Search

In this work, a mathematical formulation based on fundamental principles of momentum and mass transport with a kinetic adsorption model at the liquid-solid interface is proposed. This formulation was numerically solved and used for the interpretation of adsorption rate data of phenol onto an activated carbon cloth in a stirred tank adsorber under different agitation rates. The mathematical model solution was compared with the obtained by mathematical models that neglect the local velocity and concentration profiles in the solution; external mass transfer model (EMTM) and the first-order kinetic model (FOM). The results showed that under all studied stirring speeds (30−200 rpm) the proposed model was able to capture the dynamics of the concentration decay curves, while EMTM and FOM models were only able to interpret the data at high stirring speeds, indicating that velocity profiles play an important role during phenol adsorption. Particular “wake zones” were identified behind the mobile adsorbent, which importantly promotes the transport of solute toward the activated carbon cloth. As a result, it was found that convective transport is much more important than diffusive transport in the solution.

The objective of the present work is to determine the effect of silica nanoparticles on the microrheological properties of heavy and extra-heavy crude oils using time-domain nuclear magnetic resonance (TD-NMR) methods. Three heavy crude oils with different asphaltene contents were studied. The oils steady-state rheograms were collected as a function temperature and nanoparticles concentration. Transverse relaxation time (T2) and diffusion coefficient measurements were used as probes of the crude oils microrheological responses. A clear inverse correlation between either the log-mean T2 ( T 2 , LM ) or the diffusion coefficient and the rheometric oil viscosity in the presence of nanoparticles was found. Results further show the likely existence of an optimal concentration of nanoparticles in the vicinity of 1000 mg/L. The maximum viscosity reduction of roughly 35–45% was observed for the three heavy crude oils. The heavy oil refractive index decreases after the oil was placed in contact with nanoparticles, confirming adsorption of polar material on nanoparticles. T2 and the diffusion coefficient increase in the apparent region of optimal concentration of nanoparticles and decrease at higher concentration. The improved NMR responses, which reflect the enhanced translational and rotational motion of restricted hydrogen-bearing oil molecules/aggregates proves that microrheological changes occur as oil polar molecules aggregates break down due to the adsorption of asphaltenes. Finally, a multivariate statistical analysis evidences which parameter has the greatest influence on the system response. It is the first time, to the best of our knowledge, that these characterization tools have been used in heavy crude oils in the presence of nanoparticles.

The nanofluid (nanoparticles dispersed in determined carrier fluid) flooding has been studied for reducing the interfacial tension (IFT), increasing the viscosity of the displacement phase and to alter the rock wettability, which impact the capillary number and hence increase the crude oil recovery. However, this technique requires commonly large concentration of nanoparticles for being efficient in enhanced oil recovery (EOR) processes. Hence, the primary objective of this manuscript is to develop NiO-containing Janus nanoparticles based on zero-dimension (0-D) SiO2 nanoparticles which can be effective at low concentrations. The synthesized nanoparticles were characterized by transmission electron microscopy (TEM), surface area (SBET), zeta potential, interfacial tension (IFT), rheology, contact angle measurements and coreflooding tests. The results showed a sharply increase of the capillary number (Nc) at a very low concentration of 100 mg/L of Janus nanoparticles, mainly attributed to the decrease in the interfacial tension, which can lead to the increase of the oil recovery. Displacement tests using a SiO2 nanoparticles-based nanofluid at a concentration of 100 mg/L did not show an increase in oil recovery regarding the one obtained in the waterflooding step. Meanwhile, the nanofluid based on NiO/SiO2 Janus nanoparticles at the same concentration of 100 mg/L showed an increase in oil recovery up to 50%.

The oil productivity of tight gas-condensate reservoirs can be affected by the precipitation/deposition of inorganic scales such calcium carbonate (CaCO3), which leads to a reduction mainly in permeability and porosity of the porous media. Therefore, the main objective of this study is to develop for the first time a nanofluid based on the interaction between active nanoparticles such as Ca-diethylenetriamine pentamethylene phosphonic (Ca-DTPMP) and remaining synthesis fluid (RSF) obtained from the synthesis process, to simultaneously inhibit and remove the formation damage due to the precipitation/deposition of CaCO3 scales. The synthesis of the Ca-DTPMP nanoparticles was performed varying the phosphonate concentration between 0.01 and 0.5 M. The obtained nanoparticles were characterized through N2 physisorption at −196 °C for obtaining the surface area (SBET), field emission scanning electron microscopy (FESEM), and dynamic light scattering (DLS) measurements. The mean nanoparticles size of the obtained materials ranged between 36 and 69 nm and was lower for the nanoparticles synthesized with a lower concentration of DTPMP. Nanofluids containing the synthesized nanoparticles of Ca-DTPMP were prepared with RSF solutions in deionized water as a carrier fluid for different Ca-DTPMP/RSF ratios of 10, 50, 200 and 500. The ability of the nanoparticles and nanofluids to inhibit the CaCO3 scaling was evaluated in batch-mode experiments at 70 °C by measuring changes in the calcium ion (Ca2 +) concentration in the solution. The nanofluid with better performance was that prepared with 50 mg/L of Ca-DTPMP/0.3 nanoparticles and a Ca-DTPMP/RSF ratio of 10, with an inhibition efficiency of 67%. Further, coreflooding tests were carried out using the nanofluid with better performance from the batch – mode experiments. Displacement tests were conducted under tight gas-condensate reservoir conditions at a temperature of 110 °C (230 °F) and confining and pore pressures of 34.47 MPa (5000 Psi) and 6.89 MPa (1000 Psi), respectively. Inhibition and remediation of CaCO3 scaling were evaluated. The nanofluid was soaked in the porous media for 8 h. Based on the results of the relative permeability and oil recovery curves, it is possible to conclude that the synthesized nanofluid promotes the inhibition and removal of the formation damage due to CaCO3 inorganic scales. The nanofluid injection leads to an increase of the oil permeability of 57% in comparison with the base system, suggesting that the nanofluid acts as inhibitor agent, as remediation treatment, and as stimulation product of oil wells. Also, the treatment showed a perdurability of more than 60 pore volumes and increasing of oil recovery of 4 and 24% regarding the base and the damaged systems, respectively.

