RESUMO
The primary objective of this study is to develop a novel experimental nanofluid based on surfactant-nanoparticle-brine tuning, subsequently evaluate its performance in the laboratory under reservoir conditions, then upscale the design for a field trial of the nanotechnology-enhanced surfactant injection process. Two different mixtures of commercial anionic surfactants (SA and SB) were characterized by their critical micelle concentration (CMC), density, and Fourier transform infrared (FTIR) spectra. Two types of commercial nanoparticles (CNA and CNB) were utilized, and they were characterized by SBET, FTIR spectra, hydrodynamic mean sizes (dp50), isoelectric points (pHIEP), and functional groups. The evaluation of both surfactant-nanoparticle systems demonstrated that the best performance was obtained with a total dissolved solid (TDS) of 0.75% with the SA surfactant and the CNA nanoparticles. A nanofluid formulation with 100 mg·L-1 of CNA provided suitable interfacial tension (IFT) values between 0.18 and 0.15 mN·m-1 for a surfactant dosage range of 750-1000 mg·L-1. Results obtained from adsorption tests indicated that the surfactant adsorption on the rock would be reduced by at least 40% under static and dynamic conditions due to nanoparticle addition. Moreover, during core flooding tests, it was observed that the recovery factor was increased by 22% for the nanofluid usage in contrast with a 17% increase with only the use of the surfactant. These results are related to the estimated capillary number of 3 × 10-5, 3 × 10-4, and 5 × 10-4 for the brine, the surfactant, and the nanofluid, respectively, as well as to the reduction in the surfactant adsorption on the rock which enhances the efficiency of the process. The field trial application was performed with the same nanofluid formulation in the two different injection patterns of a Colombian oil field and represented the first application worldwide of nanoparticles/nanofluids in enhanced oil recovery (EOR) processes. The cumulative incremental oil production was nearly 30,035 Bbls for both injection patterns by May 19, 2020. The decline rate was estimated through an exponential model to be -0.104 month-1 before the intervention, to -0.016 month-1 after the nanofluid injection. The pilot was designed based on a production increment of 3.5%, which was successfully surpassed with this field test with an increment of 27.3%. This application is the first, worldwide, to demonstrate surfactant flooding assisted by nanotechnology in a chemical enhanced oil recovery (CEOR) process in a low interfacial tension region.
RESUMO
Fines migration is a common problem in the oil and gas industry that causes a decrease in productivity. In this sense, the main objective of this study is to develop nanocomposites based on the interaction of quaternary amine (hexadecyltrimethylammonium bromide-CTAB) and MgO to enhance the capacity of retention of fine particles in the porous medium. MgO nanoparticles were synthesized by the sol-gel method using Mg(NO3)2·6H2O as a precursor. Nanoparticles were characterized by dynamic light scattering (DLS), the point of zero charge (pHpzc), thermogravimetric analysis, and Fourier transform infrared spectroscopy (FT-IR). Different nanoparticle sizes of 11.4, 42.8, and 86.2 nm were obtained, which were used for preparing two system nanofluids. These systems were evaluated in the inhibition of fines migration: in the system I MgO nanoparticles were dispersed in a CTAB-containing aqueous solution, and system II consists of a nanocomposite of CTAB adsorbed onto MgO nanoparticles. The fines retention tests were performed using Ottawa sand 20/40 packed beds and fine particles suspensions at concentrations of 0.2% in a mass fraction in deionized water. Individual and combined effects of nanoparticles and CTAB were evaluated in different treatment dosages. The analysis of the interactions between the CTAB and the MgO nanoparticles was carried out through batch-mode adsorption and desorption tests. The best treatment in the system I was selected according to the fines retention capacity and optimized through a simplex-centroid mixture design for mass fractions from 0.0% to 2.0% of both CTAB and MgO nanoparticles. This statistical analysis shows that the optimal concentration of these components is reached for a mass fraction of 0.73% of MgO nanoparticles and 0.74% in mass fraction of CTAB, where the retention capacity of the porous medium increases from 0.02 to 0.39 mg·L-1. Based on the experimental results, the nanofluids combining both components showed higher retention of fines than the systems treated only with CTAB or with MgO nanoparticles, with efficiencies up to 400% higher in the system I and higher up to 600% in the system II. To evaluate the best performance treatment under reservoir conditions, there were developed core flooding tests at fixed overburden pressure of 34.5 MPa, pore pressure at 6.9 MPa and system temperature at 93 °C. Obtaining critical rate increases in 142.8%, and 144.4% for water and oil flow in the presence of the nanofluid. In this sense, this work offers a new alternative for the injection of nanocomposites as a treatment for the problem of fines migration to optimize the productivity of oil and gas wells.
RESUMO
The main objective of this study is to evaluate the effect of the preparation of the nanofluids based on the interactions between the surfactants, nanoparticles, and brine for being applied in ultra-low interfacial tension (IFT) for an enhanced oil recovery process. Three methodologies for the addition of the salt-surfactant-nanoparticle components for the formulation of an efficient injection fluid were evaluated: order of addition (i) salts, nanoparticles, and surfactants, (ii) salts, surfactants, and then nanoparticles, (iii) surfactants, nanoparticles, and then salts. Also, the effects of the total dissolved solids and the surfactant concentration were evaluated in the interfacial tension for selecting the better formulation of the surfactant solution. Three nanoparticles of different chemical natures were studied: silica gel (SiO2), alumina (γ-Al2O3), and magnetic iron core-carbon shell nanoparticles. The nanoparticles were characterized using dynamic light scattering, zeta-potential, N2 physisorption at -196 °C, and Fourier transform infrared spectroscopy. In addition, the interactions between the surfactant, different types of nanoparticles, and brine were investigated through adsorption isotherms for the three methodologies. The nanofluids based on the different nanoparticles were evaluated through IFT measurements using the spinning drop method. The adsorbed amount of surfactant mixture on nanoparticles decreased in the order of alumina > silica gel > magnetic iron core-carbon shell nanoparticles. The minimum IFT achieved was 1 × 10-4 mN m-1 following the methodology II at a core-shell nanoparticle dosage of 100 mg L-1.
RESUMO
The nanotechnology has been applied recently to increase the efficiency of enhanced oil recovery methods. The main objective of this study is to evaluate the effect of SiO2 nanoparticle functionalization with different loadings of sodium oleate surfactant for polymer flooding processes. The sodium oleate surfactant was synthesized using oleic acid and NaCl. The SiO2 nanoparticles were functionalized by physical adsorption using different surfactant loadings of 2.45, 4.08, and 8.31 wt % and were characterized by thermogravimetric analyses, Fourier-transform infrared spectroscopy, dynamic light scattering, and zeta potential. Adsorption and desorption experiments of partially hydrolyzed polyacrylamide (HPAM) polymer solutions over the unmodified and surface-modified nanoparticles were performed, with higher adsorption capacity as the surfactant loading increases. The adsorption isotherms have a type III behavior, and polymer desorption from the nanoparticle surface was considered null. The effect of nanoparticles in the polymer solutions was evaluated through rheological measurements, interfacial tension (IFT) tests, contact angle measurements, capillary number, and displacement tests in a micromodel. The surface-modified SiO2 nanoparticles showed a slight effect on the viscosity of the polymer solution and high influence on the IFT reduction and wettability alteration of the porous medium leading to an increase of the capillary number. Displacement tests showed that the oil recovery could increase up to 23 and 77% regarding polymer flooding and water flooding, respectively, by including the surface-functionalized materials.