Search Results (408)

To address high-temperature stability demands and promote resource utilization, this study investigates coal–oil co-processing residue (COCR) as an asphalt modifier. Penetration, softening point, ductility, rheological, and aging/storage evaluations were conducted on asphalt with varying COCR contents. Modification mechanisms were analyzed using FTIR, GPC, and SARA fractionation. The results revealed that COCR significantly enhanced high-temperature performance while slightly reducing low-temperature performance, showing good storage stability. At a 10% COCR content, the rutting factors of 70# and 90# asphalt increased by 44.8% and 46.2%, respectively, at 52 °C. Increased asphaltene content indicated that COCR reinforced the colloidal structure, thus improving the deformation resistance. At a 15% COCR content in mixture, the dynamic stability of asphalt mixtures increased by approximately 53.5% and 59.7% for 70# and 90# base asphalt, respectively. Considering overall performance balance, 10% COCR in 90# base asphalt would be recommended for regions with hot summers and warm winters. Full article

This study presents a risk assessment of asphaltene–resin–paraffin deposition (ARPD) in the producing formations of the XIII reservoir unit of the Uzen oil field at a late stage of development. The crude oil is characterized by an extremely high paraffin (wax) content of up to 29 wt.%. Long-term operation of the reservoir pressure maintenance (RPM) system with cold water injection has resulted in significant reservoir cooling, with temperatures declining from the initial 60–65 °C to 20–30 °C in zones of intensive waterflooding. To refine the critical phase transition temperatures of paraffin components, a dynamic laboratory approach was applied using a Wax Flow Loop system, which simulates wax deposition processes under flowing conditions. The results indicate that the wax appearance temperature (WAT) ranges from 41.0 to 44.0 °C, significantly exceeding the current bottomhole temperatures in the cooled zones of the reservoir. Intensive bulk crystallization of paraffins occurs within the temperature interval of 33.5–35.0 °C, while loss of oil flowability is observed at 25–34 °C, corresponding to the gelation and structural network formation of wax crystals under reduced thermal conditions. The obtained results confirm the inevitability of bulk oil structuring and solid wax phase precipitation directly within the reservoir porous medium. This process leads to blockage of low-permeability interlayers, deterioration of filtration properties, and a reduction in the displacement efficiency factor by 20–35%. Under the current thermal regime, ARPD should therefore be considered not merely as an operational flow assurance issue, but as a systemic factor limiting reservoir development efficiency. The research results substantiate the need to transition from reactive ARPD removal methods to proactive management of the thermal regime of the reservoir and wells, as well as to the differentiated application of thermal and chemical treatment methods. Full article

Heavy oil and extra-heavy oil represent mobility-limited petroleum resources because supramolecular associations of asphaltenes and resins, together with strong interfacial resistance, generate extremely high apparent viscosity. In recent years, nanotechnology has emerged as a promising approach for viscosity management and enhanced oil recovery (EOR). This review critically examines recent advances in nano-assisted viscosity reduction from a reservoir-operational perspective and organizes the literature into two field-relevant categories: metal-based and non-metal nano-systems. Metal-based nanoparticles (NPs) mainly promote catalytic aquathermolysis and related bond-cleavage and hydrogen-transfer reactions under hydrothermal conditions, enabling partial upgrading and persistent viscosity reduction during thermal recovery. In contrast, non-metal nano-systems—particularly silica- and graphene-oxide-derived materials—primarily operate through interfacial and structural regulation mechanisms at low or moderate temperatures. These effects include wettability alteration, interfacial-film stabilization, modification of asphaltene aggregation behavior, and the formation of dispersed-flow regimes such as Pickering-type emulsions that reduce apparent flow resistance in multiphase systems. Beyond summarizing nanomaterial types, this review emphasizes reservoir-scale considerations governing field applicability, including brine stability, NPs transport and retention in porous media, and formulation compatibility. Comparative analysis highlights the distinct operational windows of thermal catalytic nano-systems and cold-production nano-systems, providing a reservoir-oriented framework for designing nano-assisted viscosity-reduction technologies. Full article

