper. Sci. Techol. 41 (2019) 1797–1811, https://doi.org/10.1080/01932691.2019.1637262. [12] K. Li, D. Wang, S. Jiang, Review on enhanced oil recovery by nanofluids, Oil Gas Sci. Technol. 73 (2018) 37, https://doi.org/10.2516/ogst/2018025. [13] F. Yakasai, M.Z. Jaafar, S. Bandyopadhyay, A. Agi, Current developments and future outlook in nanofluid flooding: A comprehensive review of various parameters influencing oil recovery mechanisms, J. Ind. Eng. Chem. 93 (2021) 138–162, https://doi.org/10.1016/j.jiec.2020.10.017. [14] R.O. Afolabi, Enhanced oil recovery for emergent energy demand: challenges and prospects for a nanotechnology paradigm shift, Int. Nano. Lett. 9 (2019) 1– 15, https://doi.org/10.1007/s40089-018-0248-0. A. Al-Asadi, A. Arce, E. Rodil et al. Journal of Molecular Liquids 363 (2022) 119798 9