Co-adsorption behaviors of asphaltenes and different flow improvers and their impacts on the interfacial viscoelasticity

Commonly used flow improvers in oilfields, such as ethylene–vinyl acetate copolymer (EVA), poly(octadecyl acrylate) (POA), and polymethylsilsesquioxane (PMSQ) are proven to be effective to enhance the flowability of crude oil. However, the addition of these flow improvers may change the stability of the emulsion and make the crude oil treatment process challenging. In this research, the impacts of different flow improvers on the interfacial properties of the emulsions containing asphaltenes are systematically investigated. The co-adsorption behaviors of the flow improvers and asphaltenes are analyzed through dynamic interfacial tension (DIFT). The rheological properties of the interfacial layer after the adsorption are explored via dilational viscoelasticity. Significant difference is observed in the structural properties of the interface adsorbed by different flow improvers, which is attributed to different interactions between the flow improvers and asphaltenes. To investigate these interactions, conductivity, asphaltenes precipitation, dynamic light scattering (DLS), and contact angle experiments are conducted systematically. Results show that EVA and POA can alter the interfacial properties by changing the asphaltene dispersion state. The interaction between EVA and asphaltenes is stronger than that between POA and asphaltenes due to the difference in molecular structures. Unlike EVA and POA, the change of interfacial property with the addition of PMSQ is attributed to the partial adsorption of asphaltenes on PMSQ.     

Investigation the impact of additives on the displacement of the onset point of asphaltene precipitation using interfacial tension measurement

The purpose of this study is to explore the impact of additives on the displacement of the onset point of asphaltene precipitation in crude oil using the interfacial tension measurement method, based on the examined oil has been taken from Iran reservoirs. The experimental results suggest that the addition of surfactants of dodecyl benzene sulfonic acid (DBSA) and coconut diethanolamide (CDEA) to the oil has triggered the onset of asphaltene precipitation. These findings imply that CDEA has a more effective role in preventing asphaltene precipitation. Also, it was observed that increasing the concentration of the surfactants has led to obtaining greater results. Finally, critical micelle concentration was calculated to be 5000 and 4700 ppm in the cases of CDEA and DBSA, respectively.     

Prediction of the asphaltene deposition profile along a wellbore during natural production from a reservoir

The potential problem of asphaltene deposition during oil production has motivated both academics and industries to predict the asphaltene deposit profile in wellbores and pipelines. In this work, asphaltene deposition profile along an oil field well with the severe problem of asphaltene deposition was predicted. To do this, a comprehensive simulator for modeling of flow parameters such as pressure, temperature, and composition for a multiphase flow of oil, gas, and asphaltene from the reservoir to the surface was developed and coupled with the deposition model. By applying the simulator to an oil field well, it has been found that 60–70% of the total asphaltene thickness formed after 1 month of production, indicating that the problem of asphaltene deposition is bound to the initial stage of wellbore life. Moreover, the simulator was able to predict the accumulated asphaltene thickness and the time of wellbore plugging properly. This prediction is highly crucial if it is aimed to control the well performance and to optimize the productivity.     

Crude oil aggregation by microscopy and dynamic light scattering

This research is focused on establishing a methodology to evaluate the aggregation state of Mexican crude oil solutions from two different sources and SARA compositions, by using Dynamic Light Scattering (DLS). Different crude oil concentrations were established and monitored through time in order to determine their effects on the aggregation state. DLS results indicate that the aggregation state of the studied solutions is influenced by crude oil composition, specifically by the amount of resins. Particle size and elemental analysis of the aggregates were performed by Scanning Electron Microscopy (SEM) and Energy Dispersive X-ray Spectroscopy (EDX), respectively. Results from these techniques reveal particulated low-porosity smooth surfaces due to the presence of resin, as well as the determination of the characteristic elements found in asphaltenes. High-Resolution Transmission Electron Microscopy (HTEM) indicated the presence of asphaltene aggregates constituted by nanometric particles and asphaltene stacking as well as ultrafine nanocrystalline-oriented structures.     

Precipitation of asphaltenes from solvent-diluted heavy oil and thermodynamic properties of solvent-diluted heavy oil solutions

Ratios of n-heptane (hep) to toluene (tol) affect the solubility of the asphaltenes in heavy oil extraction processes. Consequently phase changes and time after mixing n-heptane and heavy oil in toluene are important for understanding produced emulsions. The kinetics of phase change when n-heptane is added to toluene-diluted heavy oils, and the thermodynamic properties of partially deasphalted heavy oils were studied. The methods used were monitoring precipitation in time using light microscopy, quantitative asphaltenes analysis by near infrared spectroscopy, refractive index and densities measurements, and calculated solubility parameters of mixtures. At critical mass ratios of hep/tol from 1.37 to 2.0 in diluted heavy oil the precipitated asphaltene particles were observed under the microscope after lag times from 2 h to instantly. Lag times were longer at low initial oil concentration. The floc growth time decreased as heavy oil concentration in toluene increased. The growth patterns in time appeared as dots to beads (strings) to clusters (fractal-like flocs). Final wt% precipitated asphaltenes vs. mass fraction (hep+tol)/heavy oil followed sigmoidal relationships. Curves showing wt% soluble asphaltenes vs. mass fraction hep/tol after 24 h initially followed the same shape as time zero curves and diverged at the onset ratios of hep/tol. Slope for precipitated asphaltenes vs. solubility parameters curve showed a break at 16.4 MPa^1/2. Linear correlations were established for concentrations of soluble asphaltenes in residual oils and density, for refractive index and density and for refractive index and solubility parameter. The latter correlation was in accordance with Lorenz-Lorentz theory. These equations provided a means by which oil density, refractive index and solubility parameter can be predicted when these measurements are difficult to measure practically.     

