Heavy Oil Research Articles

Numerical Simulation Study on Flue Gas-Assisted Steam Huff and Puff in Heavy Oil Reservoirs.

In response to challenges such as the rapid rise of water content, the rapid decline of periodic production, and the serious intrusion of edge and bottom water in heavy oil reservoirs after multicycle profile control, the flue gas-assisted steam huff and puff technology is proposed. By focusing on Block Cao128 in the L Oilfield as a research subject, the feasibility of applying the flue gas-assisted steam huff and puff technology in heavy oil reservoirs has been verified through the establishment of a three-dimensional geological model. Additionally, the injection and production parameters in steam huff and puff have been optimized. The research results indicate that when the cyclic steam injection volume is 1000 t, the maximum net oil increment can be achieved, reaching 6308 × 104 t. Furthermore, when the cyclic flue gas injection volume is 9 × 104 Nm3, the efficacy of the flue gas-assisted steam huff and puff is enhanced. The optimal injection method is to inject flue gas in the early stage of steam huff and puff, and the oil-gas ratio is increased to 1.77. The introduction of flue gas can enhance production significantly and exert a significant impact on early-stage production. The earlier the injection time of flue gas, the better the development effect. Flue gas-assisted steam huff and puff technology improves energy utilization efficiency and reduces pollutant emission. It has a significant positive impact on environmental protection and sustainable development.

Technology Progress in High-Frequency Electromagnetic In Situ Thermal Recovery of Heavy Oil and Its Prospects in Low-Carbon Situations

Heavy oil resources are abundant globally, holding immense development potential. However, conventional thermal recovery methods such as steam injection are plagued by high heat loss, substantial carbon emissions, and significant water consumption, making them incompatible with carbon reduction goals and the sustainable socioeconomic development demands. A new method of high-frequency electromagnetic in situ heating, which targets polar molecules, can convert electromagnetic energy into heat so as to achieve rapid volumetric heating of the reservoir. This method has the potential to overcome the drawbacks of traditional techniques. Nevertheless, it faces significant drawbacks such as limited heating range and inadequate energy supply during later production stages, which necessitates auxiliary enhancement measures. Various enhancement measures have been reported, including nitrogen injection, hydrocarbon solvent injection, or the use of nano-metal oxide injections. These methods are hindered by issues such as pure nitrogen being easy to breakthrough, high costs, and metal pollution. Through extensive literature review, this article charts the evolution of high-frequency electromagnetic in situ heating technology for heavy oil and the current understanding of the coupled heat and mass transfer mechanisms underlying this technology. Moreover, based on a profound analysis of the technology’s progression trends, this work introduces a new direction: CO2-N2 co-injection as an enhancement strategy for high-frequency electromagnetic in situ heavy oil recovery. There is promising potential for the development of new technologies in the future that combine high efficiency, low carbon emissions, environmental friendliness, economic viability, and energy conservation. Furthermore, some research prospects in low-carbon situations and challenges for the new technology in future are presented in detail. All in all, the contribution of the paper lies in the summarizing of some main drawbacks of current enhanced electromagnetic in situ thermal recovery methods, and presents a novel research direction of using CO2-N2 co-injection as an enhancement strategy based on its current research status in low-carbon situations.

Research on the Phase Behavior of Multi-Component Thermal-Fluid-Heavy Oil Systems

Multi-component thermal luid technology optimizes development effects and has a strong adaptability, providing a new choice for the efficient development of heavy oil reservoirs. However, due to the significant differences between the phase behavior of multi-component thermal-fluid-heavy oil systems and conventional systems, and the lack of targeted and large-scale research, key issues such as the phase behavior of these systems are unclear. This research studies the phase behavior and influencing factors of emulsions and foamy oil in a multi-component thermal-fluid-heavy oil system through high-temperature and high-pressure PVT experiments, revealing the characteristics of the system’s special phase behavior. In the heavy oil emulsion system, the water content directly affects changes in the system’s phase state. The higher the temperature, the larger the phase transition point, and the two are positively correlated. As the stirring speed increases, the phase transition point first increases and then decreases. The amount of dissolved gas is negatively correlated with the size of the phase transition point, and dissolution can form foamy oil. In the heavy oil–foamy oil system, the dissolution capacity of CO2 is greater than that of multi-component gases, which is greater than that of N2. A high water content and high temperature are not conducive to the dissolution of multi-component gases. While an increase in stirring speed is beneficial for the dissolution of gases, there are limitations to its enhancement ability. Therefore, the development of multi-component thermal fluids should avoid the phase transition point of emulsions and promote the dissolution of multi-component gases.