One of the most common sources of formation damage in tight reservoirs of gas-condensate is condensate banking. The condensate level on the porous media reduces the effective permeability to gas, decreasing the gas production primarily because the pressure reaches values that are lower than dew point pressure or because there is a sharp pressure drop in the near wellbore. The primary objective of this study is to develop a nanofluid, based on the interaction between an anionic surfactant and silica (SiO2) nanoparticles, to alter the reservoir wettability from a liquid-wet state to gas-wettability. The SiO2 nanoparticles were modified by an incipient method using a solution of anionic commercial surfactant Silnyl®FSJ (SY) at various concentrations from 3.0 to 7.0 wt%. Posteriorly, the nanofluids were prepared with modified SiO2 nanoparticles that were dispersed in an SY solution in deionized water. Nanofluids were initially evaluated at room conditions by contact angle and imbibition tests on oil-wet and water-wet sandstone samples for the wettability alteration to obtain the best concentration ratio of modified nanoparticles and SY in the nanofluid. Different combinations and individual effects of the nanoparticles and SY surfactant were evaluated. Better performance in changing the wettability of the system was achieved for a nanofluid at a concentration of 500 mg/L of SiO2 nanoparticles, which were functionalized with 5.0 wt% of SY and dispersed in an SY solution at 0.46 wt% in deionized water. In water-wet samples, contact angles changed from 0° to 118° and from 32° to 95° for water/rock/air and oil/rock/air systems, respectively. Similarly, for oil-wet samples, the contact angles were modified from 123° to 115° and from 0° to 93°.Coreflooding tests were performed under tight gas-condensate reservoir temperature and pressure conditions. Through the permeability curves and oil recovery, the synthesized nanofluid was observed to alter the wettability of the system from a strongly liquid-wet to a gas-wet condition. Additionally, according to the results, the use of the synthesized nanofluids can reduce the formation damage caused by the condensate banking, favoring the mobility of liquid and leading to a considerable improvement in oil and gas production. The oil recovery increases from 46.6% in the base system to 78.4% after treatment. Additionally, residual saturation of oil was reduced from 29.2% to 17.8% in the base and treated systems, respectively.

The primary objective of this study is to investigate the effects of SiO2 nanoparticles on improving the rheological behavior and inhibition of the thermal degradation of hydrolyzed polyacrylamide (HPAM) solutions. The SiO2-HPAM interactions were evaluated through i) Polymer adsorption onto nanoparticles, ii) rheological studies, and iii) evaluation of thermal stability in presence or absence of oxygen. SiO2 nanoparticles and HPAM were characterized through thermogravimetric analyses (TGA), Fourier transform infrared spectroscopy (FTIR) and dynamic light scattering (DLS). The nanofluids were prepared by adding a fixed concentration of nanoparticles to an HPAM-containing aqueous solution. The adsorption isotherms of HPAM over the SiO2 nanoparticles were obtained in batch-mode experiments. Results of adsorption experiments showed that isotherms followed a Type III behavior. The adsorption isotherms were modeled using Langmuir, Freundlich and Solid-Liquid Equilibrium (SLE) model. The best fitting was obtained using the SLE model based on the root-mean-square error (RMSE%), which was lower than 9.5. Also, polymer desorption from the surface of nanoparticles was found to be negligible, and thus the sorption process can be considered irreversible under conditions evaluated. Rheological tests in the range of 25 to 70 °C showed a pervasive non-Newtonian behavior for all the SiO2-HPAM combinations tested. The Herschel-Bulkley and Carreau models were used to describe the rheological behavior of the prepared nanofluids with RMSE% values better than 0.3. The thermal stability of polymeric solutions in the absence and presence of nanoparticles was evaluated under inert and oxidative atmospheres at 70 °C for 14 days. It was observed that a lower degree of degradation resulted for polymeric solutions in the presence of nanoparticles and the absence of oxygen, indicating that SiO2 nanoparticles can inhibit HPAM degradation through adsorption, and subsequently improve its thermal stability.

