Search Results (304)

Developing complex fault-block low-permeability reservoirs faces great challenges in constructing efficient injection-production flow pathways, which often leads to unsatisfactory waterflooding development performance. To improve the recovery efficiency of this type of reservoir, this study first carried out laboratory extraction experiments and then conducted CO₂ extraction numerical simulations on low-permeability porous media via ANSYS to validate the experimental results. Based on investigations targeting the target reservoir, the key findings are summarized as follows: Supercritical CO₂ preferentially extracts light hydrocarbon components lighter than C₁₀, which accounts for more than 60% of the total extracted components; when the pressure exceeds 20 MPa, a small amount of heavy components C₁₅₊ can also be extracted. Under the experimental conditions adopted in this study, the optimal CO₂ reinjection pressure range is determined as 12–20 MPa. Within this range, the extraction efficiency increases by 2.0–2.5% per 1 MPa increment of pressure, and this pressure condition can effectively dissolve medium hydrocarbon components and promote the formation of uniform plug flow. However, when the reinjection pressure continues to rise beyond 20 MPa, the CO₂ extraction efficiency will gradually decrease. The numerically simulated CO₂ extraction efficiency of crude oil shows high consistency with the experimental measurements. This study confirms that CO₂ huff-n-puff can be effectively applied for crude oil extraction in the peripheral areas of tight reservoirs and fault-block reservoir units. Nevertheless, in field application, it is imperative to optimize the reinjection pressure design: accurately customizing injection pressure parameters according to different reservoir types and their specific development requirements is a core measure to improve CO₂ extraction efficiency. Full article

Heavy oil reservoirs typically suffer from low recovery efficiency and high development costs during thermal production. This study investigates the A66 heavy oil reservoir and proposes an integrated hot-water flooding and hot-to-cold injection strategy. Laboratory experiments, numerical simulations, and techno-economic analysis are combined to optimize injection temperature, conversion timing, and injection parameters. Results show that injection temperature strongly affects oil recovery. Increasing temperature from 40 °C to 60 °C significantly improves recovery by reducing oil viscosity and enhancing mobility. However, further increases to 80 °C and 100 °C provide only marginal additional improvement, indicating a clear diminishing return effect. Considering both recovery performance and energy consumption, 60 °C is identified as the optimal injection temperature. Simulation results indicate that the timing of hot-to-cold conversion has a limited impact on final recovery, while significantly affecting development cost. A conversion window at a water cut of 10–20% achieves a balanced performance between displacement efficiency and thermal cost reduction. In addition, unstable injection improves sweep efficiency by dynamically adjusting flow paths and enhancing both areal and vertical displacement. A coupled hot-to-cold injection strategy is therefore proposed. It integrates temperature optimization, injection mode design, and conversion timing to improve both recovery and economic performance. Compared with conventional constant-temperature flooding, the proposed strategy better accounts for the time-dependent evolution of reservoir thermal conditions and fluid properties. Techno-economic evaluation confirms that the optimized scheme achieves higher economic efficiency while maintaining stable recovery improvement, demonstrating strong potential for field application in similar heavy oil reservoirs. Full article

This study addresses the operational challenges of developing hard-to-recover reserves such as heavy-oil rims in weakly consolidated sandstone reservoirs of Western Siberia, which account for a significant share of Russia’s resource base. The core challenge is the inevitable solid production during extraction, leading to abrasive wear, erosion, plugging of downhole pumping equipment, frequent failures, and substantial economic losses. The objective of this work is a comprehensive analysis of the causes of sand production and related equipment failures by integrating published research with field failure data. The research methodology includes an analysis of scientific publications and a statistical review of the causes and frequency of Electrical Submersible Pump (ESP) failures in wells produced by the PK formation. The results show that the primary failure causes are erosive wear (predominantly in medium-rate deviated wells) and plugging by produced solids (predominantly in low-rate horizontal wells), which correlate with sand transport regimes and the particle size distribution (PSD) of produced solids. The failure frequency was found to be comparable across different well types, but the equipment damage mechanisms differed significantly. The discussion confirms the necessity for an integrated approach to modeling the “reservoir–sand control screen–wellbore” system to optimize operating parameters and select effective sand control techniques. Full article

