Search Results (554)

Enhanced oil recovery (EOR) is a crucial technology for improving crude oil recovery; it extracts residual oil from reservoirs through chemical, physical, or biological methods, thereby further increasing recovery rates after secondary recovery. Biosurfactants, particularly lipopeptides, have become a research focus in the field of EOR due to their excellent properties. However, existing studies have mainly concentrated on their production and characterization, while systematic investigation into their deactivation mechanisms and stability limits remains lacking at the molecular level. This study integrates density functional theory (DFT), ab initio molecular dynamics (AIMD), and classical molecular dynamics (MD) simulations to systematically reveal the hydrolysis mechanisms and stability boundaries of lipopeptide model molecules under high-temperature and high-salinity reservoir conditions from a multiscale perspective. DFT calculations show significant differences in the energy barriers among different hydrolysis sites in lipopeptide molecules, with side-chain structure being a key factor influencing amide bond hydrolysis. Metal ions present in reservoir environments (Na⁺, K⁺, Ca²⁺, Mg²⁺), particularly divalent ones (Ca²⁺, Mg²⁺), can act as catalysts to reduce the hydrolysis energy barrier. Electronic structure analysis reveals that the catalytic effect originates from the polarization of the carbonyl oxygen by metal ions, weakening the covalent character of the C=O bond. AIMD simulations reveal that only Ca²⁺ can specifically activate the hydrolysis of lipopeptide molecules at certain distances (critical distance), while other cations (e.g., Mg²⁺, K⁺, Na⁺) do not exhibit similar catalytic activity. MD simulations further demonstrate that Ca²⁺ ion concentration and temperature are the dominant factors influencing Ca²⁺ permeation toward hydrolysis sites (limit distance), with other ions having a weaker effect. By systematically simulating lipopeptide behavior under varying temperature and ion concentration conditions, a catalytic hydrolysis criterion based on the effective distance of Ca²⁺ interaction (i.e., limit distance ≤ critical distance) is established through multiscale simulation, and the performance boundaries of its temperature and salt tolerance are preliminarily defined. This study provides a theoretical basis and quantitative design guidance for the applicability of lipopeptide-based biosurfactants in high-temperature and high-salinity reservoirs. Full article

Fractured shale oil reservoirs possess ultra-tight matrix pores and suffer unsatisfactory oil recovery under conventional exploitation, while systematic comparisons among CO₂ flooding, CO₂/CH₄ mixed gas flooding, and multi-component thermal fluid (MTF) flooding remain insufficient for guiding field-parameter design. This work establishes a matrix–fracture coupled dual-porosity compositional model and adopts a single-variable method to quantitatively clarify how injection composition, reservoir permeability, injection pressure, and temperature govern sweep efficiency and the oil recovery factor, as well as the synergistic EOR mechanisms of different displacement fluids. The results show that CH₄ acts as a weak active component with limited crude-oil-swelling and displacement capacities; MTF yields the maximum recovery via thermal viscosity reduction, molecular diffusion, and crude oil swelling, whereas pure CO₂ is reported to have comprehensive cost advantages according to field-scale practical experience (no quantitative techno-economic calculation is carried out in this work). An injection miscibility threshold of 20–30 MPa is identified, with declining incremental oil yield beyond this range. According to published engineering observations, excessively high injection temperatures may trigger liquid-phase permeability impairment, which is not captured in the present model. The oil recovery factor positively correlates with permeability within 0.02–0.1 mD, and volumetric fracturing is indispensable for ultra-low-permeability matrices to expand seepage pathways. This study delivers quantitative theoretical references for displacing-agent screening and injection–production parameter optimization in fractured shale oil reservoirs. Full article

