Search Results (58)

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

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

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

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

The extra-heavy oil in the Tahe Oilfield of China has extremely high viscosity, as it is rich in the heavy components asphaltene and resin, creating significant difficulties in its exploitation and transportation. Therefore, it is important to effectively reduce the viscosity and improve the fluidity of this extra-heavy oil. The traditional viscosity reduction method suffers from a high blending ratio and a shortage of light crude oil resources for extra-heavy oil blending. In this study, coal tar and washing oil—widely available low-cost by-products of the coal chemical industry—are used for extra-heavy oil blending and viscosity reduction. Washing oil—containing light components distilled from coal tar—was highly effective in reducing the viscosity of extra-heavy oil. When the dilution ratio of washing oil is 0.25, the viscosity of extra-heavy oil is reduced to 1214 mPa·s, and the viscosity reduction rate is 99.8%, indicating that washing oil is an efficient viscosity-reducing agent in extra-heavy oil blending. GC-MS showed that the washing oil contained abundant aromatic hydrocarbons and aromatic heterocyclic rings. A multi-component viscosity reduction system using washing oil coupled with toluene, xylene, and surfactant achieved an even better viscosity reduction effect. In conclusion, we designed a low-cost, high-efficiency, multi-component, and multi-functional synergistic system for extra-heavy oil viscosity reduction in the Tahe Oilfield. In the proposed working mechanism, aromatic hydrocarbons and aromatic heterocyclic rings in washing oil can intercalate into the layered structure of dense asphaltene aggregates, thereby dispersing and dissociating them. Full article

Reservoirs in the Orinoco Heavy Oil Belt, Venezuela, typically hold natural foamy oil. Gas liberation during depletion leads to a sharp increase in viscosity, adversely impacting development efficiency. Therefore, this paper proposes a natural gas (CH₄)–chemical synergistic huff-and-puff method (CCHP). It utilizes the synergism between a stable foam plugging system and natural gas to supplement reservoir energy and promote the generation of secondary foamy oil. To evaluate the performance of 20 types of foam stabilizers (polymers and surfactants), elucidate the influence on production and properties of key parameters, and reveal the flow characteristics of produced fluids, 24 sets of foam performance evaluation tests were conducted using a high-temperature foam instrument. Moreover, 15 sets of core experiments with production fluid visualization were performed. The results demonstrate that, in terms of individual components, XTG and HPAM-20M demonstrated the best foam-stabilizing performance, achieving an initial foam volume of 280 mL and a foam half-life of 48 h. Conversely, the polymer–surfactant composite of XTG-CBM-DA elevated the initial foam volume to 330 mL while maintaining a comparable half-life, further enhancing the performance of foaming capacity for a stable foam system. For further application in the CCHP, oil production shows a positive correlation with both post-depletion pressure and chemical agent concentration; however, the foam gas–liquid ratio (GLR) exhibits an inflection point, with the optimal ratio found to be 1.2 m³/m³. During the huff-and-puff process, the density and viscosity of the produced oil decrease cycle by cycle, while resin and asphaltene content show a significant reduction. Furthermore, visualization results reveal that the foam becomes finer, more stable, and more uniformly distributed under precise parameter control, leading to enhanced foamy oil effects and improved plugging capacity. Moreover, the foam structure transitions from an oil-rich state to a homogeneous and stable configuration throughout the CCHP process. This study provides valuable insights for achieving stable and sustainable development in natural foamy oil reservoirs. Full article

Single-type viscosity reducers often fail to meet the application requirements of specific oilfields for high-viscosity heavy oils. This study focused on Henan heavy oil, systematically investigating the viscosity reduction performances of oil-soluble viscosity reducers, emulsifiers, and their composite systems. Experimental results indicated that the oil-soluble ethylene-vinyl acetate copolymer (EVA) achieved optimal efficiency at a concentration of 500 ppm, with a viscosity reduction rate of 44.2%. Among the screened emulsifiers, acrylonitrile-ethylene-styrene (AES) exhibited the highest viscosity reduction rate (99.9%), which basically complied with relevant industrial application standards. When EVA and AES were compounded, the resulting composite reducer showed a significantly higher viscosity reduction rate than single EVA, and the stability of the formed oil-in-water (O/W) emulsion was further enhanced. The synergistic mechanism was clarified as follows: EVA first disrupts the aggregation of heavy components (resins and asphaltenes) and modifies wax crystal morphology, creating a favorable microfoundation for subsequent emulsification; AES then promotes the formation of stable O/W emulsions, ultimately achieving a “1 + 1 > 2” synergistic viscosity reduction effect. Furthermore, the potential action mechanism of the EVA-AES composite system was verified using multiple characterization techniques. This study provides a valuable reference for the selection and practical application of heavy oil viscosity reducers in oilfield operations. Full article