Thin-layer extra-heavy oil reservoirs are commonly characterized by small oil-bearing thickness, high crude oil viscosity, and severe steam override. To address these problems, a multi-component thermal composite flooding method with branched horizontal wells was proposed. The method combines steam, viscosity reducer, and N₂ injection. Three-dimensional physical experiments and laboratory-scale numerical simulations were conducted. The temperature field expansion, production performance, thermal sweep range, and reservoir utilization degree were compared under three development methods: steam flooding with branched horizontal wells, multi-component thermal composite flooding with horizontal wells, and multi-component thermal composite flooding with branched horizontal wells. The results show that multi-component thermal composite flooding with branched horizontal wells can effectively suppress steam override. It can also enlarge the steam chamber, improve the uniformity of reservoir heating, and enhance the production of remaining oil. The peak oil production rate reached 18.6 mL/min, and the final oil recovery factor was 56.19%. These values were 10.48 and 27.21 percentage points higher than those of multi-component thermal composite flooding with horizontal wells and steam flooding with branched horizontal wells, respectively. The numerical simulation results show that the effective heated zone ratio reached 51.14%, while the unswept zone ratio decreased to 20.30%. The enhancement mechanism is attributed to the synergistic effect of well structure, viscosity reducer, N₂, and steam, which improves thermal sweep efficiency and reservoir utilization. The results provide a reference for the efficient development of thin-layer extra-heavy oil reservoirs. Full article

The Jinjia oilfield in Shengli oilfield is a typical ultra-sensitive reservoir characterized by high crude oil viscosity, poor fluidity, high clay content, and weak cementation. During development, oil-sand mixtures readily plug pore throats. Various development methods including water flooding and thermal recovery have been implemented, yet severe problems persist: inability to inject, failure to displace, and lack of capacity to produce. To address these challenges, a functional microbial mineral-modified desensitization-chemical viscosity-reduction dual-effect agent, a self-growing gel dispersion profile control agent, and a low-damage deep acidizing system were developed. Laboratory experiments clarified the enhanced oil recovery mechanism of the bio-chemical desensitization and viscosity-reduction system. Results indicate that the desensitization and viscosity-reduction system can inhibit clay swelling, with the anti-swelling improvement rate of core permeability reaching 56%. Chemical viscosity reduction enabled heavy oil to “flow effectively,” achieving a viscosity reduction rate of 98.9% after adsorption. The profile control agent dispersed and migrated, then stably adsorbed onto particle surfaces to plug high-permeability channels, demonstrating strong anti-scouring capability and effectively suppressing channeling flow. In the composite system, bio-chemical desensitization and viscosity reduction synergistically enhanced mobility control, achieving an oil recovery factor of 56.5%, representing a 26.3% increase over post-water-flooding viscosity-reduction flooding. After two pilot well groups in the Jinjia oilfield were converted from water flooding to bio-chemical desensitization and viscosity-reduction composite flooding, single-well oil production capacity increased by 2.8-fold, water cut decreased by 12%, and both development performance and economic benefits were significantly improved—transforming the situation from “increasing water without increasing oil” to “increasing both liquid and oil production.” The research findings provide important reference value for the effective development of ultra-sensitive reservoirs. Full article