Middle-phase (Winsor III) microemulsion flooding is a promising technique for enhanced oil recovery (EOR). However, the presence of natural polar components in crude oil and varying reservoir salinity complicate the formulation of optimal microemulsion systems. This study experimentally investigates the effects of salinity and organic acids (lauric acid and caprylic acid) on the phase behavior of a microemulsion system composed of sodium dodecyl sulfonate (SDS), n-butanol, and different oils. Phase behavior experiments revealed that the optimal salinity window for middle-phase formation increases with the carbon number of the oil phase, expanding from 3–6.6 to 4–8.5 and 6–11.8 g/100 mL for octane, decane, and dodecane, respectively. The addition of polar acids was found to narrow this optimal salinity range; in particular, for decane, an increase in lauric acid concentration from 0.1% to 0.9% narrowed the salinity window from 4–8 to 4–6 g/100 mL, making the microemulsion systems more sensitive to salinity changes. Subsequent core flooding experiments demonstrated that the presence of polar components enhances the ultimate oil recovery, with higher acid concentrations leading to faster production rates. Furthermore, the EOR performance was shown to be highly dependent on salinity, peaking within the optimal salinity range that promotes a stable Winsor III microemulsion, leading to an ultimate recovery as high as 68.8%. These findings provide crucial insights for designing robust surfactant formulations for EOR in reservoirs containing polar crude oils. Full article

The Block MZ features tight reservoir physical properties and poor interlayer connectivity, making conventional injection-production patterns ineffective for formation energy supplementation. Although high initial production can be achieved after fracturing, stable production is difficult to maintain, resulting in a low ultimate recovery factor. To improve reserve utilization, two rounds of well pattern infilling and well adjustment have been implemented in the block, reducing the well spacing from the original 400 m to less than 50 m. The reservoir development has experienced three stages: depletion development, water huff and puff, and water flooding combined with fracturing. Nevertheless, the current recovery degree remains only approximately 7.0%. No obvious high-pressure main fractures are identified during the drilling, logging, and fracturing operations of infill wells, indicating that a large amount of remaining oil within the well spacing of 50–100 m has not been effectively produced. To further enhance the recovery factor and remaining oil producing degree of the mature tight oil reservoir in Block MZ, a novel combined fracturing technology dominated by pre-CO₂ injection, temporary plugging and diversion, and volume fracturing is innovatively proposed with the well group taken as the overall production enhancement unit. This technology effectively improves fracture complexity and expands the CO₂ sweep volume. Field application results demonstrate that the proposed technology can not only boost the production of a single well but also realize collaborative production enhancement of the entire well group. Compared with the conventional volume fracturing adopted in the early stage, the effective influencing radius of the well group is expanded from 50–150 m to 200–350 m, and the number of affected wells increases from 4 to 6–7. The average daily oil increment per well in the initial 90 days rises from 2.4 t/d to 8.1 t/d, and the average cumulative oil increment per well during the natural flow stage increases significantly from 67 t to 692 t. The remarkable production enhancement effect provides a novel technical approach for EOR (enhanced oil recovery) in mature tight oil blocks. Full article

Tight conglomerate reservoirs in the Mahu area are characterized by strong heterogeneity, complex fracture–matrix interactions, and rapid pressure depletion after volumetric fracturing, which severely restricts the sustainable production of horizontal wells. To clarify the applicability of post-fracturing energy replenishment and enhanced oil recovery strategies, this study establishes single-fracture and field-scale numerical models for tight conglomerate reservoirs and systematically investigates the effects of gas injection timing, injection volume, fracture conductivity, injection media, gas–water ratio, and well-pattern cooperation on huff-n-puff performance. The results show that immediate gas injection after fracturing is not the optimal strategy because the injected gas mainly migrates through hydraulic fractures and has limited contact with matrix oil. For the base-case single-fracture model, a favorable injection timing was obtained when oil production entered a slow-decline stage and the reservoir pressure decreased to approximately 3–4 MPa below the bubble-point pressure, resulting in a simulated recovery-factor increase of 12.3% relative to the reference case. CO₂ shows strong advantages in oil swelling, viscosity reduction, diffusion, and extraction, whereas water injection provides more effective pressure maintenance. Therefore, a gas–water synergistic huff-n-puff mode can simultaneously improve matrix oil mobilization and reservoir energy replenishment. The optimal gas–water ratio should be dynamically adjusted during different cycles, with a higher CO₂ proportion in the early stage and an increased water slug proportion in later cycles to compensate for pressure depletion. At the field scale, a cooperative scheme of edge-water injection and central gas injection is proposed. Edge-water injection forms a high-pressure barrier that suppresses gas channeling, extends CO₂ retention time, and promotes deeper gas migration into the matrix. Field-scale simulation results indicate that this scheme increases the simulated cumulative oil production by 6.9% compared with the reference scheme. This study provides a practical gas–water synergistic development strategy for improving oil recovery in Mahu and similar tight conglomerate reservoirs. Full article