Efficiency analysis of the application of thermal methods at the Pirallahi and Darwin bank fields

The efficiency of oil and gas field development is associated with the correct choice of appropriate measures to be implemented. This research considers the Pirallahi and Darwin Bank fields with hard-to-recover oil reserves. The Pirallahi field is located in the eastern part of the Absheron Peninsula. The initial balance reserve for the facility is 4 million tons, and the level of reserve utilization is 19%. Among the notable features, the Pirallahi deposit represents the southern fold of the PK (Pre-Kirma- ki) horizon. Across the horizon, the initial balance reserve is approximately one million tons, and the utilization rate is 17%. In other groups, the level of utilization exceeds 20%. Accordingly, the volume of initial balance reserves ranges between 8-35 million tons. Industrially important objects here are KSv (Kirmaki suite, fifth horizon), KSn (Kirmaki suite, n horizon), and PKS (Post-Kirmaki suite). To develop oil reserves, more than 1000 production wells were drilled at different stages of the development process. The southern fold consists of a brachyanticline extending from northwest to southeast. The main tectonic element of the southern fold is its thrust nature and its very complex tectonic structure. The fold is heavily watered. Therefore, to increase the efficiency of developing these fields, it is necessary to use appropriate methods of influencing the formations. To enhance the efficiency of the development process in the northern part, the in-situ combustion method was applied. The Darwin Bank field belongs to the Absheron archipelago and has a tectonic brachyanticlinal structure. The structure is complicated by numerous longitudinal and transverse faults. It is divided into six tectonic zones by several transverse and one longitudinal fault passing through the crest. Darwin Bank oils are heavy oils with low sulfur content. In addition, low paraffin and high resin content are observed in the composition of field oil. For both fields, the recovery rate of geological reserves fluctuates around 30%. The article, primarily, examines the selection of objects and the use of enhanced oil recovery methods in these fields. The in-situ combustion method was used in the northern part of the Pirallahi field and Darwin Bank.

Salt Tolerance of Fungi and Prospects for Mycodiagnostics of Contamination in Saline Soils

The review is devoted to the analysis of the characteristics of salt-tolerant fungi in order to identify the possibility of their use for indicating chemical contamination of highly mineralized soils and the search for potential test species for laboratory mycotesting. A list of representatives of halophilic and halotolerant genera of micromycetes is given, which can serve as indicators of pollution by heavy metals, oil products and other toxicants against the background of increased mineralization of soil substrates. For biotesting of soils with an average level of mineralization, micromycetes belonging to moderate halotolerant species are proposed as promising. The morphological, physiological and molecular mechanisms of adaptation of halophilic and halotolerant fungi to conditions of increased salinity of habitats are analyzed. The effects on fungal communities, which are caused by a combination of salinity with chemical pollution of different nature, are considered. Methodological aspects of the practical use of salt-tolerant fungi for biodiagnostics of the degree of unfavourability of saline soils are considered: the composition of media, cultivation conditions, and test reactions of fungal cultures that are optimal for an adequate assessment of the degree of halotolerance of fungi and ecotoxicity of soil samples.

