Search Results (367)

Well-killing operations in water-sensitive hydrophilic formations are often complicated by extended well clean-up periods and, in some cases, failure to restore the well’s production potential post-kill. Typical development targets exhibiting these properties include the Neocomian and Jurassic deposits of fields in Western Siberia and Western Kazakhstan. This paper proposes a well-killing method incorporating simultaneous near-wellbore treatment. In cases where heavy oil components (asphaltenes, resins, or paraffins) are deposited in the near-wellbore zone, their removal with a solvent results in post-operation flow rates that exceed pre-restoration levels. For wells not affected by asphaltene, resin, and paraffin deposits, killing is performed using a blocking pill of invert emulsion stabilized with an emulsifier and hydrophobic nanosilica. During filtration into the formation, this emulsion does not break but rather reforms according to the pore throat sizes. Flow rates in such wells typically match pre-restoration levels. The described engineering solution proves less effective when the well fluid water cut exceeds 60%. For wells exhibiting premature water breakthrough that have not yet produced their estimated oil volume, the water source is identified, and water shutoff operations are conducted. This involves polymer-gel systems crosslinked with resorcinol and paraform, reinforced with inorganic components such as chrysotile microdispersions, micro- and nanodispersions of shungite mineral, and gas black. Oscillation testing identified the optimal additive concentration range of 0.6–0.7 wt%, resulting in a complex modulus increase of up to 25.7%. The most effective polymer-inorganic composite developed by us, incorporating gas black, demonstrates high water shutoff capability (residual resistance factor ranges from 12.5 to 65.0 units within the permeability interval of 151.7 to 10.5 mD). Furthermore, the developed composites exhibit the ability to selectively reduce water permeability disproportionately more than oil permeability. Filtration tests confirmed that the residual permeability to oil after placing the blocking composition with graphene is 6.75 times higher than that to water. Consequently, such treatments reduce the well water cut. Field trials confirmed the effectiveness of the developed polymer-inorganic composite systems. Full article

Addressing IMO 2020 compliance, this study investigates marine fuel oil production from hydrotreated residues, focusing on mitigating excessive total sediment potential (TSP) caused by over-hydrotreatment. This study systematically investigates the impact of blending ratios of Fluid Catalytic Cracking (FCC) slurry oil with Residue Desulfurization (RDS) heavy oil on TSP, colloidal stability, and asphaltene structure evolution. Techniques such as XRD, SEM, and XPS were employed to analyze the structural changes in asphaltenes during the TSP exceeding process. The results indicate that as the FCC slurry oil blending ratio increases, TSP in the blended oil initially rises and then decreases. The peak TSP value of 0.41% occurs at a 10% FCC slurry oil blending ratio, primarily due to high-saturation hydrocarbons in RDS heavy oil disrupting the colloidal stability of asphaltenes in FCC slurry oil. When the blending ratio reaches 25%, TSP significantly decreases to 0.09%, attributed to the solubilizing effect of high aromatic compounds in the FCC slurry oil on the asphaltenes. The ω(Asp)/ω(Res) ratio mirrors the TSP trend, and the colloidal solubilizing capacity of asphaltenes increases with the blending ratio. Asphaltenes in RDS heavy oil exhibit a spherical structure, whereas those in FCC slurry oil show a layered structure. The precipitated asphaltenes in the blends primarily result from the aggregation of asphaltenes in FCC slurry oil, with heteroatoms (N, S, O) mainly originating from RDS heavy oil asphaltenes. During the early stage of blending, TSP formation is dominated by FCC slurry oil asphaltenes, but increasing the aromatic content in the system can significantly reduce TSP. This work provides theoretical and technical support for optimizing marine fuel blending processes in petrochemical enterprises. 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