Understanding pore-scale interactions among CO₂, the aqueous phase, and heavy oil is crucial for optimizing surfactant-assisted CO₂-enhanced oil recovery. In this study, a three-phase volume-of-fluid (VOF) framework is established in OpenFOAM to simulate immiscible displacement in two-dimensional porous media composed of circular solid grains. Two pore geometries are considered: a relatively uniform geometry and a preferential-channel geometry designed to promote early breakthrough. Sixteen injection schemes are compared, including pure CO₂ flooding, ordinary-water flooding, surfactant–water flooding, aqueous-phase preflush followed by CO₂ injection, and cyclic aqueous-phase/CO₂ injection with different aqueous-slug durations and switching frequencies. The effects of pore geometry, injection strategy, capillary number, viscosity ratio, interfacial tension, and wettability are evaluated using pore-volume-normalized oil recovery, breakthrough PV (the ratio of injected volume to pore volume), cumulative injected CO₂ PV at breakthrough, and phase-distribution indicators. The results show that pore geometry strongly affects macroscopic sweep and breakthrough behavior. In the preferential-channel geometry, pure CO₂ flooding and continuous ordinary-water flooding suffer from early breakthrough and poor sweep, whereas continuous surfactant–water flooding maintains high recovery because reduced oil–water interfacial tension and a more water-wet wall condition promote oil-film detachment and residual-oil mobilization. At 2.5 injected PV, the high-frequency short-slug and 1 s surfactant–water cyclic schemes give the highest or near-highest recovery in the relatively uniform geometry, while continuous surfactant–water flooding remains the highest-recovery scheme in the preferential-channel geometry. Considering the higher chemical demand of continuous surfactant injection and the carbon-utilization objective of CO₂-EOR, the combined surfactant–water/CO₂ schemes are evaluated to clarify the coupling between surfactant-induced oil mobilization and CO₂ displacement. Surfactant–water preflush followed by CO₂ injection becomes more effective as the preflush duration increases, and its recovery advantage over ordinary-water preflush is especially large in the preferential-channel geometry. However, the increase in CO₂ breakthrough PV in this geometry is limited compared with the recovery increment, indicating that the main benefit of surfactant–water is not only delayed gas breakthrough but also enhanced microscopic oil mobilization in poorly swept regions. Increasing the switching frequency slightly improves the cyclic response in the relatively uniform geometry under the tested schedules, whereas all cyclic schemes remain strongly constrained by reconnection with the dominant gas pathway in the preferential-channel geometry. Within the present idealized immiscible VOF model, these comparisons provide a controlled pore-scale comparison for distinguishing surfactant-induced residual-oil mobilization from CO₂ gas-channeling effects in heavy-oil porous media. Full article