Characterizing hydrocarbon discoveries and prospects in the Tay Sandstone using relative elastic inversion: Greater Pilot area, Central North Sea

The Pilot oil accumulation and associated discoveries of Blocks 21/27 and 21/28 have been stranded assets for three decades. The principal cause of delay in developing the oil fields is because these are heavy oils with low gas–oil ratio and, in some cases, significant gas caps. The oil in the Tay Sandstone is trapped in structural and stratigraphic closures at a depth of 800–1300 m. Determining pay thickness and delimiting oil-in-place in some existing discoveries and especially in undrilled prospects has been problematic. This difficulty has been addressed by conducting an innovative amplitude versus offset (AVO) inversion of the seismic data which has been successfully blind tested against the wells and prognosed closures. The method, which is a band-limited form of extended elastic impedance (EEI), has proved robust for discriminating gas-, oil- and brine-filled sands from one another. Oil and gas trapped further down-dip in the discoveries Fyne, Crinan and Dandy are developed in Tay reservoirs showing generally lower net-to-gross. The sensitivity of the rEEI attribute to the presence of thicker intervals of oil pay, in this case, is used to indicate where higher net-to-gross is present above the oil–water contact, a characteristic of direct relevance to the planning of optimally located development wells.

Development of Nanofluid-Based Solvent as a Hybrid Technology for In-Situ Heavy Oil Upgrading During Cyclic Steam Stimulation Applications.

This paper evaluates solvent-based nanofluids for in situ heavy oil upgrading during cyclic steam stimulation (CSS) applications. The study includes a comprehensive analysis of the properties and characteristics of nanofluids, as well as their performance in in situ upgrading and oil recovery. The evaluation includes laboratory experiments to investigate the effects of the nanoparticle's chemical nature, asphaltene adsorption and gasification, heavy oil recovery, and quality upgrading. The results show that alumina-based nanoparticles have a higher efficiency in asphaltene adsorption and catalytic decomposition at low temperatures (<250 °C) than ceria and silica nanoparticles. Specifically, alumina nanoparticles achieved asphaltene adsorption of 48 mg g-1, while ceria adsorbed 42 mg g-1. Alumina and ceria required around 90 and 135 min for 100% asphaltene conversion. Nanofluids were designed by varying nanoparticle and surfactant concentrations dispersed in naphtha, obtaining that the nanofluid containing 0.05 wt % of nanoparticles and 0.05 wt % of surfactant presents the highest yield in increasing API gravity by 5° and reducing oil viscosity by 90% in thermal experiments. Finally, the nanofluid was evaluated under dynamic conditions. The results show that nanofluid-based solvents can significantly improve the recovery and upgrading of heavy oil during CSS applications. When the steam injection technology was assisted by naphtha and nanofluid, 64% and 75% of the original oil in place were recovered, respectively. The effluents obtained in each stage presented lower API gravity values and higher viscosities for those obtained without a nanofluid. Specifically, the API gravity of the recovered oil rose from 11.9° to 34°, and the viscosity decreased to below 100 cP. The paper concludes by highlighting the potential of nanofluid-based solvents as a promising technology for heavy oil recovery and upgrading in the future.

A comprehensive study of the enhanced oil recovery potential of low-salinity water in heavy oil sandstone reservoir

To determine the enhanced oil recovery potential of low-salinity brine for a heavy oil sandstone reservoir, a holistic approach including both experimental and theoretical studies was employed in this study. Macro-scale forced and spontaneous imbibition tests were performed to quantify the oil recovery potential by our considered three brines. Furthermore, micro-scale experiments, including FTIR (Fourier-Transform Infrared Spectroscopy), TGA (Thermogravimetric Analysis) and zeta potential, were executed to explore the micro-scale oil-brine-rock interactions (i.e., polar component desorption from the rock surface) that has controlled the macro-scale oil recovery efficiency. In addition, to further investigate the underlying physical mechanism that leads to the discrepancy in polar component desorption when subjected to different brines, charge-distribution multi-site complexation model (CD-MUSIC) and DLVO-based disjoining pressure calculation were performed to describe the molecular-level electrokinetic interactions at the oil-brine and rock-brine interfaces, as well as the total interaction force between these two interfaces. Our results show that the oil recovery efficiency of the low-salinity aquifer water (LSAW) was markedly higher than produced water (PW) and seawater (SW) from the forced and spontaneous imbibition tests. Combined with the marginal difference on interfacial tension (IFT) results, it guided us to conclude that the micro-scale oil-brine-rock interaction controlled the macro-scale oil recovery performance. FTIR and TGA experimental results on pristine quartz, oil aged quartz, as well as different water treated aged quartz powders revealed that the polar component desorption efficiency in different brines followed the order of LSAW > PW > SW, which was consistent with the macro-scale oil recovery trend. The total disjoining pressure result gave rise to the conclusion that the most repulsive disjoining pressure in LSAW leads to the most efficient desorption of polar oil component from the rock surface. In addition, the electrokinetic properties of the oil/brine and rock/brine interfaces, as well as the consequent electrical double layer force play a crucial role in differentiating the oil-brine-rock interactions in different brines. This study has shed light on the further application of low-salinity aquifer water in our target heavy oil reservoir.