Temperature is a key factor in regulating interfacial behaviors and enhancing oil recovery during low-salinity water flooding in tight sandstone reservoirs. This study systematically investigates the synergistic mechanisms of temperature and salinity on ion exchange, wettability alteration, interfacial tension, and crude oil desorption. The experimental results show that elevated temperature significantly strengthens the oil–water–rock interactions induced by low-salinity water, thereby improving oil recovery. At 70 °C, the release of divalent cations such as Ca²⁺ and Mg²⁺ from the rock surface is notably enhanced. Simultaneously, the increase in interfacial electrostatic repulsion is evidenced by a shift in the rock–brine zeta potential from −3.14 mV to −6.26 mV. This promotes the desorption of polar components, such as asphaltenes, from the rock surface, leading to a significant change in wettability. The wettability alteration index increases to 0.4647, indicating a strong water-wet condition. Additionally, the reduction in oil–water interfacial zeta potential and the enhancement in interfacial viscoelasticity contribute to a further decrease in interfacial tension. Under conditions of 0.6 PW salinity and 70 °C, non-isothermal core flooding experiments demonstrate that rock–fluid interactions are the dominant mechanism responsible for enhanced oil recovery. By applying a staged injection strategy, where 0.6 PW is followed by 0.4 PW, the oil recovery reaches 34.89%, which is significantly higher than that achieved with high-salinity water flooding. This study provides critical mechanistic insights and optimized injection strategies for the development of high-temperature tight sandstone reservoirs using low-temperature waterflooding. Full article

CO₂ flooding has become a strategic tool for enhanced oil recovery and reservoir management in mature fields. This technique, however, is rarely utilized in asphaltenic crude oil systems, due to the likely occurrence of high asphaltene precipitation. The effect of asphaltene concentrations and CO₂ injection pressures has mostly been the focus of studies in determining asphaltene precipitation rates. However, asphaltene precipitation is not the only direct factor to be considered in predicting the extent of damage in an asphaltenic crude oil system. In this study, a compositional reservoir simulation was conducted using Eclipse 300 to investigate the injection pressure at which asphaltene-induced formation damage can be avoided during both miscible and immiscible CO₂ flooding in an asphaltenic crude system. Simulation results indicate that asphaltene-induced permeability reduction exceeded 35% in most affected zones, with a corresponding drop in injectivity of 28%. Cumulative oil recovery improved by 19% compared to base cases without CO₂ injection, achieving peak recovery after approximately 4200 days of simulation time. As CO₂ was injected below the Minimum Miscibility Pressure (MMP) of 2079.2 psi, a significantly lower asphaltene precipitation was observed near the injector. This could be attributed to the stripping of lighter hydrocarbon components (C2–C7+) occurring in the transition zone at the gas–oil interface. Injecting CO₂ at pressures above the MMP resulted in precipitation occurring throughout the entire reservoir at 3200 psia and 1000 bbl/day injection rates. An increase in the injection rate at pressures above the MMP increased the rate of precipitation. However, a further increase in the injection rate from 1000 bbl/day to 4200 bbl/day resulted in a decrease in asphaltene deposition. The pressure drop in the water phase caused by pore throat increase demonstrated that water injection was effective in removing asphaltene deposits and restoring permeability. This work provides critical insights into optimizing CO₂ injection strategies to enhance oil recovery while minimizing asphaltene-induced formation damage in heavy oil reservoirs. Full article