Steam-assisted gravity drainage (SAGD) is constrained in deep heavy-oil reservoirs by wellbore heat losses, delayed steam-chamber development and high steam–oil ratio (SOR). This study develops an experimentally parameterized reduced-order screening framework for thermocable-assisted SAGD, formulated as a digital-twin prototype that couples heat transfer, temperature-dependent viscosity, chamber-growth geometry and energy-efficiency indicators. The formulation is evaluated within an experimentally parameterized screening matrix covering steam temperature, oil viscosity, permeability, depth, cable power and early heating time. The graphical dependencies are presented in a unified publication format and supplemented by heat-balance, chamber-field, sensitivity and operating-window analyses. For the reference experimental case, thermocable support increases oil rate from 84.1 to 96.1 t/day and reduces SOR from 2.70 to 2.30 t/t. The cable heat input is small relative to useful steam heat; therefore, its effect is interpreted through local compensation of downstream heat deficit and longitudinal temperature stabilization rather than through bulk energy addition. The strongest sensitivity is associated with steam rate, oil viscosity and depth, whereas cable power shows a beneficial but saturating effect. The proposed reduced-order digital-twin prototype is intended for feasibility screening, preliminary operating-window selection and prioritization of candidate regimes for detailed thermal-reservoir simulation and subsequent field-scale validation. Full article

Steam-assisted gravity drainage (SAGD) remains one of the most energy-intensive technologies for heavy-oil recovery because production response is controlled not only by injected heat but also by spatial heat delivery, wellbore losses, viscosity reduction and steam chamber geometry. This paper develops a physics-guided digital twin for SAGD with distributed thermocable assistance and a bounded residual machine learning correction layer. The framework combines a heat-delivery model, temperature-dependent oil mobility, scenario analysis and decision-oriented visualization within a reproducible computational experiment. A reference operating envelope was formulated for heavy-oil reservoirs, including depth, horizontal well length, permeability, porosity, oil viscosity, steam temperature, injection rate, thermocable power and cable coverage. The analysis includes sensitivity testing, cumulative-production/SOR dynamics and Pareto-type operating-window mapping. In the reference computational scenario, which is treated as an illustrative screening case rather than as field-history validation, the thermocable-assisted hybrid configuration changed the model-calculated eight-year cumulative oil from 452.5 × 10³ m³ to 615.2 × 10³ m³ and the mean SOR from 3.17 to 2.72 t/t relative to the conventional SAGD physics-core case. The largest sensitivities were associated with steam rate, steam temperature, initial viscosity and permeability. Within the declared operating envelope, the results support the use of the framework as a pre-field screening tool and indicate that thermocable assistance should be interpreted primarily as spatial heat distribution control rather than as a field-validated production-improvement guarantee. Full article

Heavy crude oils exhibit complex rheological behavior governed by the interplay between temperature, pressure, and colloidal microstructure. In this work, the coupled influence of pressure and temperature on the viscoelastic response of five Mexican heavy crude oils was experimentally investigated under reservoir-relevant conditions. Steady and oscillatory shear measurements were performed at temperatures between 10 and 30 °C and at pressures ranging from atmospheric to 10.034 MPa. The results revealed pronounced shear-thinning behavior for all samples, with viscosity increasing systematically with pressure and decreasing strongly with temperature. Pressure effects were particularly significant at low temperatures, where enhanced elastic behavior and longer characteristic relaxation times were observed. Oscillatory measurements showed that pressurization shifted the viscoelastic crossover toward lower frequencies, indicating pressure-induced reinforcement of internal structures and reduced molecular mobility. The viscoelastic response was interpreted using a pressure-modified Arrhenius model, which successfully described the dependence of characteristic relaxation time on temperature and pressure. The fitted activation energies and activation volumes revealed systematic differences associated with crude oil composition and colloidal stability. Samples with lower resin-to-asphaltene ratios exhibited stronger pressure sensitivity and higher structural rigidity. The results demonstrate that pressure and temperature jointly control the relaxation dynamics and structural organization of heavy crude oils. These findings provide useful insights into flow assurance, transport, and production operations involving heavy crude systems under thermobaric conditions. Full article