In-situ hydrothermal upgrading and mechanism of heavy oil with nano-Fe2O3 in the porous media

Hydrothermal upgrading is a promising technology for heavy oil, yet the impact of reservoir conditions on the catalytic effect of catalysts and the pathway are not clear. In this study, the effect of the formation environment on the catalytic upgrading process was investigated through simulating the reservoir conditions (2000 mD permeability, 25 % porosity) for catalytic hydrothermal cracking of heavy oil. Under the hydrothermal upgrading conditions（240 ℃, 24 h, 50 wt%, 0.1 wt% nano-Fe2O3）, 9.15 % of the heavy component(5.1 % resin and 4.05 % asphaltene) was converted to light component. The content of hydrocarbons below C17 in the saturated fraction increased from 36.29 % to 59.85 %. The structure of the asphaltene was disrupted resulting in a lower level of asphaltene stacking, and NC/NH ratio increased 13.61 % compared to heavy oil. In addition, the reservoir condition with quartz as the supporting medium improved the catalytic ability of iron oxide nanoparticles. When injected into the reservoir medium, nano-size facilitated dispersion on the surface of the proppant and inhibited the aggregation of nanoparticles, which ensured the continuous operation of the active sites on the surface of the catalyst. Electron transfer of Fe2+/Fe3+ catalyzed the heterolytic cleavage of covalent bonds of H2O/heavy oil molecules was the mechanism for heavy oil upgrading. These findings demonstrated the feasibility of in-situ upgrading of heavy oil through the use of nano-catalysts under reservoir conditions.

Effect of biochar-based nano‑nickel catalyst on heavy crude oil upgrading and oil shale pyrolysis

This study involved the preparation of a biochar-based nano‑nickel (Ni/C) catalyst, achieving high dispersion of the nano‑nickel catalyst by utilizing waste coffee grounds as a biochar carrier. The Ni/C catalyst demonstrated commendable catalytic performance in heavy crude oil upgrading. Compared with the control group, the viscosity reduction rate of heavy crude oil was increased by 21.53 %, and the contents of heteroatoms, resins and asphaltenes were effectively reduced, while increasing the ratio of C2-C4 and saturated components. Additionally, the catalyst reduced the initial decomposition temperature and the maximum thermal decomposition rate temperature of oil shale by 10 °C and 8 °C, respectively. The results of DFT calculations also indicated that the catalyst effectively improved the pyrolysis activity of kerogen molecules. Noteworthy characteristics of the catalyst include its low cost, simple operation, and high catalytic activity, making it highly promising for broad applications in unconventional petroleum energy exploitation.

Roles of Catalysts and Feedstock in Optimizing the Performance of Heavy Fraction Conversion Processes: Fluid Catalytic Cracking and Ebullated Bed Vacuum Residue Hydrocracking