Recovering oil by fracturing fluid imbibition has demonstrated significant potential for enhanced oil recovery (EOR) in tight oil reservoirs. White mineral oil (WMO), kerosene, or saturated alkanes with matched apparent viscosity have been widely used as “crude oil” to investigate imbibition mechanisms in light shale oil or tight oil. However, the representativeness of these simulated oils for low-maturity crude oils with higher viscosity and greater content of resins and asphaltenes requires further research. In this study, imbibition experiments were conducted and T₂ and T₁–T₂ nuclear magnetic resonance (NMR) spectra were adopted to investigate the oil recovery characteristics among resin–asphaltene-rich Jimusar shale oil and two WMOs. The overall imbibition recovery rates, pore scale recovery characteristics, mobility variations among oils with different occurrence states, as well as key factors influencing imbibition efficiency were analyzed. The results show the following: (1) WMO, kerosene, or alkanes with matched apparent viscosity may not comprehensively replicate the imbibition behavior of resin–asphaltene-rich crude oils. These simplified systems fail to capture the pore-scale occurrence characteristics of resins/asphaltenes, their influence on pore wettability alteration, and may consequently overestimate the intrinsic imbibition displacement efficiency in reservoir formations. (2) Surfactant optimization must holistically address the intrinsic coupling between interfacial tension reduction, wettability modification, and pore-scale crude oil mobilization mechanisms. The alteration of overall wettability exhibits higher priority over interfacial tension in governing displacement dynamics. (3) Imbibition displacement exhibits selective mobilization characteristics for oil phases in pores. Specifically, when the oil phase contains complex hydrocarbon components, lighter fractions in larger pores are preferentially mobilized; when the oil composition is homogeneous, oil in smaller pores is mobilized first. Full article

Micro-fracturing technology is a key approach to enhancing the flow capacity of oil sands reservoirs and improving Steam-Assisted Gravity Drainage (SAGD) performance, whereas heterogeneity in reservoir physical properties significantly impacts stimulation effectiveness. This study systematically investigates the coupling mechanisms of asphaltene content, clay content, and heavy oil viscosity on micro-fracturing stimulation effectiveness, based on the oil sands reservoir in Block Zhong-18 of the Fengcheng Oilfield. By establishing an extended Drucker–Prager constitutive model, Kozeny–Poiseuille permeability model, and hydro-mechanical coupling numerical simulation, this study quantitatively reveals the controlling effects of reservoir properties on key rock parameters (e.g., elastic modulus, Poisson’s ratio, and permeability), integrating experimental data with literature review. The results demonstrate that increasing clay content significantly reduces reservoir permeability and stimulated volume, whereas elevated asphaltene content inhibits stimulation efficiency by weakening rock strength. Additionally, the thermal sensitivity of heavy oil viscosity indirectly affects geomechanical responses, with low-viscosity fluids under high-temperature conditions being more conducive to effective stimulation. Based on the quantitative relationship between cumulative injection volume and stimulation parameters, a classification-based optimization model for oil sands reservoir operations was developed, predicting over 70% reduction in preheating duration. This study provides both theoretical foundations and practical guidelines for micro-fracturing parameter design in complex oil sands reservoirs. Full article

The goal of this study is to evaluate how the inclusion of synthetic wax, added in 0.5% increments from 1.5% to 3.5%, affects the characteristics of PMB 45/80-65 (polymer-modified bitumen) during both short-term (RTFOT) and long-term (PAV) aging processes. Tests were carried out to assess the fundamental properties of the binder, leading to the determination of the penetration index (PI) and the plasticity range (PR). The binder’s properties were examined at below-freezing operating temperatures, with creep stiffness measured using a bent beam rheometer (BBR) at −10 °C, −16° C, −22 °C, and −28 °C. The rheological properties of the asphaltenes were evaluated based on both linear and nonlinear viscoelasticity. The experimental study explored temperature effects on the rheological properties of composite materials using a DSR dynamic shear rheometer at 40 °C, 60 °C, and 80 °C over a frequency range of 0.005 to 10 Hz. The main parameters of interest were composite viscosity (η*) and zero shear viscosity (η₀). Viscoelastic parameters, including the dynamic modulus (G*) and phase shift angle (δ), were determined, and Black’s curves were used to illustrate the relationship between these parameters, where G*/sinδ was determined. The MSCR test was employed to investigate the impact of bitumen on the asphalt mixture’s resistance to permanent deformation and to assess the degree and efficacy of asphalt modification. The test measured two parameters, irreversible creep compliance (J_nr) and recovery (R), under stress levels of 0.1 kPa (LVE) and 3.2 kPa (N-LVE). The Christensen–Anderson–Marasteanu model was used to describe the bitumen behavior during binder aging, as reflected in the rheological study results. Ultimately, this study revealed that synthetic wax influences the rheological properties of PMB 45/80-65 polymer bitumen. Specifically, it mitigated the stiffness reduction in modified bitumen caused by polymer degradation during aging at an amount less than 2.5% of synthetic wax. Full article