Steam-assisted gravity drainage (SAGD) remains one of the most effective thermal enhanced-oil-recovery technologies for heavy-oil reservoirs; however, its energy performance is strongly constrained by wellbore heat losses, delayed steam-chamber development, and an increase in the steam–oil ratio (SOR) under deep or thermally unfavorable conditions. This study develops a physics-based computational digital-twin framework for thermocable-assisted SAGD and evaluates the influence of steam temperature, oil viscosity, permeability, reservoir depth, thermocable linear power, and heating time on oil production and SOR. The model couples wellbore heat transfer, temperature-dependent viscosity reduction, steam-chamber geometry, heat-loss compensation by an electrical thermocable, and production response. The results show that increasing steam temperature from 220 to 300 °C raises the oil rate by approximately 13–15% and reduces SOR from about 2.47 to 2.30. Increasing oil viscosity from 300 to 1500 mPa·s decreases the oil rate by more than 25% and increases SOR above 3.0. Thermocable integration increases the oil rate by approximately 8–12% in the base scenario and reduces SOR by 5–10% compared with conventional SAGD. The highest relative benefit is obtained in deeper reservoirs, where additional heat input compensates wellbore heat losses and stabilizes the temperature profile. These findings indicate that thermocable-assisted SAGD can improve energy efficiency and extend the practical operating window of thermal recovery in heavy-oil reservoirs. Full article

Deep high-temperature and high-pressure (HTHP) oil reservoirs have limited experimental MMP data, large differences between reservoir and saturation pressures, low gas–oil ratios, and pressure-sensitive CO₂–oil phase behavior, which make both minimum miscibility pressure (MMP) prediction and miscibility-mechanism identification challenging. To address these gaps, this study determines the MMP of a CO₂–oil system by integrating slim-tube experiments, empirical formula methods, the Multiple Mixed-Cell (MMC) method, the Method of Characteristics (MOC), compositional numerical simulation, and three intelligent algorithm models (GWO-RBF, GWO-LSSVM, and GWO-SVM). The slim-tube MMP of 44.13 MPa at 140 °C is used as the experimental reference for comparing prediction errors, whereas PVTsim and literature data are used for consistency checks and model benchmarking. The results show that when the injected CO₂ mole fraction exceeds 0.88, the formation oil under original reservoir conditions cannot achieve first-contact miscibility with CO₂, and the maximum dissolved CO₂–oil molar ratio is 7.3:1. Supercritical CO₂ forms dual displacement mechanisms, including front-end vaporizing miscible drive and rear-end condensing miscible drive, but the dominant mechanism for this CO₂–oil system is vaporizing miscible drive. During the vaporizing gas drive, the CO₂ + N₂ + C₁ content in the liquid phase increases from less than 60% to nearly 90%, indicating significant CO₂ dissolution into oil and associated density and viscosity reduction; meanwhile, the C₇₊ content in the gas phase increases to nearly 10%, indicating extraction of heavy components. Relative to the slim-tube reference at 140 °C, the deviations of MMC, GWO-SVM, GWO-LSSVM, compositional numerical simulation, GWO-RBF, MOC, and empirical formula methods are 2.97%, 3.08%, 3.40%, 4.24%, 4.26%, 11.62%, and 19.74%, respectively. The MMC method is the most suitable approach for this specific HTHP oil system, while intelligent algorithms should be regarded as supplementary predictors whose reliability depends on training-domain coverage and independent validation. Full article