Petroleum refining has been, is still, and is expected to remain in the next decades the main source of energy required to drive transport for mankind. The demand for automotive and aviation fuels has urged refiners to search for ways to extract more light oil products per barrel of crude oil. The heavy oil conversion processes of ebullated bed vacuum residue hydrocracking (EBVRHC) and fluid catalytic cracking (FCC) can assist refiners in their aim to produce more transportation fuels and feeds for petrochemistry from a ton of petroleum. However, a good understanding of the roles of feed quality and catalyst characteristics is needed to optimize the performance of both heavy oil conversion processes. Three knowledge discovery database techniques—intercriteria and regression analyses, and artificial neural networks—were used to evaluate the performance of commercial FCC and EBVRHC in processing 19 different heavy oils. Seven diverse FCC catalysts were assessed using a cascade and parallel fresh catalyst addition system in an EBVRHC unit. It was found that the vacuum residue conversion in the EBVRHC depended on feed reactivity, which, calculated on the basis of pilot plant tests, varied by 16.4%; the content of vacuum residue (VR) in the mixed EBVRHC unit feed (each 10% fluctuation in VR content leads to an alteration in VR conversion of 1.6%); the reaction temperature (a 1 °C deviation in reaction temperature is associated with a 0.8% shift in VR conversion); and the liquid hourly space velocity (0.01 h-1 change of LHSV leads to 0.85% conversion alteration). The vacuum gas oil conversion in the FCC unit was determined to correlate with feed crackability, which, calculated on the basis of pilot plant tests, varied by 8.2%, and the catalyst ΔCoke (each 0.03% ΔCoke increase reduces FCC conversion by 1%), which was unveiled to depend on FCC feed density and equilibrium FCC micro-activity. The developed correlations can be used to optimize the performance of FCC and EBVRHC units by selecting the appropriate feed slate and catalyst.

Research on the Compounding Scheme of High-Efficiency and Environmentally Friendly Water-Based Well Cleaning Fluid and Analysis of Its Application Effect

In the process of oil well production, the deposition and enrichment of heavy oil and wax are common phenomena. The deposition of these high-viscosity organic substances will not only seriously affect the normal production of oil wells but also cause certain pollution to the environment. Traditional well-washing operations usually rely on high temperatures and strong cleaning chemicals, which have the problems of low cleaning efficiency at low temperatures and poor environmental protection. Therefore, it is particularly important to study a more efficient and environmentally friendly water-based well-washing fluid. At present, most oilfields in China use diesel or organic cleaning agents to clean oil wells, which not only increases the cost of well-washing operations but also may cause pollution to the environment. In response to this problem, the core of this study lies in its innovative compounding scheme. The scheme includes preferred alkaline components, surfactants, emulsifiers, and solubilizers, and introduces glass fiber cutting and erosion technology. This well-washing fluid can effectively remove wax and heavy oil attached to the well wall at a lower temperature, which not only improves cleaning ability but also greatly reduces the dependence on high temperature. The water-based well-washing fluid provided in this study is composed of water, alkaline substances, surfactants, emulsifiers, and glass fibers. Emulsifiers such as Tween 80, OP-20, and polyethers form a stable emulsification system to help disperse and encapsulate oil and grease particles.

Hydroxyl-Functionalized Carbon Nanoparticles Alter the Asphaltene Aggregate Structure and Reduce the Viscosity of Heavy Oil

Hydroxyl-Functionalized Carbon Nanoparticles Alter the Asphaltene Aggregate Structure and Reduce the Viscosity of Heavy Oil

Study the implication of different SiO2/Al2O3 ratios on the pore size and acidity of Beta zeolite and its catalytic pyrolysis mechanism of Kraft lignin

This study employed a one-step synthesis method to prepare Beta zeolites (BZs) with various SiO2/Al2O3 ratios and applied them as catalysts in the process of producing bio-oil from Kraft lignin (KL). The research investigated the changes in acidity and pore size of BZs under different SiO2/Al2O3 ratios and their impact on the catalytic pyrolysis products of KL. Characterization and a series of physicochemical analyses of BZ with different SiO2/Al2O3 ratios as well as catalytic pyrolysis products were carried out. The Pearson correlation coefficient was also used to correlate BZ SiO2/Al2O3 ratios and the acidity/pore size of BZ as well as the distribution of the products and the deoxygenation effect. The results indicate that BZs with different SiO2/Al2O3 ratios can effectively catalyze the upgrading of KL during pyrolysis. BZ with SiO2/Al2O3 ratios of 45 exhibited stronger acidity, a more prominent layered porous structure, and a more orderly distribution of mesopores. It showed the best catalytic upgrading effect on KL, achieving a product yield of 58.4 %. More prominently, the oxygen content is reduced to 14.19 % and the deoxygenation extent of the heavy oil reached 37.1 %.