The main objective of this study is twofold. First, we evaluate the effect of nanofluids as additives to optimize the transport of heavy crude oil using steady-state rheological measurements and dynamic flow tests. The use of these additives produces viscosity reduction for heavy (HO) and extra heavy (EHO) crude oils. Second, we show how the addition of nanofluids can lead to significant economic and environmental impacts in Colombia as a country and possibly the region through optimization in the use of naphtha for transportation. Four nanofluids were prepared using different solvents and fumed silica nanoparticles. Mixtures of nanofluids with naphtha were prepared to reduce the viscosity of the crude oil as to attain mobility targets (400–500 cP at 311 K). To this end, 27% and 63% v/v of naphtha were required for heavy and extra-heavy crude oils, respectively. Through steady-state rheological measurements and dynamic flow tests in a pipeline, we found that the best performing material turned out to be the nanofluid composed of 1000 mg/L of SiO 2 and biodiesel without surfactant. This nanofluid yielded a reduction in the consumption of naphtha of approximately 50% v/v. Our results show that the best-performing nanofluid can serve as an optimizing agent for the transport conditions of heavy and extra-heavy crude. The proposed technology was evaluated through a preliminary economic analysis that shows a potential reduction of dilution costs of almost 50%, equivalent to more than USD $2.5 million per day, as well as a decreased energy consumption associated with pumping of 37%, able of generating savings of more than USD $2 million per year. Additionally, a discussion on environmental impacts are presented, and the advantages of reducing naphtha consumption are discussed. A nanofluid-based technology could generate savings in both energy and fuel consumptions for the oil and gas industry and resolve national or regional issues constrained by limited access to diluent.

In Colombia, the estimated reserves of crude oil are approximately 2.0 thousand million barrels, decreasing by approximately 13% in the last year according to the National Hydrocarbons Agency (ANH). In addition, the exponential growth of the world population as well as increasing motorization and industrialization has led to higher demand for fossil fuels to supply energy requirements. Colombia is aware of this issue and has become a key player of incorporating advances in nanotechnology to address this challenge by increasing the productivity/reserves of crude oil. Nanotechnology progress in Colombia has been supported by academy – state – industry synergy, which has aimed to mitigate formation damage and enhance oil recovery to facilitate increases in oil productivity and reserves based on the development of nanoparticles/nanofluids. In this sense, Colombia has been a worldwide pioneer in the application of nanotechnology under field-scale conditions, which has led to significant increases in oil rate production. This document presents a review of the recent applications of nanotechnology in Colombia, from laboratory approaches to field conditions. This review addresses the development of nanoparticles/nanofluids for application to the inhibition/remediation of formation damage (asphaltenes, alteration of reservoir wettability from liquid-wet to gas-wet, and inorganic scales, among other applications), productivity improvement (hydraulic fracturing, drilling fluids, and improvement mobility of heavy and extra-heavy oils), enhanced oil recovery (EOR) and heavy oil transport. Finally, three cases of field trials employing nanofluids are discussed for inhibiting the formation damage of asphaltene in tight-condensate reservoirs and light oil crude, fines migration in tight-condensate reservoirs and mobility improvement of heavy and extra-heavy oils. It is expected that this document will aid in the alignment of the academic and industrial sectors to pursue and incentivize the opening of a wider range of applications under field conditions through the extrapolation of laboratory studies.

Hydraulic fracturing is one of the most common stimulation operations for increasing the productivity of a well. The fracturing fluid is one of the key factors in the operation and must accomplish some special requirements and behavior. The fluid that remains inside the fracture and the reservoir after the fracturing operation is finished, causes severe damage to the proppant pack and the formation, leading to a lower efficiency of the stimulation. This study presents experimental research on adding nanoparticles to a commercial fracturing fluid commonly used for tight gas-condensate reservoirs, aiming to enhance its performance in rheological behavior and its capacity to reduce the formation damage associated with the use of fracturing fluids. Nanoparticles with mean particle sizes of 8 and 19 nm with basic and acidic surface modifications were employed for modifying a commercial fracturing fluid. Rheology tests were performed at pressure and temperature conditions of 1.38 MPa and 104 °C, respectively, for the different nanoparticles at dosages of 100 and 200 mg/L. The improvement of those properties enabled the modification of the original formulation of the fluid, reducing the amount of methanol, one of most expensive and hazardous additives, by up to 33%, and reducing the formation damage by approximately 71%. Furthermore, this modified fluid was evaluated in terms of its impact in the wettability of the rock and its relative permeability to water and oil through static (contact angle measurements) and dynamic tests (relative permeability curves). The modified fracturing fluid showed an excellent capability to improve the water-wettability of the rock and also decreased the relative water permeability by 83%. This work demonstrates the suitability of adding nanoparticles to fracturing fluid for stimulations where it is necessary to reduce the relative permeability of water, acting as a Relative Permeability Modifier (RPM) in a conformance for a fracturing operation.