CO₂ flooding plays a crucial role in enhancing oil recovery (EOR) in heterogeneous reservoirs; however, the reservoir’s vertical rhythmic characteristics and permeability gradients significantly influence the flooding efficiency. Unlike homogeneous reservoirs, CO₂ migration in heterogeneous reservoirs is jointly controlled by gravitational overburden and differences in flow conditions, which can easily lead to gas short-circuiting and the formation of dominant flow paths, thereby reducing the degree of crude oil mobilization. However, systematic research on the mechanisms of CO₂ flooding under different rhythm types and permeability difference remains relatively scarce. In this study, two-dimensional large-scale physical model experiments were conducted using stratified core plates with a planar size of 30 × 30 cm² and a single-layer thickness of 1 cm. The experiments were performed at 70 °C and 18 MPa, corresponding to the target reservoir conditions, with CO₂ injected from the inlet side and outlet pressure controlled by a backpressure valve. Under these conditions, CO₂ remained in the supercritical state during displacement. These experiments were designed to comparatively investigate the effects of reservoir rhythm and permeability contrast on pressure distribution, CO₂ migration patterns, and crude oil mobilization. The study elucidated the mechanisms by which reservoir heterogeneity influences the effectiveness of CO₂ flooding. The results show that the positive rhythmic unit delays upward CO₂ migration and gas breakthrough because of the low-permeability top layer, resulting in the highest ultimate oil recovery of 73.35%. In contrast, the reverse rhythmic unit promotes rapid CO₂ breakthrough through the high-permeability top layer and forms dominant flow paths, causing insufficient mobilization of the middle and bottom layers and yielding the lowest oil recovery of 51.03%. In the sandwich-type rhythmic unit (low–high–low permeability configuration), the interaction between the high-permeability middle layer and gravity override enhances mobilization in the top and middle layers, whereas oil mobilization in the bottom layer remains limited. Under interlayer conditions, increasing the permeability contrast from three-fold to five-fold strengthens preferential flow in the high-permeability layer and reduces oil recovery from 65.58% to 60.99%. Full article

Water-based enhanced oil recovery (EOR) techniques continue to attract interest because of their technical practicality and economic feasibility. Hybrid low-salinity surfactant flooding is a promising EOR strategy for carbonate reservoirs; however, the coupled effects of low-salinity brine, surfactant addition, wettability alteration, electrostatic modification, and capillary pressure reduction remain difficult to isolate. This study investigates hybrid low-salinity surfactant flooding in restored tight carbonate cores using integrated experimental measurements and core-scale numerical modeling. The experimental workflow included oil–water interfacial tension (IFT), zeta potential, contact angle measurements using a custom-designed HPHT imbibition cell, and reservoir-condition HPHT coreflooding under sequential and standalone injection schemes. The sequential flood evaluated the transition from seawater (SW) to 1%diluted seawater (1%dSW) and then to 1%dSW+A-1 surfactant, while standalone floods assessed the direct displacement performance of 1%dSW and 1%dSW+A-1. Dilution from SW to 1%dSW increased IFT from approximately 10.2 to 14.9 mN/m, indicating that the recovery improvement during 1%dSW injection was not caused by IFT reduction. Instead, zeta potential and contact angle results indicated progressive electrostatic modification and wettability alteration toward a less oil-wet state. The contact angle decreased from approximately 123° for SW to 101° for 1%dSW and further to 84° after A-1 addition. In contrast, 1%dSW+A-1 reduced IFT sharply to approximately 0.178 mN/m at 0.2 wt%, lowering the estimated capillary pressure magnitude and weakening capillary trapping. Sequential coreflooding showed that SW recovered 42.65% OOIP, followed by an additional 24.21% OOIP from 1%dSW and 9.11% OOIP from 1%dSW+A-1. Standalone 1%dSW and 1%dSW+A-1 recovered approximately 58.44% and 65.82% OOIP, respectively. Core-scale models reproduced the main recovery and pressure drop trends using zeta potential-guided relative permeability and capillary pressure functions supported by surface complexation modeling concepts. Overall, 1%dSW+A-1 improved oil displacement through a synergistic mechanism in which low-salinity brine stabilized the water film and altered wettability, while A-1 surfactant reduced IFT and weakened capillary trapping. The integrated experimental and modeling workflow provides a mechanistic basis for evaluating hybrid low-salinity surfactant flooding and for linking laboratory-measured interfacial properties to effective core-scale rock–fluid functions. Full article