Research for the Enhanced Oil Recovery Mechanism of Heavy Oil after Composite Huff and Puff Assisted by Edge-Bottom Water Displacement

Abstract In the late stage of exploiting heavy oil reservoirs with edge-bottom water, we are faced with problems such as high crude oil viscosity, channeling of bottom water, and rapid rise in water cut. To clarify the synergistic effect of N2, CO2, N2 foam, and viscosity reducer in water control and oil increase, and solve the problem of edge-bottom water rushing into production wells, one-dimensional sand-pack huff and puff experiments were carried out. First, the N2 foam huff and puff experiment evaluated the effect of N2 foam on controlling bottom water. Then the viscosity reducer assisted CO2 huff and puff experiment analyzed the synergistic viscosity reduction ability between the two to mobilize the remaining heavy oil. Next, the N2 foam-viscosity reducer-CO2 huff and puff experiment clarified the synergistic effect between the three. Finally, the N2 foam-viscosity reducer-CO2-N2 huff and puff experiment solved the problem of insufficient reservoir energy based on synergistic precipitation and oil increase. Experimental results show that N2 foam-viscosity reducer-CO2-N2 huff and puff is the optimal water control and oil increase solution. This solution can significantly reduce water production and increase oil production. In the one-dimensional sand-pack experiment, this technical solution reduced the water content by 68% and increased the recovery rate by 16.09%. The research results provide a reference for the development of exploitation technology schemes for similar edge-bottom water heavy oil reservoirs after entering high water cut.

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.

The Influencing Factors and Mechanism of Anionic and Zwitterionic Surfactant on Viscosity Reduction in Heavy O/W Emulsions.

The high viscosity of heavy crude oil has been an obstacle to its safe production and economic transportation. In this work, a screened emulsified viscosity reducer system is conducted. Experimental results demonstrate that the most effective viscosity reducing agent comprises sodium oleate (NaOl) and cocamidopropyl betaine (CAB-35) in a ratio of 1:2, achieving a viscosity reduction rate of 94.65%. Additionally, the interfacial tension between oil and water decreases from 27 to 4 mN/m with 0.1 mass % TEOA and NaOH in a 1:1 ratio. The oil droplet size is uniformly distributed with D mean is 14 μm and D 50 is 11 μm. Droplets flocculate as the salinity increases to 0.2 mol/L, which corresponds to the apparent increase of viscosity. The adsorption of long alkyl chain lipophilic groups on surfactant molecules at the oil-water interface and the water film alters the wettability of pipe steel to water-wet, further enhancing the application of emulsification and viscosity reduction effects. The primary mechanism behind the viscosity reduction in emulsification is attributed to strong electrostatic interactions stemming from molecular electrostatic potential distributions.

Viscometric studies of heavy oil in the presence of compositions consisting of amphiphilic compounds and organic solvents

The chemical composition of high-viscosity heavy oil has been studied by IR spectroscopy and X-ray fluorescence spectrometry. It is found that characteristic absorption bands are available and characterize aliphatic structures and aromatic cycles, sulfur- and organophosphorus compounds, and the presence of compounds containing heteroatoms P, V, Ca, Pd, Ni, Ru, Mo, Fe, Cu and Zn in its composition is found. The method of rotational viscometry has established the Newtonian nature of the oil flow in the studied range of the velocity up to 300 s–1. At the same time, according to the densitometry results (ρ = 0.954 g/cm3 ), studied heavy oil belongs to the bituminous type characterized by a complex rheological behavior under long- and high-term deformation conditions. In order to regulate the studied oil viscosity properties, composite additives based on amphiphilic reagents of cationic and amphoteric type and organic solvents have been developed, their influence on dynamic and kinematic viscosity has been examined. It has been established that compositions with surfactants simultaneously containing a large amount of amino and phosphate groups dissolved in a non-polar aromatic solvent (toluene) or an organic mixture (catalytic reforming gasoline) have a maximum modifying effect of the colloidal structure of bituminous oil. The interaction of functional groups of amphiphilic reagents with oil heteroatoms leads to the dispersion of resinous-asphaltene substances, a decrease in the structural and mechanical strength of the system, an increase in the molecular mobility of aggregates, which results in improving the investigated oil quality and viscosity characteristics by 7.0 and 12.6 % according to the composition efficiency index.