Fines migration in the reservoir can leads to damage associated with the mobilization of particles and their posterior accumulation in throat pores, producing obstructions in the flow of fluids, resulting in a decrease of reservoir permeability. An emergent alternative to solve this issue is the use of nanoparticles/nanofluids due to their physicochemical properties that can favor the trapping capacity of fines. Hence, this experimental work aims to evaluate the chemical nature effect of different fines and their respective interaction with three kinds of nanoparticles used in specialized literature for formation damage. In this work was emulated experimentally the retention phenomena through a packed sand bed treated with the different nanofluids and then assessed with the suspension of the fines. The sand beds were prepared with Ottawa sand in two ways: water-wet and sand restored to reservoir wettability (oil-wet). The sand beds were soaked with the specific nanofluids which were with deionized water as carrier fluid for the nanoparticles of iron, silica, and alumina at a dosage of 0.01% in a mass fraction respectively. The suspension of fines was constituted by quartz, kaolinite, illite, at a dosage of 0.2 wt%; the chemical nature was based on an average composition of a Colombian field. The Adams-Bohart, Thomas, and Wolborska models were used for describing the results of breakthrough curves. The beds treated with alumina nanoparticles at 0.01 wt% presented a higher capacity to retain and stabilize the Kaolinite fines, increasing the retention capacity up to 50%. The results agree with the total energy interaction of the fines-nanoparticles system reported for alumina nanofluids. Additionally, critical rate tests at reservoir conditions were performed, obtaining successful results by the increasing of critical rate by more than 50% for water and oil flow velocities in comparison to the untreated system. In this sense, this work presents a comprehensive analysis of selectivity of fines-nanoparticles couples through the design of the optimized experiment, focused on selecting select the best nanofluid treatment for the problem of fines migration.

Nanotechnology offers potentially disruptive methods to improve the mobility of heavy oil through viscosity reduction. In this sense, the objective of this work is to probe changes in the viscoelastic network of asphaltenes intrinsic to heavy oil structure upon addition of fumed SiO 2 nanoparticles, using dynamic rheological techniques. The effects of the addition of nanoparticle (100, 1000 and 10,000 mg/L) on heavy oil are patently reflected as a viscosity reduction (for shear rates between 0 and 100 s −1 ) and a non-Newtonian shear thinning behavior. The best concentration of nanoparticles over the wide range evaluated is obtained at 1000 mg/L, which was evaluated at 288, 298 and 313 K. The viscosity reductions were found to range from 12 to 45% in the shear rate range 0–100 s −1 . The linear viscoelastic region (LVR) was determined by running an amplitude sweep test at 10 rad/s and 298 K. Viscoelastic moduli were measured in dynamic tests in a frequency range from 0.1 to 100 rad/s at a strain of 2% and at temperatures of 288, 298 and 313 K. For heavy crude oil without nanoparticles, the magnitude of the loss modulus G″ and its growing trend suggest the existence of a viscoelastic network of asphaltenes and auto-associative behavior. For all tests, the loss modulus, G″, is always greater than the storage modulus G′, suggesting that the crude oil is more viscous than elastic, except at 313 K and at a frequency > 30 rad/s, where G′ is greater than G″. By adding 1000 mg/L of nanoparticles, the magnitude of the viscoelastic moduli is reduced compared to values for crude oil without nanoparticles. The results conclusively prove that nanoparticles disrupt the viscoelastic network formed by asphaltenes aggregates in the presence of resins, and this causes the viscosity reduction in heavy crude oil. This conclusion is further supported by results obtained when nanoparticles were added to de-asphalted oil (DAO) and light oil with a low asphaltene content; in both cases the viscosity increases, suggesting that the nanoparticles interact directly with asphaltenes in crude oil. Effects are observed if asphaltenes are present at high enough concentration.

In this work, we evaluate the effect of nanoparticles and nanofluids as viscosity reducers for heavy crude oil (HO). The effect of alumina, silica and acidic silica nanoparticles was evaluated through n-C7 asphaltene adsorption and aggregation tests using UV–vis spectrophotometry and dynamic light scattering. The nanoparticles of acidic silica were used to prepare a water-based nanofluid at different concentrations in distilled water, and also with the addition of 2.0 wt% of a non-ionic surfactant. The shear rheological response was obtained as function of nanoparticle concentration, temperature (from 298 to 323 K) and shear rate (ranging from 0 to 100 s−1). Experimental results indicate that increasing the concentration of nanoparticles in the mixture, up to 10,000 ppm, leads to a viscosity reduction of approximately 90% in comparison with the nanoparticle-free crude oil. At higher concentration of nanoparticles, the effectiveness of the heavy-oil viscosity reduction diminishes. Rheological tests showed a non-Newtonian behavior for the mixtures tested at 298 K. However, as the temperature reaches 323 K the specimens behave in a Newtonian fashion. Coreflooding tests were conducted under typical reservoir conditions of pore and overburden pressures, i.e. 2600 and 3600 psi, respectively, and at 360 K. Results indicate that the addition of nanoparticles increases the heavy oil mobility and leads to an improvement in oil recovery of roughly 16%.

