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"HEAVY OIL"
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Upgrading oilsands bitumen and heavy oil
\"The high demand for quality petroleum products necessitates ongoing innovation in the science and engineering underlying oilsands extraction and upgrading. Beginning with a thorough grounding in the composition, fluid properties, reaction behaviour, and conomics of bitumen and heavy oil, Murray Gray then delves into current processing technologies, particularly those used at full commercial scale. The tables of data on composition, yield, and behaviour of oilsands bitumen and heavy oil fractions are extensive. Though the focus is on bitumen from Alberta's oilsands-the largest resource in the world-the science applies to upgrading of heavy oil and petroleum residue feeds worldwide. Upgrading Oilsands Bitumen and Heavy Oil lays out the current best practice for engineers and scientists in the oilsands and refining industries, government personnel, academics, and students.\"-- Provided by publisher.
Book
Upgrading Oilsands Bitumen and Heavy Oil
\"The emphasis throughout is to link the fundamentals of the molecules through to the economic drivers for the industry, because this combination determines the technology used for processing.\"-From the Introduction The high demand for quality petroleum products necessitates ongoing innovation in the science and engineering underlying oilsands extraction and upgrading. Beginning with a thorough grounding in the composition, fluid properties, reaction behaviour, and economics of bitumen and heavy oil, Murray Gray then delves into current processing technologies, particularly those used at full commercial scale. The tables of data on composition, yield, and behaviour of oilsands bitumen and heavy oil fractions are extensive. Though the focus is on bitumen from Alberta's oilsands-the largest resource in the world-the science applies to upgrading of heavy oil and petroleum residue feeds worldwide. Upgrading Oilsands Bitumen and Heavy Oil lays out the current best practice for engineers and scientists in the oilsands and refining industries, government personnel, academics, and students.
eBook
Study on the kinetics of formation process of emulsion of heavy oil and its functional group components
Enhanced oil recovery (EOR) by in situ formation of oil-in-water emulsion in heavy oil cold production technology has received growing interest from the petroleum industry. We present an experimental study of emulsification of model oils prepared by heavy oil and its functional group compositions dissolved into toluene brought into contact with a surfactant solution. The effects of functional group composition, emulsifier concentration, temperature, pH and stirring speed on the emulsification rate of heavy oil was investigated. A second-order kinetic model characterizing the temporal variation of conductivity during the emulsification has been established. The results show that acidic and amphoteric fractions exhibit higher interfacial activity, larger emulsification rate constant and faster emulsification rate. With the increase of emulsifier concentration, the emulsification rate constant increase to the maximum value at a concentration of 0.05 mol/L before decreasing. Temperature increase benefits the emulsification rate and the activation energy of the emulsification process is 40.28 kJ/mol. Higher pH and stirring speed indicate faster emulsification rate. The heterogeneity of emulsions limits the accuracy of dynamic characterization of the emulsification process and the determination method of emulsification rate has always been controversial. The conductivity method we proposed can effectively evaluates the emulsification kinetics. This paper provides theoretical guidance for an in-depth understanding of the mechanism and application of cold recovery technology for heavy oil.
Journal Article
Prediction Model for the Viscosity of Heavy Oil Diluted with Light Oil Using Machine Learning Techniques
Due to the presence of asphaltene, the flow assurance of high viscosity crude oil becomes more challenging and costly to produce in wellbores and pipelines. One of the most effective ways to reduce viscosity is to blend heavy oil with light oil. However, the viscosity measurement of diluted heavy crude is either time-consuming or inaccurate. This work aims to develop a more accurate viscosity model of diluted heavy crude based on machine learning techniques. A multilayer neural network is used to predict the viscosity of heavy oil diluted with lighter oil. The input data used in the training include temperature, light oil viscosity, heavy oil viscosity, and dilution ratio. In this modeling process, 156 datasets were retrieved from the available iterature of various heavy-oil fields in China. Part of the data (80%) is used to train the developed models using Adam optimizer algorithms, while the other part of the data (20%) is used to predict the viscosity of heavy oil diluted with lighter. The performance and accuracy of the machine learning models were tested and compared with the existing viscosity models. It was found that the new model can predict the viscosity of diluted heavy oil with higher accuracy, and it performs better than other models. The absolute average relative error is 10.44%, the standard deviation of the relative error is 8.45%, and the coefficient of determination is R2 = 0.95. The viscosity predicted by the neural network outperformed existing correlations by the statistical analysis used for the datasets available in the literature. Therefore, the method proposed in this paper can better estimate the viscosity of diluted heavy crude oil and has important promotion value.