After long-term waterflooding in offshore oilfields, the remaining oil becomes highly dispersed and discontinuous. To address the limitations of classical waterflooding theory in describing the effects of microscopic oil occurrence and stress differences on oil-phase flow, this study investigated oil–water two-phase flow during heavy-oil waterflooding using core samples from the Bohai Oilfield. The evolution of the oil-phase starting pressure gradient at different water-cut stages was measured through core two-phase steady-state displacement experiments. By combining in situ core CT scanning with pore-scale phase-field simulations, the multi-form start-up mechanisms and microscopic causes of the oil phase were clarified. The fractal characteristics of the reservoir pore structure were further incorporated to establish a calculation method for the multi-form start-up resistance of the oil phase. The results show that, as the water cut increases, the starting pressure gradient of the oil phase exhibits a nonlinear increasing trend. At a water cut of 90%, the oil-phase starting pressure gradient is approximately 7–8 times that of the pure oil phase. Meanwhile, the oil phase gradually transforms from a continuous phase to a discontinuous phase, with a smaller pore radius and a larger surface area per unit volume. Owing to the Jamin effect, capillary force exerts a stronger influence on oil-phase flow, resulting in a significant increase in the starting pressure gradient during the ultra-high water-cut stage. These findings provide a pore-scale explanation for the increase in oil-phase starting pressure gradient during ultra-high water-cut waterflooding and offer a theoretical basis for the sustainable development of mature offshore oilfields. Full article

Nanoemulsions are thermodynamically unstable but kinetically stable colloidal dispersion systems with droplet sizes ranging from 20 to 500 nm. With their high specific surface area, excellent optical properties, tunable rheology, and remarkable penetration ability, these systems demonstrate enormous potential in enhanced oil recovery (EOR). This paper systematically reviews the significant advances in nanoemulsion characterization techniques and oil displacement mechanisms. The nanoemulsion characterization techniques are examined, covering a comprehensive multi-scale characterization system from particle size and distribution analysis (e.g., dynamic light scattering, laser diffraction), micro-morphology and structure visualization (e.g., transmission electron microscopy, atomic force microscopy), and interface and surface property characterization (e.g., interfacial tension measurement, zeta potential analysis) to stability and rheology assessment, as well as chemical composition and structure analysis. Furthermore, core mechanisms of nanoemulsions in oil displacement processes are briefly summarized, revealing multiple synergistic enhancement mechanisms including ultra-low interfacial tension and oil film stripping, rock wettability alteration, emulsification and viscosity reduction, improved fluid flow and injection pressure reduction. Finally, prospects for the potential application of nanoemulsion oil displacement technology in the development of low-permeability, tight, and heavy oil reservoirs are described by analyzing the current challenges such as unclear structure–activity relationships, full-chain stability (including storage, transport, injection, and reservoir aging), and environmental safety, and future research directions are pointed out, including clarifying structure–activity relationships, smart responsive system development, artificial intelligence-assisted design, and pilot-scale validation. Clarifying the link between nanoemulsion characterization techniques and oil displacement mechanisms is of significant academic and engineering value for promoting the transition from empirical application to rational design of related technologies. Full article

Addressing issues such as corrosion and the eccentric wear of metal tubing strings, low heating efficiency, and high operation and maintenance costs of lifting systems in heavy-oil extraction, core equipment comprising carbon-fiber-reinforced PEEK (Polyetheretherketone) multi-layer composite continuous tubing has been developed. This equipment integrates an embedded cable-laying system and an intelligent regulation module, establishing a rodless oil-extraction technology system suitable for heavy-oil reservoirs. This article systematically describes the process structure, preparation principle, core characteristics, and key parameters of this composite continuous tubing. By deriving an equivalent thermal-resistance model for the multi-layer structure and an unsteady-state heat-transfer equation, precise regulation of the wellbore temperature field is achieved. Combined with field tests at Well A in Jinghe Oilfield, the tubing’s effectiveness in reducing viscosity, increasing production, saving energy, and extending the operational cycle in heavy-oil extraction is verified. The results show that the carbon-fiber-reinforced PEEK composite continuous tubing possesses characteristics such as high strength, strong corrosion resistance, low friction, and high thermal insulation. When paired with a viscosity–temperature coupling regulation algorithm, the heating efficiency is improved by 40% compared to traditional electric heating rods. The efficiency ranges from 37% to 43% when the formation thermal conductivity fluctuates by ±20%. Field applications have achieved a 230% increase in daily oil production, a 30% reduction in system energy consumption, and an extension of the hot washing cycle to over 180 days. The development of this tubing breaks through the technical bottleneck of traditional metal tubing, providing a new material solution for the efficient and intelligent development of heavy-oil extraction, and has broad promotional value. Full article