Manganese ferrite solid nanospheres (MSNs) were prepared by a solvothermal method and calcined at various temperatures up to 500 °C. Their surface area, morphology, particle size, weight change during calcination, surface coordination number of metal ions, oxidation state, crystal structure, crystallite size, and magnetic properties were studied. The MSNs were used as catalysts to activate potassium peroxymonosulfate (PMS) for the oxidative degradation of para-nitrophenol (PNP) from water and for the oxidation of n-C7 asphaltenes in flowing air at atmospheric (0.084 MPa) and high pressure (6 MPa). Mn was in oxidation states (II) and (III) at calcination temperature of 200 °C, and the crystalline structure corresponded to jacobsite. Mn was in oxidation states (III) and (IV) at 350 °C and in oxidation states (II), (III), and (IV) at 500 °C, and the crystalline structure was maghemite at both temperatures. MSN catalysts generated hydroxyl (HO·) and sulfate (SO4·-) radicals in the PMS activation and generated HO· radicals in the n-C7 asphaltene oxidation. In both reactions, the best catalyst was MSN calcined at 350 °C (MSN350), because it has the highest concentration of Mn(III) in octahedral B sites, which are directly exposed to the catalyst surface, and the largest total and lattice oxygen contents, favoring oxygen mobility for Mn redox cycles. The MSN350 sample reduces the decomposition temperature of n-C7 asphaltenes from 430 to 210 °C at 0.084 MPa and from 370 to 200 °C at 6.0 MPa. In addition, it reduces the effective activation energy by approximately 77.6% in the second combustion (SC) region, where high-temperature oxidation reactions take place.

This study has a primary objective the evaluation of the effect of surface acidity of silica nanoparticles for mitigation of time-dependent thermal degradation of polymer solutions of partially hydrolyzed polyacrylamide (HPAM), for employment in chemical enhanced oil recovery (EOR) processes. For this, silica (SiO2) nanoparticles were modified on the surface with NaOH (SiO2B) and HCl (SiO2A). The obtained nanoparticles were characterized through field emission electron microscopy, surface area, total acidity by NH3-Temperature programmed desorption, dynamic light scattering (DLS), and electrophoretic light scattering (ELS) for zeta potential. The nanoparticle-polymer interaction was analyzed by adsorption isotherms. Also, the rheological behavior of HPAM solutions at 500 mg L−1 with and without 3000 mg L−1 of raw and functionalized nanoparticles was evaluated at a temperature of 70 °C through steady-state rheometry and dynamic oscillatory measurements at the day zero and after 15 days of aging. Also, coreflooding tests were carried out at conditions of pressure and temperature of a reservoir of interest using the aged polymer solutions with and without nanoparticles. The results show that the polymer adsorption decreases in the order SiO2B > SiO2>SiO2A, indicating that polymer uptake is higher as the surface acidity of nanoparticles decreases. SiO2B nanoparticles showed greater interactions between the functional groups on the surface and the HPAM in solution, forming a polymer network more resistant to degradation. A lower viscosity reduction with the addition of the unmodified SiO2 nanoparticles and SiO2B up to 49.6% and 22.9% was observed, respectively, and is closely related to the adsorption affinity and nanoparticles’ surface acidity. Coreflooding tests also indicated that, there is lower polymer retention in the porous medium when nanoparticles are included. In addition, the aged polymer solution with nanoparticles promotes an additional oil recovery of about 30% regarding polymer without nanoparticles.

The main objective of this manuscript is the design of completion nanofluids (NanoCF) using silica nanoparticles based on the impact on the capillary number for being applied in heavy crude oil reservoirs. Six types of silica nanoparticles with different chemical nature were characterized by dynamic light scattering (DLS), point of zero charge (pHpzc), Fourier transform infrared spectroscopy (FTIR), transmission electron microscopy (TEM), surface area (SBET), X-ray diffraction (XRD) and total surface acidity through temperature-programmed desorption of NH3 (TPD-NH3). Adsorption isotherms were constructed for understanding the non-ionic surfactant interaction with nanoparticles and rock surfaces, showing that a high adsorption affinity of the surfactant onto the rock surface, leaving less than 24% of free surfactant molecules able to migrate to the water/oil interface. Nevertheless, nanoparticle addition onto completion fluids (CF) could reduce the adsorbed surfactant onto the rock surface by 75%, which means more molecules of surfactant at the interface due to the nature of the obtained nanoparticles (NPS). The nanoparticles were selected based on the capillary number, showing that the best material reduced the interfacial tension between heavy crude oil and CF more than 76% and have the capacity to modify an initial oil-wet state to a water-wet rock surface. Finally, a coreflooding test was carried out at reservoir conditions (158 °F and 6.89 MPa) for evaluating the best completion nanofluid design based on the static tests, showing an increase of the oil effective permeability of 37% and incremental oil recovery of 3% in comparison to the completion fluid without nanoparticles. For the first time, novel completion nanofluids could allow stimulating the well from the beginning of the productive life.