Prediction of asphaltene precipitation during gas injection

Maintaining the flow of multiphase fluid from the reservoir to the surface has been an important issue with wide economic importance for the petroleum industry. Asphaltene precipitation due to change in temperature, pressure, and composition of oil can adversely affect the oil flow to the surface by reducing the available diameter of the tubing. In this study, the precipitation of asphaltene from an Iranian crude oil was investigated. To do our study, through information about asphaltene instability in the live oil during both natural depletion and gas injection conditions about oil sample from Iranian oil field was gathered. Then, the solid model and scaling model were utilized to predict the weight percent of precipitated asphaltene at a wide range of the pressure and temperature. Results of the work revealed that both models predict the increase in weight percent of precipitated asphaltene when lean gas injected to the live oil at the maximum point of asphaltene instability. In addition, the study showed that both models are capable of predicting the experimental data of asphaltene precipitation; while scaling modeling is more reliable when the gas is injected to the oil.     

Study of self-aggregation of coal derived asphaltene in organic solvents: A fluorescence approach

Fluorescence spectra of coal derived asphaltenes sourced from Barari coke plant situated at Dhanbad, India, have been studied as a function of concentration in benzene, toluene and carbon tetrachloride with an eye to study the self-aggregation of the solute. Aggregation has been found to be a gradual process and the concentration characterizing onset of aggregation process coincide for the solvents. The critical aggregation constants (CAC) appear to be ca 90-100 and 180-200 for all the solvents. A small red shift of fluorescence band is observed when traces of water (∼0.05%, v/v) are present in carbon tetrachloride solution.     

Prediction of asphaltene deposition parameters in porous media using experimental data during miscible gas injection

The study of asphaltene deposition under actual field conditions is impossible. Therefore, many models have been derived based on experimental data. All models have some matching parameters, which are estimated along with numerical solving or simulation to match experimental and simulation data, so it is possible that these were estimated as required (tuning factor).

In this study, two miscible CO₂ injection dynamic tests in porous media were performed. In these tests, CO₂ and live oil were injected into the core simultaneously. The CO₂ concentration was more than the onset concentration for asphaltene precipitation.

The main objective of this work was to determine the deposition coefficients from the experimental data, so these were predicted by using basic equations using the material balance. Also, by mathematical methods, the relation between these parameters was determined.

Results from this work imply that the deposition parameters can be estimated from the experimental data and these parameters are not constant during modeling and simulation.     

Detecting and Characterizing Asphaltene Instability

Methods of detecting and characterizing asphaltenes abound in the literature, but most can raise significant levels of controversy. Because of real differences between samples, it can be difficult for one lab to validate the results of another. In this work, a suite of seven crude oil samples, including two with recognized asphaltene problems and a sequence of three hydrotreater product fluids, have been selected for comparative testing by relatively simple techniques at ambient conditions. The onset of flocculation in response to addition of heptane was identified in batch mode by microscopic observation with the onset solubility conditions calculated from refractive index measurements. These were compared to continuous heptane titrations of toluene solutions of oil with an optical detection system. At essentially infinite dilution, solubility parameter can be calculated from the known properties of toluene and heptane. Further characterization of some asphaltene fractions was provided by measurements of the amount of precipitate, by FTIR, and by elemental analysis. The results demonstrate similarities and differences in the properties measured by these different techniques and help to highlight some of the difficulties of such comparisons of asphaltenes and their stability.     

Effect of scale and corrosion inhibitors on well productivity in reservoirs containing asphaltenes

During oil production from several wells in Arabian Gulf area, significant productivity decline was noticed. One of the reasons behind the productivity decline might be asphaltene precipitation. Production data of the particular wells were collected and analyzed. It was found that many of these wells were injected with scale and corrosion inhibitors in downhole and surface equipment. Thus, it was desired to investigate the potential of formation damage due to asphaltene in the presence of scale and corrosion inhibitors as field chemicals. The effect of asphaltenes on the wettability, surface, and interfacial tensions were measured in the presence of scale and corrosion inhibitors. It was observed that the scale inhibitor did not indicate any alteration of the wettability, while the presence of corrosion inhibitor indicates high potential for wettability change into oil-wet conditions especially in the presence of asphaltenic oil. Similar results were obtained from the measurements of surface and interfacial tensions, in which corrosion inhibitors showed a significant decrease in surface and interfacial tensions. To assess the potential of asphaltene precipitation in the presence of both inhibitors and to study the effect of asphaltenes on the oil productivity, flooding experiments were carried out and oil/water relative permeability was determined.The results of flooding displacements showed that the presence of scale inhibitors indicates no effect on the oil/water relative permeability even in the presence of asphaltenes, while a significant decrease in oil relative permeability associated with an increase of residual oil saturation was observed in the presence of corrosion inhibitors.Mixture of scale and corrosion inhibitors showed no effect on relative permeability curves.