Search Results (127)

The Hadamengou gold deposit, hosted in the Precambrian metamorphic basement, is a super-large gold deposit occurring along the northern margin of the North China Craton. Despite extensive investigation, the genesis of the gold mineralization is poorly understood and remains highly debated. This study integrates a comprehensive dataset, including fluid inclusion microthermometry and C-H-O-S-Pb isotopes, to better constrain the genesis and ore-forming mechanism of the deposit. Hydrothermal mineralization can be divided into pyrite–potassium feldspar–quartz (Stage I), quartz–gold–pyrite–molybdenite (Stage II), quartz–gold–polymetallic sulfide (Stage III), and quartz–carbonate stages (Stage IV). Four types of primary fluid inclusions are identified, including pure CO₂-type, composite CO₂-H₂O-type, aqueous-type, and solid-daughter mineral-bearing-type inclusions. Microthermometric and compositional data reveal that the fluids were mesothermal to hypothermal, H₂O-dominated, and CO₂-rich fluids containing significant N₂ and low-to-moderate salinity, indicative of a magmatic–hydrothermal origin. Fluid inclusion assemblages further imply that the ore-forming fluids underwent fluid immiscibility, causing CO₂ effusion and significant changes in physicochemical conditions that destabilized gold bisulfide complexes. The hydrogen–oxygen isotopic compositions, moreover, support a dominant magmatic water source, with increasing meteoric water input during later stages. The carbon–oxygen isotopes are also consistent with a magmatic carbon source. Sulfur and lead isotopes collectively imply that ore-forming materials were derived from a hybrid crust–mantle magmatic reservoir, with minor contribution from the country rocks. By synthesizing temporal–spatial relationships between magmatic activity and ore formation, and the regional tectonic evolution, we suggest that the Hadamengou is an intrusion-related magmatic–hydrothermal lode gold deposit. It is genetically associated with multi-stage magmatism induced by crust–mantle interaction, which developed within the extensional tectonic regimes. Full article

The investigation of fluid flow channeling and viscous fingering during immiscible two-phase displacement in subsurface porous media is crucial for optimizing CO₂ geological sequestration and improving hydrocarbon recovery. In this study, we develop a pore-scale numerical framework for unsteady state immiscible displacement based on a body-centered cubic percolation network, which explicitly captures the coupled effects of pore-scale heterogeneity, capillary number, and unfavorable viscosity ratio on flow channeling and viscous fingering. The simulations reveal that viscous fingering and flow channeling preferentially occur along overlapping high conductivity pathways that conform to the minimum energy dissipation principle. Along these preferential routes, the local balance between viscous and capillary forces governs the stability of the two-phase interface and gives rise to distinct patterns and intensities of viscous fingering in the invading phase. Building on these insights, we establish a theoretical framework that quantifies how the critical pore radius and capillary number control the onset and growth of interfacial instabilities during immiscible displacement. The model demonstrates that lowering the injection rate, and hence, the effective capillary number, suppresses viscous fingering, leading to more stable displacement fronts. These findings provide practical guidance for the design of injection schemes, helping to enhance oil and gas recovery and improve the storage efficiency and security of CO₂ geological sequestration projects. Full article

Gas injection is a well-established method for enhancing oil recovery by improving oil mobility, primarily through viscosity reduction. While its application in heavy oil reservoirs is extensively studied, the specific impact of carbon dioxide (CO₂) injection pressure on fluid viscosity reduction and the ultimate recovery factor from light oil reservoirs has not been fully investigated. To address this gap, this experimental study systematically explores the effects of CO₂ injection pressure and reservoir permeability on light oil recovery. This study conducted miscible, near-miscible, and immiscible gas injection experiments on two core samples with distinct permeabilities (13.4 md and 28 md), each saturated with light oil. CO₂ was injected at five different pressures, including conditions ranging from immiscible to initial reservoir pressure. The primary metrics for evaluation were the recovery factor (measured at gas breakthrough, end of injection, and abandonment pressure) and the viscosity reduction of the produced oil. The results conclusively demonstrate that CO₂ injection significantly enhances light oil production. A direct proportional relationship was established between both the injection pressure and the recovery factor and between permeability and overall oil production at the gas breakthrough. However, a key finding was the inverse relationship observed between permeability and viscosity reduction: the lower-permeability sample (13.4 md) consistently exhibited a greater percentage of viscosity reduction across all injection pressures than the higher-permeability sample (28 md). This unexpected trend is aligned with the inverse relationship between the permeability and the recovery factor after the gas breakthrough. This outcome suggests that enhanced CO₂ solubility, driven by higher confinement pressures within the nanopores of the lower-permeability rock, promotes a localized, near-miscible state. This effect was even evident during immiscible injection, where the low-permeability sample showed a noticeable viscosity reduction and superior long-term production. These findings highlight the critical role of pore-scale confinement in governing CO₂ miscibility and its associated viscosity reduction, which should be incorporated into enhanced oil recovery design for unconventional reservoirs. Full article