This study focuses on understanding the effect of the resin/asphaltene mass ratio (R/A) on the rheological behavior of asphaltene solutions. To this aim, two cases were evaluated experimentally and theoretically. The first case comprised asphaltenes dissolved in a de-asphalted oil (DAO) at asphaltene concentrations of 2, 10, and 16.5% of mass fraction, with R/A ratios of 3, 6, and 31 being obtained. The second case consisted of asphaltenes dissolved in p-xylene, at an asphaltene mass fraction of 1 and 18%, and adding resins to obtain low R/A ratios (0, 0.125, 0.5, 1, and 1.5). The viscosities measured experimentally were reproduced by molecular dynamics (MD) simulations, using the Green-Kubo method and non-equilibrium MD (NEMD) for estimating the viscosity of solutions with Newtonian and non-Newtonian behavior, respectively. In all cases, the experimental measurements were accurately reproduced by MD. Further, the asphaltene-asphaltene and asphaltene-resin coordination number (CN), the asphaltene-asphaltene and asphaltene-solvent interaction energies, the radius of gyration, and the volumetric fraction for asphaltene aggregates were calculated. Theoretical results evidence that the asphaltene molecules dissolved in DAO exhibited repulsive interaction energies between them, whereby the asphaltene is mainly dispersed for R/A ratios higher than 3 in DAO. This result indicates that the viscosity of the heavy oil is not only dependent on the asphaltene aggregation, but that the resin plays a key role in the rheological behavior of this type of crude oil. This latter suggestion was evidenced in the viscosity measurements due to the DAO viscosity (1776 cP) being considerably higher compared to the individual viscosity of the other compounds of the mixture (i.e., saturates and aromatics), which were at least two orders of magnitude lower. In the experimental evaluations of rheological behavior, varying the resin amount in asphaltene dissolved in p-xylene, a minimum viscosity point was obtained for a specific R/A ratio. The MD results indicated that the resins inhibit the asphaltene aggregation, reducing the volumetric fraction and, therefore, the viscosity decreased. Understanding the physical principles of the effect of the resin on the asphaltenes' aggregation, from an atomistic point of view, is a valuable contribution for designing inhibitors that can be used for the specific molecular characteristics of any crude oil.

Large amounts of produced water from oilfields is one of the consequential environmental problems caused by the oil and gas industry. This work is the first to attempt the production of biomaterials based on the immobilization of a hydrocarbon-degrading bacterial strain (P. stutzeri) on xerogel microspheres. It aims to evaluate their ability to adsorb and decompose hydrocarbons (benzene, toluene, and phenol (BTP) system) and crude oil from oil-in-saltwater emulsions (O/W). Four xerogel microspheres are prepared by the sol–gel method: carbonized and functionalized microspheres labeled as organic microspheres (OMe), carbonized microspheres (CMe), and carbonized-functionalized microspheres with nitrogen (CMeN) and phosphorous atoms (CMeP). Their textural properties are characterized by scanning electron microscopy, N2 adsorption, and mercury porosimetry. X-ray photoelectron spectroscopy and isoelectric point are employed for the chemical characterization. Biomaterials are developed by the excess impregnation of P. stutzeri strain in the stationary phase onto the microspheres. Finally, the removal of crude oil and BTP system from O/W emulsions using biomaterials is assessed, and the residual oil and BTP contents are analyzed by gas chromatography–mass spectrometry and high-performance liquid chromatography, respectively. Results show that the BTP removal is better in the following order of materials: Microspheres without P. stutzeri (support) > biomaterials > free P. stutzeri with removal percentages of up to 100 %, 84.8 %, and 60.8 %, respectively. For crude oil, biomaterials and supports lead to the complete removal of hydrocarbons from O/W emulsions, i.e., 100 % in 72 h, whereas that of free microorganisms only reach 61 % over the same duration

This study is focused on understanding the effect of the additional methyl group (-CH3) of p-xylene, in comparison with toluene, on the rheological behavior of model solutions of asphaltenes. For this, three concentrations of asphaltenes in both solvents were evaluated experimentally and theoretically. Experimental results show an increase of the viscosity as the asphaltene concentration increase, being up to 739% higher in p-xylene than in toluene. Molecular dynamics (MD) simulations were conducted to understand the difference in the rheological behavior of asphaltene model solutions. The viscosity, volumetric fraction of aggregates, coordination number (CN), as well as the asphaltene-asphaltene and asphaltene-solvent interaction energies were calculated. Experimental viscosities were accurately reproduced by MD simulations, with average deviation lower than 7.4% and 10.9% for toluene and p-xylene solutions, respectively. The volumetric fraction exhibits a similar trend regarding the increase in viscosity, whereby the results obtained are in agreement with the Einstein theory modified for concentrated suspensions, since an increase in the volumetric fraction promotes viscosity increases. On the other hand, from the theoretical evaluation, it was found out that the additional methyl group in the p-xylene structure regarding toluene, promotes significant differences between the interaction energies of asphaltene aggregates. This is a consequence of an increasing of the aggregates size, which contributes to the increase of volumetric fraction and therefore the viscosity. Finally, this study highlights the importance of the asphaltene-solvent relationship, from an atomistic point of view, since small changes in aggregates volume promotes significantly changes in viscosity.