This study evaluates the effectiveness of various rejuvenating oils, including soybean oil (N-oil), waste frying oil (F-oil), byproduct oil (W-oil), and aromatic hydrocarbon oil (A-oil), in restoring aged asphalt coatings by reducing asphaltene flocculation and improving colloidal stability. The rejuvenators were incorporated into aged asphalt binder via direct mixing at controlled dosages. Their effects were assessed using microscopy, droplet diffusion analysis, rheological testing (DSR and BBR), and molecular dynamics simulations. The aim is to compare the compatibility, solubility behavior, and rejuvenation potential of plant-based and mineral-based oils. The results indicate that N-oil and F-oil promote asphaltene aggregation, which supports structural rebuilding. In contrast, A-oil and W-oil act as solvents that disperse asphaltenes. Among the tested oils, N-oil exhibited the best overall performance in enhancing flowability, low-temperature flexibility, and chemical compatibility. This study presents a novel method to evaluate rejuvenator effectiveness by quantifying colloidal stability through grayscale analysis of droplet diffusion patterns. This integrated approach offers both mechanistic insights and practical guidance for selecting bio-based rejuvenators in asphalt recycling. 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

Capturing CO₂ emitted by coal chemical enterprises and injecting it into oil reservoirs not only effectively improves the recovery rate and development efficiency of tight oil reservoirs in the Ordos Basin but also addresses the carbon emission problem constraining the development of the region. Since initiating field experiments in 2012, the Ordos Basin has become a significant base for CCUS (Carbon capture, Utilization, and Storage) technology application and demonstration in China. However, over the years, projects have primarily focused on enhancing the recovery rate of CO₂ flooding, while issues such as potential reservoir damage and its extent have received insufficient attention. This oversight hinder the long-term development and promotion of CO₂ flooding technology in the region. Experimental results were comprehensively analyzed using techniques including nuclear magnetic resonance (NMR), X-ray diffraction (XRD), scanning electron microscopy (SEM), inductively coupled plasma (ICP), and ion chromography (IG). The findings indicate that under current reservoir temperature and pressure conditions, significant asphaltene deposition and calcium carbonate precipitation do not occur during CO₂ flooding. The reservoir’s characteristics-high feldspar content, low carbon mineral content, and low clay mineral content determine that the primary mechanism affecting physical properties under CO₂ flooding in the Chang 4 + 5 tight sandstone reservoir is not, as traditional understand, carbon mineral dissolution or primary clay mineral expansion and migration. Instead, feldspar corrosion and secondary particles migration are the fundamental reasons for the changes in reservoir properties. As permeability increases, micro pore blockage decreases, and the damaging effect of CO₂ flooding on reservoir permeability diminishes. Permeability and micro pore structure are therefore significant factors determining the damage degree of CO₂ flooding inflicts on tight reservoirs. In addition, temperature and pressure have a significant impact on the extent of reservoir damage caused by CO₂ flooding in the study region. At a given reservoir temperature, increasing CO₂ injection pressure can mitigate reservoir damage. It is recommended to avoid conducting CO₂ flooding projects in reservoirs with severe pressure attenuation, low permeability, and narrow pore throats as much as possible to prevent serious damage to the reservoir. At the same time, the production pressure difference should be reasonably controlled during the production process to reduce the risk and degree of calcium carbonate precipitation near oil production wells. Full article

Asphalt–rubber binders (A-RBs) have a long and deep history of use; however, little is known regarding the interrelated chemical behaviors and miscibility of rubber with the asphalt fractions [saturates, aromatics, resins, and asphaltenes (SARA)]. This study comprehensively attempted to address this knowledge deficiency by employing Fourier transform infrared spectroscopy (FTIR) to investigate the chemical evolution of A-RBs. A-RB interacted at 190 °C and 3000 min⁻¹ for 8 h was deemed to have the optimal rheological performance. FTIR of the liquid fractions of A-RB 190–3000 showed a prominent chemical shift in the SARA fractions, with new peaks that showed rubber polybutadiene (PB) and polystyrene migration into asphaltenes. Meanwhile, decreases in peaks with C–H aromatic bending and S=O stretching for the A-RB 190–3000 saturates showed that the rubber absorbed low-molecular-weight maltenes during swelling. Peaks associated with C=C aromatic appeared in saturates and aromatics, respectively, emphasizing that unsaturated components migrated from the rubber into the asphalt. Thermal analysis showed that rubber dissolution for this sample reached 82%. While a PB peak existed in asphaltenes of A-RB 220–3000, its intensity was diminished by depolymerization, thus compromising the integrity of the migrated rubber structure and generating less rheological enhancement. This study concludes that FTIR characterization of SARA fractions offers valuable insights into the interactions between asphalt and rubber, and that regulated processing conditions are essential for enhancing binder performance. Full article