A large, low-grade Fe–Ti–V oxide deposit occurs within the Xiaohaizi Ultramafic–Mafic intrusion. Based on petrographic observations and electron probe microanalysis (EPMA) of amphibole, this study examines the magmatic evolution and ore-forming processes of the intrusion through analyses of amphibole occurrence, mineral chemistry, and crystallization conditions. Five textural types of amphibole were identified: (i) inclusions, (ii) co-crystallization with early silicates, (iii) reaction rims, (iv) co-crystallization with late Fe–Ti oxides, and (v) phenocrysts. The amphiboles are calcic varieties, mainly composed of magnesio-hastingsite, kaersutite, and tschermakite. Crystallization occurred at temperatures of 901–1013 °C and pressures of 254–424 MPa, with ΔNNO values ranging from −1.3 to +2.8 and estimated melt H₂O contents of 3.3–7.1 wt.%, corresponding to crystallization depths of 9.6–16.0 km. Importantly, the crystallization interval of the Fe–Ti oxides is defined by these amphibole-assemblage conditions, as evidenced by their direct intergrowth. Integration of mineralogical and geochemical data indicates that the Xiaohaizi intrusion underwent four distinct stages of magmatic evolution. During these stages, the crystallization of Fe–Ti oxides was accompanied by notable fluctuations in oxygen fugacity and melt water content. These results suggest that fractional crystallization played a dominant role in ore formation, with possible late-stage liquid immiscibility observed at the mineral scale. Overall, this study proposes that the Xiaohaizi Fe–Ti–V oxide deposit represents a magmatic conduit-type ore-forming system developed within a crystal mush. The enrichment of Fe–Ti oxides is strongly associated with hydrous melts and elevated oxygen fugacity conditions. Full article

During the process of CO₂ displacing shear-thinning oil, the occurrence of fingering is a key factor contributing to a reduction in both displacement and sequestration efficiency. Existing studies typically use the average viscosity to calculate the viscosity ratio M for shear-thinning oil, overlooking the non-uniform viscosity distribution resulting from uneven shear stress. Consequently, a phase diagram based on M fails to accurately capture the underlying mechanism influencing fingering. We investigate the influence of shear-thinning on fingering patterns by analyzing viscosity heterogeneity during immiscible CO₂ flooding in porous media. The results showed the following: (1) An increase in zero-shear viscosity (μ₀) resulted in a greater viscosity difference between the two phases, which intensified interface instability, and the power-law index (n) diminished the shear-thinning effect, promoted fingering formation, and significantly reduced displacement efficiency, with a maximum reduction of 28.6% observed in this study. (2) Shear-thinning oil was more prone to capillary fingering compared to Newtonian oil under the same capillary number Ca and viscosity ratio M. (3) Intense pressure fluctuations at the displacement front combined with non-uniform viscosity distribution exacerbate interfacial instability and make shear-thinning oil more prone to capillary fingering. This study provides guidance for optimizing displacement strategies for shear-thinning fluids and advancing the practical implementation of CO₂ flooding technology. Full article

The environmental impact of petroleum-based plastics has accelerated the search for sustainable alternatives in food packaging. Polylactic acid (PLA), a biobased and compostable polymer, is among the most promising candidates, yet its inherent brittleness and poor moisture barrier limit its application in high-humidity contexts such as dairy packaging. This study investigates immiscible PLA/poly(butylene succinate-co-adipate) (PBSA) blend films as potential biobased packaging materials for perishable foods. Even if these blends have been already studied, limited attention has been given to the systematic characterization of the baseline barrier properties of unmodified PLA/PBSA blends in contact with liquid dairy products. Four blend ratios (PLA/PBSA = 30/70, 40/60, 50/50, 60/40 wt%) were prepared via micro-compounding and compression molding. The films were characterized through melt flow analysis, FTIR, SEM, DSC, DMTA, and tensile testing to evaluate their thermal, morphological, and mechanical properties. Crucially, moisture barrier performance was assessed under simulated dairy conditions by sealing fresh whey at 4 °C and monitoring weight loss over 30 days. Results revealed that while tensile strength and storage modulus (E’) decreased nearly linearly with increasing PBSA content, elongation at break exhibited a non-linear trend, highlighting the complex interplay between blend morphology and mechanical behavior. The study provides a baseline understanding of neat PLA/PBSA blends in contact with liquid dairy, identifying the most promising formulations for future scale-up. These findings contribute to the development of biodegradable packaging systems tailored for refrigerated, high-moisture food applications Full article