In this study, the influence of Al2O3/SiO2 nanoparticles (NPs) on the Cetyl Trimethyl Ammonium Bromide (CTAB) foam formation and stability is investigated for enhanced oil recovery (EOR). The optimum foaming concentration of CTAB in the presence of heavy crude oil was first determined via visual foam stability inspections for different CTAB concentrations. The results of these sets of experiments were used to find out an appropriate CTAB: Al2O3/SiO2 NPs concentration ratio for foam stabilization through spectroscopy measurements. Different static analyses, including zeta potential, contact angle, and interfacial viscosity measurements were conducted to support the observations in the porous media during flooding. Improved foam stability in the presence of crude oil was observed with Al2O3/SiO2 CTAB foam via electrostatic adsorption of positive CTA+ molecules onto the negatively charged NPs at the appropriate concentration ratio of CTAB: NPs. Contact angle measurements showed a similar glass wettability alteration from an oil-wet (155 ± 3°) to a water-wet condition (19–29°) for all blends of CTAB and Al2O3, SiO2, or Al2O3/SiO2 NPs. Foam/heavy crude oil interfacial viscosity measurements increased with the addition of NPs to the foam solutions, indicating an improved foam bubble deformability, viscoelasticity, and stability, which was consistent with the foam behavior in the porous medium. Oil displacement studies in the glass micromodel showed the highest ultimate and incremental oil recovery of 92% and 73% OOIP, respectively, for Al2O3/SiO2 CTAB foam injection in the dual permeability porous medium. Some new forms of conventional foam mechanisms in the porous medium were also observed during the injection of Al2O3/SiO2 CTAB foam, which are believed to be the possible reason for this high ultimate oil recovery. These results prove the efficient role of Al2O3/SiO2 NPs in enhancing the foam performance via synergistic effects of NPs and CTAB.

In a previous study, we showed that Ni–Pd bimetallic nanocatalysts supported on fumed silica had better adsorption affinity and catalytic activity toward adsorption and post-adsorption decomposition of asphaltenes compared to the support without functionalization. In this study, the effect of oxide support types on the adsorption and subsequent steam gasification of adsorbed asphaltenes was studied over Ni–Pd bimetallic nanocatalysts supported on TiO 2 or γ-Al 2 O 3 nanoparticles. X-ray diffraction (XRD), field emission scanning electron microscopy (FESEM) and N 2 physisorption at 77 K were used to characterize the crystal size and surface area of NiO and/or PdO-supported-on-TiO 2 or γ-Al 2 O 3 nanoparticles, respectively. The type of support was shown to affect the adsorption affinity and catalytic activity of the particles; Ni–Pd/TiO 2 nanoparticles showed higher adsorption capacity and catalytic activity than Ni–Pd/γ-Al 2 O 3 , presumably due to different metal-support interaction and geometric and electronic effects on the surface. Bimetallic nanoparticles appeared to have better adsorption and catalytic behavior than monometallic nanoparticles regardless of the oxide support used, confirming their synergistic effect.

To meet the growing global energy demand, it is necessary to use enhanced oil recovery (EOR) methods to produce fuel from unconventional oil fields. The injection of steam combined with foams as a divergent fluid is one of the techniques proposed as an alternative to improve the production efficiency of heavy and extra heavy oil reservoirs. To achieve this goal, it is necessary to optimize foam stability. This work proposes a technique to improve foam stability using polyethylene glycol (PEG)-coated silica nanoparticles as an additive, which in synergy with a surfactant provide a structural reinforcement of the bubbles to increase their half-life time and durability. For this purpose, four silica nanoparticles with different amounts of surface coating material (i.e. polyethylene glycol) were synthesized by the sol gel method in order to modify their chemical and physical properties. Then, the nanoparticles were characterized to determine properties such as size, point of zero charge, and chemical composition. Nanofluids were obtained by mixing of surfactant solution and nanoparticles. Their corresponding aggregate size and zeta potential were experimentally determined. Subsequently, nanofluids were tested and it was found an increase in the durability of the foam up to 67%. Additionally, adsorption tests were performed to analyze the interactions between nanoparticles and fluids. Moreover, apparent viscosity and the morphologies of the foams were analyzed through microscopic observation of the bubbles to determine changes in their structure. The results show that the diffusion of gas slows down in the presence of nanoparticles and the liquid films between bubbles also become thicker. In summary, the results show that the functionalized nanoparticles could increase the quality of nitrogen foam.