The presence of source rock with a high concentration of kerogen is not a sufficient condition for petroleum formation, as maturation requires specific thermodynamic conditions. In this study, the artificial maturation of organic matter was investigated through hydrothermal treatment simulating the vaporization–condensation zones associated with in situ combustion and steam-assisted recovery processes. The experiments were conducted under an inert nitrogen atmosphere at 250–350 °C to reproduce oxygen-depleted thermal environments where hydrothermal reactions dominate. The results demonstrate that the bitumoid yield increases with temperature, reaching a maximum of 4.44 wt.% at 300 °C, followed by a decline at 350 °C due to secondary cracking. At the same time, gas generation increases significantly, with a more than five-fold rise in total gas yield between 250 and 350 °C. In parallel, the H/C atomic ratio of kerogen decreases from 1.17 in the initial sample to 0.52 at 350 °C, indicating progressive aromatization and advanced catagenetic transformation. These changes are accompanied by the conversion of high-molecular-weight kerogen into resins, asphaltenes, and subsequently lighter hydrocarbons. The study provides experimental evidence for the effectiveness of hydrothermal processes in inducing kerogen transformation under inert conditions, offering insights into the mechanisms governing artificial maturation in unconventional reservoirs. Full article

High-viscosity reservoirs are widely distributed across various countries with abundant reserves. However, their high resin and asphaltene content leads to elevated oil viscosity and low recovery rates. Conventional chemical flooding techniques are unsuitable for the development of such high-viscosity oilfields. Chemical viscosity reduction technologies face challenges such as low viscosity reduction efficiency, poor economic feasibility, and unclear mechanisms. Microbial-assisted chemical viscosity reduction represents a relatively novel approach. This study systematically investigated the enhanced oil recovery performance of a microbial-assisted chemical viscosity reducer. The results demonstrated that this microbial-assisted chemical viscosity reducer achieved a viscosity reduction rate exceeding 85% for five different crude oil samples. It effectively altered the wettability of oil-wet surfaces, improved the oil film stripping rate by 50–65% compared to pure chemical flooding agents, and achieved ultra-low oil–water interfacial tension on the order of 10⁻³ mN/m with crude oil, leading to an enhanced oil recovery (EOR) enhancement of 22–26%. The underlying mechanism is that viscosity-reducing bacteria degrade asphaltene in heavy oil, thereby weakening intermolecular forces. Their metabolites enhance the emulsion stability of the chemical viscosity reduction process. Chemical viscosity reducers enhance the physiological cycle and metabolic activity of microorganisms while also emulsifying and dispersing heavy oil and improving emulsion stability. Therefore, this novel microbial-assisted chemical viscosity reduction technology offers a new and effective EOR method for high-viscosity reservoirs. Full article

Extended-solvent steam-assisted gravity drainage (ES-SAGD) has emerged as a promising advancement over conventional SAGD for improving the efficiency and sustainability of in situ heavy oil and bitumen recovery. By co-injecting light hydrocarbon or alternative solvents with steam, ES-SAGD integrates thermal and compositional mechanisms to reduce viscosity, accelerate chamber development, and reduce steam–oil ratios. This review synthesizes the current state of knowledge on ES-SAGD, encompassing fundamental transport mechanisms, solvent selection and phase behavior, mass transfer dynamics, laboratory and physical modeling studies, numerical simulation approaches, and field-scale operational experiences. Experimental evidence consistently demonstrates substantial mobility enhancement through solvent-induced dilution, while compositional thermal simulations highlight an improved sweep efficiency and reduced energy intensity relative to steam-only processes. Field pilots further validate accelerated early-time production and significant steam savings, though challenges related to solvent retention, asphaltene stability, and reservoir heterogeneity persist. Key research gaps are identified in solvent transport prediction, formation damage risk, long-term solvent recovery, and integrated economic–environmental optimization. Overall, ES-SAGD offers a viable pathway toward lower-emission, higher-efficiency bitumen production, provided that solvent chemistry, reservoir complexity, and operational controls are carefully managed through continued research and targeted field deployment. Full article