Viscous fingering is an interfacial instability that occurs when multiple fluids displace each other. This research focuses on the interface instability during immiscible displacement of shear-thinning fluids by CO₂. By controlling velocity and applying heat to the upper and lower walls, the influence of velocity and temperature on viscous fingering during CO₂ displacement is investigated. Moreover, by modifying the geometric conditions of the classical Hele-Shaw cells (HSCs), a novel analytical framework for viscous fingering is proposed. The primary methodology involves implementing a minute depth gradient distribution within the HSC, coupled with the Volume of Fluid (VOF) multiphase model, which systematically reveals the dynamic suppression mechanism of shear-thinning effects on viscous finger bifurcation. The results indicate that temperature elevation leads to increased sweep efficiency, reduced residual non-Newtonian fluid in the displaced zone, and enhanced displacement efficiency. Furthermore, increased velocity leads to reduced sweep efficiency. However, at lower velocities, displacement efficiency remains relatively low due to limited sweep coverage. The direction and magnitude of the depth gradient significantly govern the morphology and extension length of viscous fingering. Both positive and negative depth gradients promote fingering development on their respective sides, as the gradient establishes anisotropic permeability that prioritizes flow pathways in specific orientations, thereby intensifying finger propagation. Full article

Skarn-type iron ore is economically significant, and numerous skarn ore deposits have been identified in the North China Craton. The newly discovered orbicular diorite in this region is distinguished from other analogous rocks due to the accumulation of large magnetite particles, which may shed new light on the genesis of this ore type. The magnetite in different parts of the orbicular structure exhibits distinct compositional differences. For example, magnetite at the edge has a small particle size (200 μm) and is associated with the minerals plagioclase and hornblende, indicating that it crystallized from normal diorite magma. By contrast, magnetite in the core has a relatively large particle size (>1000 μm), is associated with apatite and actinolite, and contains apatite inclusions as well as numerous pores. The size of magnetite in the mantle falls between that of the edge and the core. The syngenetic minerals of magnetite in the mantle include epidote and plagioclase. The magnetites in the cores of orbicules have a higher content of Ti, Al, Ni, Cr, Sc, Zn, Co, Ga, and Nb than those in the rim. The δ⁵⁶Fe value of the core magnetite (0.46‰–0.78‰) is much higher than that of the mantle and rim magnetite in orbicules. Moreover, the δ⁵⁶Fe value of magnetite increases as the V content of magnetite gradually decreases. This large iron isotope fractionation is likely driven by liquid immiscibility that forms iron-rich melts under high oxygen fugacity. The reaction between magma and carbonate xenoliths (Ca, Mg)CO₃ during magma migration generates abundant CO₂, which significantly increases the oxygen fugacity of the magmatic system. Under the action of CO₂ and other volatile components, liquid immiscibility occurs in the magma chamber, and Fe-rich oxide melts are formed by the melting of carbonate xenoliths. Iron oxides (Fe₃O₄/Fe₂O₃₎ will crystallize close to the liquidus due to high oxygen fugacity. These characteristics of magnetite in the Tanling orbicular diorite (Wuan, China) indicate that diorite magma reacts with carbonate xenoliths to form “Fe-rich melts”, and skarn iron deposits are probably formed by the reaction of intermediate-basic magma with carbonate rocks that generate such “Fe-rich melts”. A possible reaction is as follows: diorite magma + carbonate → (magnetite-actinolite-apatite) + garnet + epidote + feldspar + hornblende + CO₂↑. Full article