Study on organic carbon in medium-low mature shale oil reservoirs rich in type II kerogen: Oxidation behavior, thermal effect, and kinetics

In-situ combustion technology (ISC) was a potential technology for efficient development of medium–low maturity shale oil reservoirs. Clarifying the exothermic behavior of organic carbon oxidation will be beneficial for better control of ISC processes. In this work, the organic carbon composition, type II kerogen and residual oil, were separated and extracted from the shale samples of typical medium–low maturity shale oil reservoirs in the Ordos Basin, China. The synchronous thermal analyzer and mass spectrometry (STA-MS), Fourier transform infrared spectroscopy (FTIR), and ROCK-EVAL VI were used to study the products, heat release, and functional group changes of type II kerogen, residual oil, and shale during the oxidation process. The results indicated that the oxidation heat release of shale mainly came from the oxidation reaction between its residual oil and type II kerogen, but the oxidation heat release range of shale was relatively lagging compared to the single residual oil or type II kerogen affected by rock debris. Secondly, under atmospheric pressure, the type II kerogen experiences obviously higher heat release than residual oil and heavy oil, indicating its superior potential of in-situ heat release. In addition, the major productions that CO, H2O, SO2, and CO2 were quantitatively characterized, with CO2 having the highest production of 882.25 mg/g. Furthermore, combined with the molecular weight, an oxidation reaction equation of type II kerogen was constructed. Finally, the oxidation kinetics parameters of type II kerogen, residual oil, and shale were determined using Friedman and Ozawa-Flynn-Wall (OFW) models. It was found that the activation energy of shale was higher than II kerogen and residual in low temperature oxidation (LTO) and fuel deposition (FD) stages. This may be due to the joint reaction between kerogen and residual oil, thus exacerbating the challenge of shale in-situ ignition. However, due to the catalytic effect of rock debris, the activation energy of shale was lower than LTO in high temperature oxidation (HTO) stage, indicating that once fuel deposition was completed, organic carbon will undergo stable combustion. This study has theoretical guidance for the numerical simulation research of ISC development technology of maturity-low shale oil reservoirs.

Efficacy of Foldable Capsular Vitreous Body Implants Filled With Light or Heavy Silicone Oil in the Treatment of Silicone Oil-dependent Eyes.

The purpose of this study was to compare the clinical efficacy of foldable capsular vitreous body (FCVB) filled with either light or heavy silicone oil and the incidence of complications after their implantation for the treatment of severe ocular trauma and silicone oil-dependent eyes. FCVB filled with either light (n = 16) or heavy (n = 8) silicone oil was implanted in 24 patients. During the 12-month follow-up period, the intraocular pressure, final best-corrected visual acuity, retinal reattachment condition, position of the FCVB, and complications were assessed. All surgeries were performed without issue. There was no significant difference in preoperative and postoperative best-corrected visual acuity between the two groups. A significant improvement in the intraocular pressure was observed after surgery in both the light silicone oil (P = 0.029) and heavy silicone oil (P = 0.035) groups. None of the patients developed displacement or prolapse of the FCVB. The most common early and late postoperative complications were postoperative hemorrhage (33.3%) and corneal opacification (50%), respectively. FCVB filled with heavy silicone oil can be used as a supplemental therapy for patients who have lost the anterior segment of their eye, have lesions of the inferior retina, or cannot maintain the prone position for various reasons. Implantation of FCVB combined with heavy silicone oil compensates for the shortcomings of this with light silicone oil, providing patients with more personalized treatment.