Many advances in enhanced oil recovery (EOR) take advantage of the unique properties of nanomaterials to improve characterization of formation properties, achieve conformance control during flood operations, and extend the controlled release time of polymers. Magnetite nanoparticles (nMag) have been employed in these processes due to their low cost, low toxicity, and ability to be engineered to meet desired needs, especially with the application of a magnetic field. Similarly, silica dioxide (SiO₂) and aluminum oxide (Al₂O₃) nanoparticles have been evaluated for the delivery of scale and asphaltene inhibitors. However, the injection of nanoparticles into porous media comes with the risk of formation damage due to particle deposition, which can lead to increased injection pressures and reductions in permeability. The goal of this study was to develop a method to evaluate and assess nanoparticle formulations for their potential to cause formation damage. A screening apparatus was constructed to hold small sandstone discs (~2 mm) or cores (~2.5 cm) for rapid testing with minimal material use and the capability to be used with either aqueous brine solutions or non-polar solvents as the mobile phase. Image analysis of the disc and pressure measurements demonstrated increasing deposition of nMag and face-caking when the salinity was increased from 500 mg/L NaCl (8.56 mM) to API brine (2.0 M). Similarly, when the injected concentration of silica nanoparticles in 500 mg/L NaCl was increased from 1 to 10 wt%, the back pressure increased by 55 psi, and face-caking was observed. The screening test results were consistent with traditional core-flood tests and was able to be modified to accommodate organic liquid mobile phases. The screening test results closely matched nanoparticle transport and retention measured in sandstone cores, confirming the ability of the system to rapidly screen nanoparticle formulations for potential formation damage. Full article

Leveraging fungal consortia to degrade heavy oil is an emerging strategy for mitigating/cleaning up environmental pollution. However, many consortia are predominantly evaluated by measuring the biodegradation efficiency of heavy oil, with insufficient attention paid to the mechanistic underpinnings and metabolic pathways. In this study, heavy oil-degrading fungal consortia were developed for potential application in soil bioremediation. Whole-genome sequencing was used to predict the metabolic pathways and interspecific interactions driving heavy oil biodegradation. Three heavy oil-degrading fungal strains, designated Aspergillus corrugatus FH2, Aspergillus terreus FL4, and Alternaria alstroemeriae FW1, were isolated from oil sludge in the Karamay Oilfield in Xinjiang, China. Four consortia were constructed through the combination of two or three strains. The consortium F13 (FH2 + FW1) achieved 72.0% removal of heavy oil in a simulated bioremediation test over 30 days, which was more efficient than other consortia and single strains (59.5–68.5%). Notably, the mean degradation rate of long-chain alkanes (C₂₄–C₂₈) by F13 reached 95.9%. After F13 treatment, the major fractions of heavy oil showed considerable degradation, 87.4% for saturates, 92.0% for aromatics, 69.5% for resins, and 27.3% for asphaltenes. Genome annotation of FH2, FL4, and FW1 revealed the presence of core genes for degradation of n-alkanes and aromatics, e.g., CYP505, frmA, fadB, hmgA, ALDH, and ACSL. These functional genes encoded cross-lineage enzymes, enabling synergistic catabolism of C₁₃–C₂₈ alkanes and aromatics. Our findings indicated that the fungal consortium of A. corrugatus FH2 and Al. alstroemeriae FW1 has remarkable bioremediation potential for heavy oil-contaminated sites. This study provides molecular evidence for the design of targeted interventions to improve soil remediation efficiency with fungal consortia. Full article

This study is devoted to a comparative analysis of modern methods for determining the wax crystallization onset temperature (WCOT) of high-paraffin crude oil from the Uzen field. The objects of investigation were crude oil samples from the 13th reservoir horizon with a paraffin mass content ranging from 22.5% to 27.5%. For the first time in the practice of the oil and gas industry of Kazakhstan, a comprehensive comparison of results obtained using two fundamentally different approaches was performed: the light transmittance method using the KING-UNNP-70 apparatus, which simulates reservoir conditions (pressure of 12 MPa), and a dynamic method using a Wax Flow Loop facility, which reproduces crude oil flow in a pipeline. The experimental results showed that the light transmittance method detects the appearance of the first microcrystals at temperatures of 38.0–41.7 °C, whereas the dynamic method yields higher WCOT values, ranging from 41.0 °C to 44.0 °C. It was also found that the temperature of bulk crystallization, characterizing intensive solid phase formation, lies within the range of 33.5–35.0 °C. The results confirm that under flow conditions, paraffin crystallization begins at higher temperatures compared to static conditions, which is of critical importance for the design of crude oil gathering and transportation systems. The obtained data allow more accurate prediction of the risks of asphaltene–resin–paraffin deposits (ARPD) formation and optimization of technological operating conditions of wells at the late stage of field development. Full article