Conventional thermal recovery techniques face challenges in low-permeability heavy oil reservoirs due to low recovery factors and poor economic viability. To address these challenges, low-temperature oxidation (LTO) during oxygen-reduced air flooding was employed to achieve in situ oil upgrading and enhance oil recovery. Static oxidation tests at oxygen concentrations of 5%, 10%, 15%, and 21% were designed to analyze the produced gas composition and the physical properties of the oil following oxidation. We further employed Differential Scanning Calorimetry (DSC) and Thermogravimetric (TG) analysis to evaluate the oxidation behavior of crude oil under the same oxygen concentration conditions. Finally, long-core displacement experiments were performed to assess how the oxygen concentration influences the recovery efficiency. The results showed that under the tested conditions, oxygen consumption exceeded CO₂ generation, indicating that low-temperature oxygen addition reactions (formation of oxygenated species) dominated over complete oxidation. As the oxygen concentration increased, the oxidized crude oil exhibited a higher viscosity. At higher oxygen concentrations (15% and 21%), the asphaltene content increased significantly, resulting in poorer fluidity. The activation energy in the LTO stage decreased with increasing oxygen concentration, as revealed by kinetic analysis over the range of 5% to 21%. The LTO stage dominated the crude oil oxidation process. However, the heat release during this stage was less affected by the oxygen concentration. Consequently, increasing the oxygen concentration contributed only marginally to elevating the reservoir temperature. For the studied reservoir, oxygen-reduced air flooding with a 5% oxygen concentration achieved a final recovery factor of 34.82%. This represented a 1.76% improvement over conventional air flooding, thereby enabling economically efficient reservoir development. Full article

The Ordos Basin hosts abundant lacustrine shale oil resources. Adequately retained hydrocarbons in source rocks, together with favorable mobility, are prerequisites for large-scale shale oil exploitation. Therefore, the quantitative characterization of retained hydrocarbon content and mobility is a core research focus in shale oil exploration and development. This study investigates Chang 7 shale with varying lithofacies and geochemical characteristics. Stepwise pyrolysis and pyrolysis gas chromatography–mass spectrometry (GC–MS) were applied to analyze retained hydrocarbons in different occurrence states, their compositions, and biomarkers. In addition, nuclear magnetic resonance (NMR) combined with CO₂ flooding experiments was conducted, and the collected products under different displacement pressures were analyzed using GC–MS. The aim was to quantitatively examine the variations in expelled oil volume, compositional differences during migration, and occurrence features of shale oil within reservoir micro-pores. The results show the following: (1) Organic-rich shale is characterized by higher proportions of light and medium hydrocarbons, lower heavy fractions, and elevated aromatic hydrocarbon content. In contrast, low-organic-carbon mudstone or siltstone contains more medium and heavy hydrocarbons, with lower light and aromatic fractions. The C13−/C14+ ratio increases with total organic carbon (TOC). (2) In black shale, oil displacement is mainly contributed by mesopores. At low pressures, oil expulsion is difficult and dominated by heavy hydrocarbons. When pressure reaches a threshold, the capillary-bound oil in micropores is released, increasing production and improving oil quality. Muddy siltstone shows higher displacement efficiency than black shale, with contributions from pores of all sizes. At low pressures, its expelled oil volume is larger and lighter than that of black shale. With increasing pressure, the oil yield rises significantly, and medium–large pores produce heavier fractions compared with micropores, likely because light hydrocarbons preferentially enter micropores and are less prone to dissipation. (3) The main controlling factors for shale oil enrichment include retained hydrocarbon content, mobile hydrocarbon fraction, fluidity, and engineering-related parameters. Thick shale layers with high organic matter abundance, high proportions of light–medium hydrocarbons, and favorable porosity–permeability conditions, as well as interbedded siltstone, are enriched in mobile hydrocarbons. Full article