The development of eco-friendly surfactants is pivotal for enhanced oil recovery (EOR). In this study, a novel lignin-derived zwitterionic surfactant (DMS) was synthesized through a two-step chemical process involving esterification and free radical polymerization, utilizing renewable alkali lignin, maleic anhydride, dimethylamino propyl methacrylamide (DMAPMA), and sulfobetaine methacrylate (SBMA) as precursors. Comprehensive characterization via ¹H NMR, FTIR, and XPS validated the successful integration of amphiphilic functionalities. Hydrophilic–lipophilic balance (HLB) analysis showed a strong tendency to form stable oil-in-water (O/W) emulsions. The experimental results showed a remarkable 91.6% viscosity reduction in Xinjiang heavy crude oil emulsions at an optimum dosage of 1000 mg/L. Notably, DMS retained an 84.8% viscosity reduction efficiency under hypersaline conditions (total dissolved solids, TDS = 200,460 mg/L), demonstrating exceptional salt tolerance. Mechanistic insights derived from zeta potential measurements and molecular dynamics simulations revealed dual functionalities: interfacial modification by DMS-induced O/W phase inversion and electrostatic repulsion (zeta potential: −30.89 mV) stabilized the emulsion while disrupting π–π interactions between asphaltenes and resins, thereby mitigating macromolecular aggregation in the oil phase. As a green, bio-based viscosity suppressor, DMS exhibits significant potential for heavy oil recovery in high-salinity reservoirs, addressing the persistent challenge of salinity-induced inefficacy in conventional chemical solutions and offering a sustainable pathway for enhanced oil recovery. Full article

UV radiation can change the internal molecular composition, macroscopic rheological properties, and microscopic chemical composition of asphalt. To study the effect of ultraviolet aging on asphalt and its structure–activity relationship, its rheological properties were measured by dynamic shear rheology and multiple stress recovery creep tests, its chemical compositions were measured by component composition, elemental composition, and infrared spectrum tests, and its molecular weight, distribution, and molecular structure were determined by gel permeation chromatography and nuclear magnetic resonance tests. Then, the molecular weight and molecular structure, rheological properties, and microchemical aging behavior of asphalt after UV aging were characterized by correlation analysis, and the structure–activity relationship was analyzed. The results show that the deformation resistance and elastic recovery ability of asphalt after UV aging are enhanced, and the flow performance is decreased. The ultraviolet radiation caused the aromatic hydrocarbons containing naphthenes and long alkyl chains in the asphalt to break and connect with asphaltenes with a ring structure. The asphaltene content in each bitumen sample exceeded 46%, and that in KL reached 55%, indicating that the bitumen changed into a gel structure. UV aging causes the aggregation of asphalt molecules, and the aggregation of molecules narrows the molecular distribution boundary and moves in the direction of macromolecules, resulting in the reduction of the dispersion coefficient by 2–10%. Hydrogen atoms will undergo condensation and substitution reactions due to long-chain breaking, cyclization, or aromatization under UV action, and the breaking of C=C bonds in carbon atoms will increase the stable aromatic ring, strengthen the stiffness of the molecular backbone, and make it difficult for the backbone to spin. Through correlation analysis, it was found that the molecular composition index could characterize the aging behavior index of asphalt, and that the aromatic structure was the most critical molecular change. Further, it was found that the sulfoxide group and carbonyl group could be used as evaluation criteria for the UV aging of asphalt because the correlation between them was above 0.7. This study provides an essential index reference for evaluating the performance change of asphalt under ultraviolet aging to save testing time. Moreover, the molecular structure characterization revealed the changes in internal molecular composition that were behind the observed aging properties, providing a theoretical basis for research on asphalt anti-aging technology. Full article