High-temperature and high-salinity reservoirs (typically referring here to temperatures ≥ 100 °C and salinities > 100 g/L) impose stringent requirements on chemical flooding and profile-control agents, particularly in terms of thermal stability, salt tolerance, injectivity, and environmental compatibility. In this study, a bio-based composite mobility-control and oil-displacement system was developed by combining carbonized corn-straw particles with the biopolymer scleroglucan. Corn-straw biomass particles were prepared by pyrolysis at 500 °C followed by ball milling for 2 h. Their particle-size distribution, elemental composition, and suspension stability were characterized, and the rheological behavior, thermal and salt tolerance, long-term aging stability, injectivity, plugging performance, and enhanced-oil-recovery efficiency of the composite system were evaluated systematically. The average particle size decreased from 25.6 μm for mechanically ground straw to 2.8 μm after carbonization and ball milling. The H/C atomic ratio of the carbonized particles was 0.31, indicating enhanced aromatization and structural stability. A scleroglucan concentration of 1000 ppm provided a suspension rate of 97%, balancing suspension stability and chemical dosage. The composite system maintained stable viscosity and viscoelasticity from 30 to 130 °C in deionized water, saturated NaCl solution, and saturated CaCl₂ solution, with viscosity loss below 10%. After sealed anaerobic aging at 100 °C for 28 days, the viscosity retention remained above 90%. Sand-pack tests showed stable injectivity in media with permeabilities of 1235 and 2064 mD and a plugging efficiency of 95.7% in a 2846 mD model. In oil-displacement experiments, the composite system increased the final recovery factor from 46.6% for scleroglucan flooding alone to 53.3%, corresponding to an additional 6.7 percentage points. These results demonstrate that the carbonized biomass particle-scleroglucan system has promising thermal stability, salt tolerance, plugging capacity, and oil-displacement performance, providing a potential green strategy for mobility control in harsh reservoir environments. Full article

Polymer flooding is one of the most widely implemented chemical-enhanced oil recovery (EOR) techniques for improving sweep efficiency and mobilizing residual oil in mature reservoirs. However, the performance of partially hydrolyzed polyacrylamide (HPAM) flooding is strongly influenced by reservoir temperature, formation water salinity, and polymer concentration, particularly in carbonate formations where harsh reservoir conditions may significantly reduce polymer effectiveness. In this study, laboratory core flooding experiments combined with Response Surface Methodology (RSM) and Analysis of Variance (ANOVA) were employed to systematically investigate and optimize the effects of temperature, HPAM concentration, and salinity on the incremental recovery factor (RF) of matrix-type carbonate core samples. A total of 45 flooding experiments were conducted under temperatures ranging from 20 to 80 °C, polymer concentrations between 500 and 2500 ppm, and salinities from 1000 to 100,000 ppm. A highly significant quadratic model was developed, exhibiting excellent predictive capability (R² = 0.9991, p < 0.0001) and accurately describing the individual and interactive effects of the investigated variables. Among the examined parameters, HPAM concentration was identified as the dominant factor controlling flooding performance, followed by salinity and temperature. The incremental recovery factor varied from approximately 6 to 19%, and optimization analysis predicted a maximum RF of 18.82% at 20 °C, 2500 ppm HPAM concentration, and 10,000 ppm salinity. Furthermore, optimization under high-temperature and high-salinity conditions revealed that a minimum HPAM concentration of about 2150 ppm is required to maintain RF values above 10%. The proposed experimental–statistical framework provides a reliable tool for predicting and optimizing HPAM flooding performance and offers practical guidance for polymer flooding design in carbonate reservoirs. Full article