Journal Article
Crude Oil Pyrolysis Studies: Application to In Situ Superheat Steam Enhanced Oil Recovery
This work focuses on the occurrence and composition of flammable pyrolysis gases which can be expected from stimulation of heavy oil with superheat steam. These gases can have commodity value or be used to fire a conventional boiler to generate steam vapor for superheater feed. Seven oil samples taken from different US locations were tested via thermogravimetric analysis (TGA) with off-gas analysis of light hydrocarbons via mass spectrometry (MS). The samples were heated up to 500 °C at 5 °C/min in a gas flow of moist carbon dioxide and held at 500 °C until no further mass loss was noted. Then, carbonaceous residue was exposed to air at 500 °C to determine enthalpy of combustion by differential scanning calorimetry (DSC). To demonstrate that pyrolysis was indeed occurring and not simple de-volatilization, a high-molecular-weight reagent-grade organic molecule, lactose, was first demonstrated to produce components of interest. After treatment under moist CO2 at 500 °C, all samples were found to lose around 90% of mass, and the follow-up combustion process with air further reduced the residual mass to between 2% and 12%, which is presumed to be mineral matter and char. The light hydrocarbons methane, ethane, and propane, as well as hydrogen, were detected through MS during pyrolysis of each oil sample. Heavier hydrocarbons were not monitored but are assumed to have evolved, especially during periods where additional mass loss was occurring in the isothermal process, with minimal light hydrocarbon evolution. These results correspond to a possible concept of subsequent in situ combustion drive with or without heat scavenging following high-temperature pyrolysis from in situ superheat steam injection.
Journal Article
Solvent Exsolution and Liberation from Different Heavy Oil–Solvent Systems in Bulk Phases and Porous Media: A Comparison Study
In this paper, experimental and numerical studies were conducted to differentiate solvent exsolution and liberation processes from different heavy oil–solvent systems in bulk phases and porous media. Experimentally, two series of constant-composition-expansion (CCE) tests in a PVT cell and differential fluid production (DFP) tests in a sandpacked model were performed and compared in the heavy oil–CO2, heavy oil–CH4, and heavy oil–C3H8 systems. The experimental results showed that the solvent exsolution from each heavy oil–solvent system in the porous media occurred at a higher pressure. The measured bubble-nucleation pressures (Pn) of the heavy oil–CO2 system, heavy oil–CH4 system, and heavy oil–C3H8 system in the porous media were 0.24 MPa, 0.90 MPa, and 0.02 MPa higher than those in the bulk phases, respectively. In addition, the nucleation of CH4 bubbles was found to be more instantaneous than that of CO2 or C3H8 bubbles. Numerically, a robust kinetic reaction model in the commercial CMG-STARS module was utilized to simulate the gas exsolution and liberation processes of the CCE and DFP tests. The respective reaction frequency factors for gas exsolution (rffe) and liberation (rffl) were obtained in the numerical simulations. Higher values of rffe were found for the tests in the porous media in comparison with those in the bulk phases, suggesting that the presence of the porous media facilitated the gas exsolution. The magnitudes of rffe for the three different heavy oil–solvent systems followed the order of CO2 > CH4 > C3H8 in the bulk phases and CH4 > CO2 > C3H8 in the porous media. Hence, CO2 was exsolved from the heavy oil most readily in the bulk phases, whereas CH4 was exsolved from the heavy oil most easily in the porous media. Among the three solvents, CH4 was also found most difficult to be liberated from the heavy oil in the DFP test with the lowest rffl of 0.00019 min−1. This study indicates that foamy-oil evolution processes in the heavy oil reservoirs are rather different from those observed from the bulk-phase tests, such as the PVT tests.
Journal Article
Visualization of Chemical Heavy Oil EOR Displacement Mechanisms in a 2D System
This study aims to develop a visual understanding of the macro-displacement mechanisms associated with heavy oil recovery by water and chemical flooding in a 2D system. The sweep efficiency improvements by water, surfactant, polymer, and surfactant-polymer (SP) were evaluated in a Hele-Shaw cell with no local pore-level trapping of fluids. The results demonstrated that displacement performance is highly correlated to the mobility ratio between the fluids. Surfactant and water reached similar oil recovery values at similar mobility ratios; however, they exhibited different flow patterns in the 2D system—reductions in IFT can lead to the formation of emulsions and alter flow pathways, but in the absence of porous media these do not lead to significant improvements in oil recovery. Polymer flooding displayed a more stable front and a higher reduction in viscous fingering. Oil recovery by SP was achieved mostly by polymer rather than due to the effect of the surfactant. The surfactant in the SP slug washed out residual oil in the swept zone without increasing the swept area. This shows the impact of the surfactant on reducing the oil saturation in water-swept zones, but the overall oil recovery was still controlled by the injection of polymer. This study provides insight into the fluid flow behavior in diverging flow paths, as opposed to linear core floods that have limited pathways. The visualization of bulk liquid interactions between different types of injection fluids and oil in the Hele-Shaw cell might assist in the screening process for new chemicals and aid in testing the production process.