Asphaltene–resin–paraffin deposits (ARPDs) represent one of the most complex flow assurance challenges in oil production, particularly under late-stage reservoir development conditions characterized by pressure depletion, temperature gradients, multiphase flow, and compositional changes. Despite extensive industrial experience, ARPD control strategies are often applied empirically, without explicit linkage to the underlying physicochemical mechanisms governing deposit formation. This review presents a comprehensive and mechanism-oriented analysis of ARPD formation and mitigation in a reservoir–wellbore system. The multicomponent composition, structural heterogeneity, and interfacial activity of paraffins, resins, and asphaltenes are examined alongside thermodynamic, hydrodynamic, and operational factors controlling precipitation, transport, adhesion, and deposit growth. Particular attention is paid to the correspondence between ARPD formation stages and applicable prevention or removal technologies. The analysis demonstrates that preventive strategies targeting early-stage physicochemical processes are fundamentally more effective than post-formation removal methods. The mechanisms of inhibitor action—adsorption, desorption, and dissolution—are shown to operate in a complementary manner, while delivery efficiency is strongly influenced by spatial distribution and retention in the formation. Advanced delivery technologies, including microencapsulation and nanocarrier-based systems, provide enhanced control over inhibitor release and persistence under complex reservoir conditions. Overall, this review establishes an integrated framework linking crude oil properties, formation mechanisms, inhibition chemistry, and delivery technologies, providing a rational basis for designing adaptive and efficient ARPD mitigation strategies in modern oil production systems. Full article

Methane hydrate formation in multiphase transportation pipelines represents a critical challenge to flow assurance under low-temperature conditions. Gaining insight into the kinetic effects of crude oil on hydrate formation aids in developing countermeasures for mixed oil–gas transportation. For this purpose, experiments were carried out at 50 vol% to 90 vol% water cut and pressure of 6.0–7.5 MPa under crude oil–methane–water systems. Results demonstrate that crude oil has kinetic inhibition on hydrate formation, which is caused by mass transfer resistance in emulsion gels. The gas consumption increased by 81.38% when the water cut increased from 60 vol% to 70 vol%. Tween-80 converts crude oil W/O emulsions into O/W emulsions. The addition of Tween-80 to a 50 vol% water cut system resulted in only a 10.04% increase in gas consumption compared to the 90% water cut condition. The results indicate that Tween-80 significantly promotes the formation of hydrates. Furthermore, analysis of gas consumption reveals that the O/W system is more conducive to hydrate growth than the W/O system. Observations through the viewing window revealed that lowering the temperature and hydrates synergistically disrupt the stability of the emulsion. This is caused by the phase transition of wax and asphaltene in crude oil. These findings provide insights for developing flow assurance strategies in crude oil multiphase transportation pipeline operations. Full article

Asphaltenes are the most polar and refractory fraction of crude oil, and are typically isolated using petroleum-derived precipitants (e.g., n-hexane, n-heptane) and then dissolved in aromatic solvents such as toluene, which raises safety and sustainability concerns. Here we evaluate D-limonene, a renewable terpene, as a green, room-temperature precipitant for asphaltene fractionation and benchmark it against n-alkanes and the ASTM D-6560 workflow. Multi-technique characterization (ATR-FTIR/NIR, TGA, CHN, EDS, LDI(+) FT-ICR MS, and ¹H/¹³C NMR) shows that D-limonene yields a lower mass of precipitate yet a fraction with reduced thermal refractoriness (lowest TGA residue, broader/attenuated DTG peak). Molecular readouts indicate lower aromatic condensation/cross-linking in the precipitated subpopulation—narrower DBE envelopes by FT-ICR MS and lower aromatic carbon indices (Car_tot, Car-b, Car-j) by ¹³C NMR—consistent with a mechanism in which π–π/dispersion interactions retain highly condensed multi-ring aggregates in solution under cold, static conditions. These results establish D-limonene as a selective green precipitant for asphaltenes, offering immediate analytical benefits (cleaner, safer fractionation for molecular studies) and a sustainable basis for pretreatments of heavy fractions. Full article