Channeling control remains the most critical challenge in fluid injection for enhanced oil recovery (EOR). Polymer gels are widely applied in channeling control due to their capability to alter the permeability of flow channels. However, high temperature and high salinity lead to low efficiency of gels, causing injected fluid to flow away through high-permeability channels and thereby hindering petroleum production. To address this, this study developed and applied a new gel, synergistically combining a tailored temperature-/salt-resistant co-polymer with an optimized cross-linker. Laboratory evaluation experiments demonstrated that this gel could resist high temperature (>130 °C) and high salinity (>20 × 10⁴ mg/L), exhibit remarkable stability (gel dehydration rate <20% after 100 days aging), and achieve a plugging rate exceeding 98%. A pilot field case, designed based on laboratory outcomes, was successfully implemented in the Gasikule Block of the Qinghai Oilfield. The field validation indicated that this advanced gel system effectively restored reservoir pressure, thereby establishing critical prerequisites for subsequent EOR operations. This study advances the application of polymer gels in channeling control, demonstrating their superior performance and broad perspective in enhancing channeling control. Full article

Surfactant adsorption onto reservoir rocks remains a critical challenge in chemical enhanced oil recovery (cEOR), as it directly impacts flooding efficiency and chemical costs. This study presents a comprehensive scientometric analysis of research on surfactant adsorption for EOR applications over the period 2005–2025. Based on the Scopus database, 877 publications accounting for more than 22,100 citations were retrieved and analyzed to map the intellectual and conceptual structure of this research field. VOSviewer 1.6.20 software was employed to generate keyword co-occurrence networks, author bibliographic coupling, and country-level contributions. The results reveal a strong growth in scientific output after 2016, with annual publications increasing from fewer than 30 papers per year before 2010 to more than 100 papers per year after 2021. “Enhanced Oil Recovery” (165 occurrences), “Adsorption” (101 occurrences), and “Surfactant” (88 occurrences) emerged as the most frequent and highly interconnected keywords. At the geographical level, China (29.4%), the United States (22.3%), and Iran (9.6%) were identified as the leading contributors, together accounting for more than 60% of the global research output. Bibliographic coupling analysis highlighted a core group of highly influential authors shaping the field through strong collaborative networks. Emerging themes such as nanoparticle-assisted EOR, wettability alteration, and low-salinity surfactant systems were identified as rapidly growing research frontiers. This scientometric analysis provides the first quantitative mapping dedicated specifically to adsorption phenomena in cEOR, while highlighting future opportunities for optimizing adsorption control strategies and improving reservoir performance. Full article

Conventional depletion development and waterflooding are often ineffective in tight oil reservoirs because of their ultra-low permeability, complex fracture–matrix architecture, and limited fluid mobility. Although inter-fracture CO₂ flooding has demonstrated considerable potential for enhanced oil recovery (EOR), the coupled effects of key operational parameters on reservoir pressure evolution, fracture–matrix mass transfer, and oil mobilization remain inadequately understood. In this study, a multi-component compositional simulation model, constrained by detailed geological characterization and calibrated through production history matching of the Yuan 284 block in the Changqing Oilfield, was developed to systematically evaluate the effects of CO₂ injection rate, injection–production time ratio, and shut-in duration on recovery performance and reservoir response. The results show that increasing the CO₂ injection rate from 1000 to 50,000 m³/d improves the recovery factor from 40.49% to 49.90%; however, the incremental recovery gain decreases markedly beyond 30,000 m³/d, which is aggravated by enhanced gas channeling through high-conductivity fracture pathways. Analysis of the injection–production time ratio indicates that an optimal ratio of 0.50 provides the best balance between reservoir energy replenishment and oil displacement efficiency, whereas excessively small ratios result in insufficient pressure support and reduced recovery. In contrast, extending the shut-in duration consistently lowers recovery performance by weakening fracture–matrix mass transfer and promoting pressure dissipation, demonstrating that immediate production following injection is more effective than prolonged soaking under the investigated conditions. The optimized operating scheme yields a recovery factor of 48.87%, substantially exceeding the representative waterflooding recovery level of 35.20%. These findings clarify the mechanisms controlling pressure maintenance, CO₂ utilization efficiency, and volumetric sweep during inter-fracture asynchronous CO₂ flooding, and provide both theoretical insights and practical guidance for the efficient development of ultra-low-permeability fractured tight oil reservoirs. 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