The growing global demand for energy necessitates the efficient utilization of unconventional petroleum resources, particularly heavy oil reserves. However, extracting, transporting, and processing these resources remain challenging due to their low mobility, low API gravity, and significant concentrations of resins, asphaltenes, heteroatoms, and metals. In recent years, various in situ upgrading techniques have been explored to enhance heavy oil quality, with catalytic aquathermolysis emerging as a promising approach. The effectiveness of this process largely depends on the development of cost-effective, environmentally friendly catalysts. This study investigates the upgrading performance of water-soluble ammonium alum, (NH₄)Al(SO₄)₂·12H₂O, for an extra-heavy oil sample from the Zarafshan Depression, located along the Tajikistan–Uzbekistan border. Comprehensive analyses demonstrate that the catalyst facilitates the breakdown of heavy oil components, particularly resins and asphaltenes, into lighter fractions. As a result, oil viscosity was significantly reduced by 94%, while sulfur content decreased from 896 ppm to 312 ppm. Furthermore, thermogravimetric (TG-DTG) analysis, coupled with Fourier-transform infrared spectroscopy (FT-IR), scanning electron microscopy (SEM), and X-ray diffraction (XRD), revealed that the thermal decomposition of ammonium alum produces catalytically active Al₂O₃ nanoparticles. These findings suggest that ammonium alum is a highly effective water-soluble pre-catalyst for hydrothermal upgrading, offering a viable and sustainable solution for the development of extra-heavy oil fields. Full article

Asphaltene deposition remains a critical challenge in water-injected reservoirs, where pressure and compositional variations destabilize the oil phase, triggering precipitation and formation damage. This study explores the application of intermittent waterflooding (IWF) as a practical mitigation strategy, combining alternating injection and well shut-in times to stabilize fluid conditions. A synthetic reservoir model was developed in Eclipse 300 to evaluate how key parameters such as shut-in time, injection rate, and injection timing affect asphaltene behavior under varying operational regimes. Comparative simulations against traditional continuous waterflooding reveal that IWF can significantly suppress near-wellbore deposition, preserve permeability, and improve overall oil recovery. The results show that early injections and optimized cycling schedules maintain reservoir pressure above the bubble point, thereby reducing the extent of destabilization. This study offers a simulation-based framework for IWF design, providing insights into asphaltene control mechanisms and contributing to more efficient reservoir management in fields prone to flow assurance issues. 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

Conjugated polymers (CPs) offer many attractive features for photodiodes and photovoltaics, including solution processability, ease of scale-up, light weight, low cost, and mechanical flexibility. CPs have a wide range of energy gaps; thus, the choice of the specific polymer determines the optimum operational wavelength range. However, there are relatively few CPs with a strong absorption in the blue region of the spectrum where the human eye is most sensitive (440 to 470 nm) and none with an energy gap at 2.75 eV (450 nm), which corresponds to the peak of the CIE-1931 z(λ) color-matching function and the dominant blue light emission wavelength in computer and smartphone displays. Blue-light detectors in this wavelength range are important for light hazard control, sky polarization studies, and for blue-light information devices, where 450 nm corresponds to the principal emission of GaN-based light sources. We report on a new CP called Atums Green (AG), which shows promising characteristics as a blue-light photodetection polymer optimized for exactly this range of wavelengths centered around 450 nm. We built and measured a simple photodetector made from spin-coated films of AG and showed that its photosensitivity can be improved by the addition of asphaltene, a low-cost carbonaceous waste product. Full article