Oil spills on fresh water can cause serious environmental and economic impacts onshore activities affecting those who exploit freshwater resources and grassland. Alumina nanoparticles functionalized with vacuum residue (VR) were used as a low-cost and high hydrophobic nanosorbents. The nanomaterial resulting showed high adsorption affinity and capacity of oil from oil-in-freshwater emulsion. The effects of the following variables on oil removal were investigated, namely: contact times, solution pH, initial oil concentrations, temperature, VR loadings and salinity. Kinetic studies showed that adsorption was fast and equilibrium was achieved in less than 30 min. The amount adsorbed of oil was higher for neutral system compared to acidic or basic medium. Increasing the VR loading on nanoparticle surface favored the adsorption. Results of this study showed that oil removal for all systems evaluated had better performance at pH value of 7 using nano-alumina functionalized with 4 wt% VR. Adsorption equilibrium and kinetics were evaluated using the Polanyi theory-based Dubinin–Ashtakhov (DA) model, and pseudo-first and pseudo-second order-models, respectively.

Nanoparticles can be used as adsorbents and catalyst in oil industry for in situ upgrading in the oil industry. The main objective of this study was to investigate the kinetic and thermodynamic equilibrium of asphaltene sorption onto nanoparticles of nickel oxide supported on nanoparticulated alumina at different temperatures, times, and concentrations. Alumina-supported nanoparticles were characterized by N2 adsorption at −196 °C and X-ray diffraction. Complete asphaltene sorption on nanoparticles of nickel oxide supported on nanoparticulated alumina can be effectively reached at relatively short times (around 2 min), making this sorbent a good candidate for asphaltene sorption. The sorption equilibrium of asphaltene for alumina and alumina-supported nanoparticles at different temperatures (25, 40, 55, and 70 °C) over a wide range of asphaltene concentration, from 150 to 2000 mg/L, was determined using a static method. The Langmuir and Freundlich models were used for correlating the experimental data of the sorption equilibrium at different temperatures. Regarding to the Al and AlNi5 samples, the experimental data on asphaltene sorption isotherms were adequately adjusted by the Freundlich model. On the other hand, for the AlNi15 sample the experimental data were adequately fitted by the Langmuir model. The adsorption of asphaltene on NiO supported on alumina was much higher than that over alumina for the range of equilibrium concentrations tested. Pseudo-first-order and pseudo-second-order kinetic models were applied to the experimental data obtained at different concentrations of asphaltenes from 250 to 2000 mg/L for alumina and alumina-supported materials, with a better fitting to the pseudo-second-order model.

Silica gel and zeolite 13X were used as supports for the hygroscopic salts LiBr, MgCl 2 and CaCl 2 . The silica- and zeolite-supported hygroscopic salts were characterized by N 2 adsorption at −196 °C and X-ray diffraction. The silica support was mesoporous whereas the zeolite support was microporous. The dispersion of CaCl 2 was much lower on the zeolite than on the silica support, and the microporosity of the zeolite was blocked by the salt. CaCl 2 supported on silica was a superior water sorbent versus zeolite, and CaCl 2 supported on zeolite was an inferior sorbent versus zeolite. Complete water desorption from silica-supported hygroscopic salts can be effectively reached at a relatively low temperature (100–110 °C), making them candidates for efficient cooling or air conditioning applications. The isosteric heat of water desorption was obtained from the isobars and was dependent on the amount of water adsorbed. Finally, the thermodynamic cooling cycle for the SCa33 (silica gel containing 33 wt.% CaCl 2 ) – water vapour pair showed a coefficient of performance of 0.83.

A rapid and novel approach for predicting sorption isotherms based on the Polanyi theory is proposed. This approach allows the prediction of the sorption isotherms at different temperatures from one experimental isotherm. The theoretical predictions of isotherms and isosteric heats were validated successfully using data from the literature for different meat types. This method allows total experimental time and operation costs to be reduced.

A theoretical dissertation and experimental assays of the irreversible phenomena applied to electro-kinetics and inverse osmosis is presented. Experimental assays were made on simple equipment to evidence the occurrence of connected irreversible phenomena between electric current flow and global mass flow. The coupling of these two phenomena allowed us to make conclusions about the possibility of reducing operation costs of the inverse osmosis equipment due to increasing the saline solution flow between 12% and 20%.

A transient model of a sorption refrigerator using activated carbon/methanol pair is presented. It is a non-uniform pressure model conformed by the mass, energy and momentum balance equations in cylindrical coordinates, for the activated coal bed contained in the adsorber. The results obtained from the simulation were suitably validated by the experimental information obtained from field test data and from data reported in the literature, presenting errors below 1.6% for each cycle step. The model allows to get data of temperature, pressure, density and gas velocity profiles in radial direction, as well as the solid temperature and the quantity of adsorbed methanol in the activated carbon bed in adsorption/evaporation and desorption/condensation steps.