Journal Article
In-situ upgrading of Egyptian heavy crude oil using matrix polymer carboxyl methyl cellulose/silicate graphene oxide nanocomposites
This study delves into catalytic aquathermolysis to enhance the economic viability of heavy oil production by in-situ upgrading technique. It is known that introducing nanocatalysts would promote the aquathermolysis reaction. Therefore, in this study, the effect of matrix polymer carboxyl methyl cellulose/silicate graphene oxide nanocomposites (CSG1 and CSG2) in the catalytic aquathermolysis of Egyptian heavy crude oil was studied. Characterization techniques including Fourier-transform infrared (FTIR), X-ray diffraction (XRD), Dynamic light scattering (DLS), Brunauer–Emmett–Teller (BET) surface area analysis, Scanning electron microscopy (SEM), and thermogravimetric analysis (TGA) were used to evaluate the structure of the synthesized nanocomposites. Results reveal CSG2 has higher crystallinity and superior dispersion compared to CSG1, and both exhibited a good stability in aqueous suspensions. CSG2 enriched with graphene oxide, demonstrates superior thermal stability, suitable for high-temperature applications such as catalytic aquathermolysis process. Single factor and orthogonal tests were used to assess the catalytic aquathermolysis performance of the prepared nanoparticles. The obtained results revealed that the optimum conditions to use CSG1 and CSG2 are 40% water concentration, 225 °C temperature, and 0.5 wt% catalyst percentage. Where, CSG2 showed better viscosity reduction (82%) compared to CSG1 (62%), highlighting its superior performance in reducing the viscosity of heavy oil. Numerical results from SARA analysis, gas chromatography, and rheological testing confirmed the catalytic aquathermolysis's efficacy in targeting asphaltene macromolecules and producing lighter hydrocarbon fractions.
Journal Article
Experimental Study on Enhanced Oil Recovery of Shallow Super-Heavy Oil in the Late Stage of the Multi-Cycle Huff and Puff Process
The shallow, thin super-heavy oil reservoir demonstrates certain characteristics, such as shallow reservoir depths, low-formation temperature, and high crude oil viscosity at reservoir temperatures. In the current production process, the central area of P601 is undergoing high-frequency huff and puff operations, facing certain problems such as decreasing production, low recovery rates, and rapid depletion of formation pressure. Through physical simulation experiments, the various elements of HDNS-enhanced oil recovery technology were analyzed. Nitrogen plus an oil-soluble viscosity reducer can improve the thermal recovery and development effect of super-heavy oil. With the addition of the viscosity-reducing slug, the recovery rate of steam flooding was 58.61%, which was 23.32% higher than that of pure steam flooding; after adding the 0.8 PV nitrogen slug, the recovery rate increased to 76.48%. With the increased nitrogen injection dosage, the water breakthrough time was extended, the water cut decreased, and the recovery rate increased. Nitrogen also plays a role in profile control and plugging within the reservoir; this function can effectively increase the heating range, increase steam sweep efficiency, and reduce water cut. So, the synergistic effects of steam, nitrogen, and viscosity-reducing agents are good. This technology enhances the development of shallow-layer heavy oil reservoirs, and subsequent development technologies are being compared and studied to ensure the sustainable development of super-heavy oil reservoirs.
Journal Article
Research on the Mechanism and Characteristics of Gel–Microbial Composite Oil Displacement in Hypertonic Heavy Oil Reservoirs
To address the limitations of traditional chemical flooding—such as high cost, environmental impact, and formation damage—and the challenges of standalone microbial flooding—including preferential channeling, microbial loss, and limited sweep efficiency—this study develops a novel composite system for a high-permeability heavy oil reservoir. The system integrates a 3% scleroglucan + 1% phenolic resin gel (ICRG) with Bacillus licheniformis (ZY-1) and a surfactant. Core flooding and two-dimensional physical simulation experiments reveal a synergistic mechanism: The robust and biocompatible ICRG gel effectively plugs dominant flow paths, increasing displacement pressure fourfold to divert subsequent fluids. The injected strain ZY-1 then metabolizes hydrocarbons, producing biosurfactants that reduce oil–water interfacial tension by 61.9% and crude oil viscosity by 65%, thereby enhancing oil mobility. This combined approach of conformance control and enhanced oil displacement resulted in a significant increase in ultimate oil recovery, achieving 15% and 20% in one-dimensional and two-dimensional models, respectively, demonstrating its substantial potential for improving heavy oil production.
Journal Article