Asphalt recycling technologies have advanced considerably over the last few decades with the utilization of reclaimed asphalt pavements (RAP) and recycled asphalt shingles (RAS). Characterizing aged and heterogeneous binders in these mixtures is challenging, particularly with limited extracted binders. This study suggests a data-driven framework that considers the rheological, chemical, and thermal characteristics to predict the binders’ performance. Ninety-seven mixtures with 0–35% of the asphalt binder replaced with RAP/RAS binders were included as cores from the field, plant-produced mixtures, and laboratory-fabricated mixtures. The binders were chemically quantified using aging, aromatic, and aliphatic indices. Thermal analyses of the binders involved the percentage of the thermal residue. The framework predicted the rheological resistance of the binders to rutting and cracking using linear and nonlinear machine learning models. The nonlinear models outperformed the linear models for the three rheological parameters. The nonlinear models achieved a 69% reduction in the root mean square error (RMSE) for rutting, a 37% reduction in the RMSE for fatigue cracking, and a 21% reduction in the RMSE for thermal cracking. However, the nonlinear models overfitted for block cracking and had an RMSE 41% higher than the linear models, despite a perfect correlation (R = 1.00). The feature importance demonstrated the strong effects of the chemical and thermal parameters on rheological prediction. The data-driven framework can successfully support efforts to better manage asphalt recycling by predicting the binder performance. Full article

In the production process of the heavy oil industry, efficiently demulsifying water-in-heavy oil (W/HO) emulsions can effectively prevent the negative effects of emulsion corrosion on equipment, increase costs, reduce oil quality, and pollute the environment. Herein, polyether demulsifier complexes (PDC) were obtained by compounding fatty alcohol nonionic polyether (FAP) with perfluoropolyether (PFPEA, [CF₃O(CF₂CF₂O)_nCF₃]) through a simple physical blending method. The experimental results demonstrate that PDC exhibited outstanding demulsification performance for W/HO emulsions across varying temperatures: At 60 °C and 400 ppm dosage, PDC achieved complete dehydration (100%) within just 2 min, showing significantly faster demulsification kinetics compared to FAP and PFPEA. Even at the reduced temperature of 40 °C, PDC maintained effective demulsification capability, achieving complete phase separation within 6 min. These findings collectively establish PDC’s superior demulsification efficiency for W/HO emulsions, with particularly remarkable performance under challenging low-temperature conditions. Research on the demulsification mechanism indicates that PDC achieves efficient demulsification performance due to the synergistic effect the synergistic effect of FAP and PFPEA to effectively destroy the non-covalent bonds (hydrogen and π–π stacking) of interfacially active asphaltenes (IAA) at the oil–water interface, thereby achieving demulsification of W/HO emulsion. PDC with outstanding demulsification ability exhibits significant potential for practical applications in heavy crude oil–water emulsion treatment, and this work can provide insights for developing new composite demulsifiers for petroleum production. Full article

The results of core flooding experiments can guide the formulation of development plans for similar oil reservoirs. However, for cores from heavy oil reservoirs, asphaltene deposition often occurs during flooding due to changes in pressure, temperature, and petroleum composition, affecting the determination of injection parameters. Taking core samples from the Xia 018 well block as the research object, this study determined that the crude oil sample exhibits normal CO₂ sensitivity based on PVT experiments and core flooding results. A corresponding asphaltene precipitation model was established and coupled with core-scale numerical simulation, forming an integrated core-scale numerical simulation method considering asphaltene precipitation. Through orthogonal experimental design, the optimized fracturing production parameters for Well Y were determined as follows: fracturing stage length of 1000 m, CO₂ injection volume of 100 m³ per stage, fluid volume per stage of 1000 m³, proppant volume of 1000 m³, and injection rate of 14 m³/min. Finally, the optimized parameters were applied to simulate a case well, where the asphaltene deposition model combined with pressure nephograms during production provided effective guidance on unplugging timing. Compared with results without using the asphaltene deposition model, cumulative production decreased by 1300 m³ when the model was applied. These findings can provide a reference for the development of similar reservoirs. Full article