Carbon dioxide injection is one of the most advanced and commercially proven methods of enhanced hydrocarbon recovery, and CO₂ injection has been shown to be very effective in conventional oil reservoirs and is gaining attention in gas, unconventional, and coalbed methane reservoirs. The advantages of CO₂ injection lie in the favorable phase properties and interactions with reservoir fluids, such as swelling, reduction in oil viscosity, reduction in interfacial tension, and miscible displacement in favorable cases. But the low viscosity and density of CO₂ compared to the reservoir fluids result in unfavorable mobility ratios and gravity override, resulting in sweep efficiency limitations. This review offers a broad and EOR-centric evaluation of the various CO₂ injection methods for a broad array of reservoir types, such as depleted oil reservoirs, gas reservoirs for the purpose of gas recovery, tight gas/sands, as well as coalbed methane reservoirs. Particular attention will be given to the use of mobility control/sweep enhancement techniques such as water alternating gas (CO₂-WAG), foam-assisted CO₂ injection, polymer-assisted WAG processes, as well as hybrid processes that combine the use of CO₂ injection with low salinity or engineered waterflood. Further, recent developments in compositional simulation, fracture-resolving simulation, hysteresis modeling, and data-driven optimization techniques have been highlighted. Operational challenges such as injectivity reduction, asphaltene precipitation, corrosion, and conformance problems have been reviewed, along with the existing methods to mitigate such issues. Finally, key gaps in the current studies have been identified, with an emphasis on the development of EHR processes using CO₂ in complex and low-permeability reservoirs, enhancing the resistance of chemical and foam methods in realistic conditions, and the development of reliable methods for optimizing the process on the field scale. This review article will act as an aid in the technical development process for the implementation of CO₂ injection projects for the recovery of hydrocarbons. Full article

In this work, the kinetics of the redistribution of oils, resins, and asphaltenes in high-viscosity oil from the Karazhanbas field (Republic of Kazakhstan) were investigated. This was achieved with an ultrasonic treatment (22 kHz, 50 W) in the presence of a zeolite catalyst (1.0 wt%). The parameters of the technological process were established as a temperature range from 30 to 70 °C and an exposure time of 3 to 11 min. This allowed us to increase the oil content by 14.8% and decrease the concentration of resins by 12.2% and asphaltenes by 2.6%. Conversion schemes (“oils ↔ resins” and “resins ↔ asphaltenes”) were developed, which made it possible to determine the main direction of the reaction processes. The most rapid process is the conversion of resins to oils (k₂ = 0.1148–0.1860 min⁻¹). The process of the cracking of asphaltenes with the formation of resins (k₄ = 0.1023–0.1413 min⁻¹) ranks second in rates. Condensation reactions, including the transition of oils to resins (k₁ = 0.0175–0.0252 min⁻¹) and resins to asphaltenes (k₃ = 0.0139–0.0194 min⁻¹), occur significantly more slowly. The calculated activation energies (7.0–10.4 kJ/mol) show that the cavitation treatment of high-viscosity oil in the presence of a catalyst effectuates the processing of heavy oil with minimal energy consumption. A group composition analysis of the light and middle oil fractions demonstrated an increase in paraffinic, naphthenic, benzenic, and olefinic hydrocarbons, with a simultaneous decrease in naphthalenes and heteroatomic compounds. The results obtained confirm the effectiveness of ultrasonic–catalytic treatment for the structural cracking of high-viscosity oil and the formation of lighter hydrocarbon fractions. Full article

In this study, formation water sample No. 1082 from the Narimanov OGPD, together with crude oil samples from the Bulla-Deniz and Muradkhanli fields, was examined under laboratory conditions to evaluate the efficiency of chemical reagents. The Alkan-318 demulsifier, Marza-1 inhibitor, Difron-4201 depressor additive, and a combined ADM composition (Alkan-318 + Difron-4201 + Marza-1 in a 1:1:1 ratio) were tested for their effects on water separation, corrosion inhibition, sulfate-reducing bacterium activity, paraffin deposition, and pour point depression. Comparative experiments showed that the ADM composition demonstrated superior performance over individual reagents at equal concentrations. At an optimal dosage of 600 g/t, the ADM composition reduced the residual water content (mass fraction) of Bulla-Deniz (75% initial water cut) and Muradkhanli (41% initial water cut) crude oils to 0.1 wt.% and 0.8 wt.%, respectively, after thermochemical treatment. The depressant performance was evaluated based on the degree of pour point reduction (ΔT, °C) relative to untreated oil. At optimal concentrations, Difron-4201 and the ADM composition reduced the pour point by 9.0–10.0 °C, demonstrating the superior efficiency of the multifunctional composition compared to individual additives. Corrosion tests revealed that Marza-1 and ADM provided up to 99.9% protection in aggressive H₂S and CO₂ environments, while ADM also exhibited a nearly complete bactericidal effect (99.8%) against sulfate-reducing bacteria, highlighting its multifunctional efficiency. Full article