Accurately simulating immiscible counter-current flow is crucial for applications from geological ${\mathrm{CO}}_2$ storage to shale gas production, yet it remains a major challenge for conventional pore network models (PNMs), which are unable to handle the numerical instability of opposing flows. To address this critical gap, we developed a novel dynamic PNM that incorporates a ‘transition state’ algorithm. This method successfully eliminates the spurious meniscus oscillations that hinder traditional models, enabling robust simulation of the complete counter-current process. Using this model, we quantify the profound impact of pore structure on flow efficiency. Our results demonstrate that increasing the pore size distribution uniformity (Weibull shape factor k from 0.5 to 3.0) extends the persistence of continuous air outflow pathways by more than six-fold (from 359 to over 2300 simulation steps). This leads to a quantifiable increase in the initial fluid exchange rate by nearly 10 times (from ${10}^{-11}$ to ${10}^{-10}$${\mathrm{m}}^3$/s) and a reduction in final residual air saturation by 53% (from 0.91 to 0.43). This work provides a tool for predicting and optimizing counter-current flow efficiency in subsurface engineering applications. Full article

Oil and gas reservoirs dominated by coarse clastic rocks, particularly conglomerates (including gravel sandstones), are commonly termed conglomerate reservoirs in both the domestic and international literature. Sandy conglomerate reservoirs generally have high thickness and high productivity per unit area, but because of their characteristics such as rapid lithology change, strong heterogeneity, low porosity, and low permeability, it is difficult to develop conventional waterflooding. There is an urgent need for an efficient development scheme for the giant sandy conglomerate reservoir. In this study, nuclear magnetic resonance (NMR) technology was employed to investigate the stratified injection-production strategy for large-scale sandy conglomerate reservoirs. Three representative cores from different strata were selected to perform CO₂ flooding and CO₂-water alternating gas (WAG) flooding experiments, respectively. The aim was to explore how different development methods affect the recovery efficiency of various core types and the distribution of remaining oil under miscible and immiscible pressure conditions. The results show that immiscible CO₂ flooding mainly displaces crude oil in large pores, and oil in micropores and mesopores is difficult to displace. After gas channeling, there is still a large area of residual oil “aggregate” in the core, and the recovery rate is low. Compared with medium-coarse sandstone, the strong heterogeneity of sandy conglomerates leads to early gas breakthrough and low recovery efficiency during gas flooding. Compared with CO₂ flooding, CO₂-WAG flooding can balance the micro-oil displacement effect between micropores and macropores, significantly improve the oil production in micropores and mesopores. Thus, CO₂-WAG flooding has a certain micropore “profile control” effect, which can delay the gas channeling and improve the core recovery efficiency of reservoirs, especially for the highly heterogeneous sandstone. Miscible CO₂ flooding can effectively extract the oil in the mesopores and micropores that immiscible CO₂ flooding is difficult to displace. The gas breakthrough is slower and the recovery is much higher in miscible CO₂-WAG flooding than that of immiscible one. Therefore, ensuring that the formation pressure is higher than the minimum miscible pressure to achieve miscible flooding is the key to reservoir stimulation. Full article

During the process of oil extraction, the urgent need for unconventional oil resources is driven by escalating global demand and the progressive depletion of conventional reserves. Shale oil represents a critical unconventional resource, with recovery efficiency being fundamentally constrained by the multiscale heterogeneity of shale reservoirs characterized by intricate networks of microscale fractures and nanoscale pores. To unravel pore structure impacts on microscopic transport phenomena, this study employed microfluidic chips replicating authentic shale pore architectures with pore depths as small as 200 nm to conduct immiscible flooding, constant volume depletion, and huff-n-puff experiments under representative reservoir conditions, with experiments reaching a maximum pressure of 40 MPa. The results show that large-pore and fine-throat structures create dual flow restrictions: the abrupt change in pore throat size amplifies the local flow resistance relative to the homogeneous structure, leading to a 78.09% decline in displacement velocity, while Jamin effect-induced capillary resistance reduces recovery efficiency, and even prevents some crude oil in the pore from being driven out. Slug flow occurred in the experiment, with calculated capillary numbers (Ca) of 0.0015 and 0.0026. This slug flow impedes microscopic transport efficiency, and lower Ca values yield more distinct liquid slugs. CO₂ exhibited effective extraction capabilities for light crude oil components, enriching residual heavy components that impeded subsequent extraction. When contact time was tripled under experimental conditions, this ultimately led to a 25.6% reduction in recovery rate. This investigation offers valuable insights into microscopic transport mechanisms within shale oil systems and provides practical guidance for optimizing shale reservoir development strategies. Full article

In this study, we present a novel and straightforward approach for the synthesis of copolymers and nanocomposites based on α- and β-pinene, employing an eco-friendly and cost-effective nano-reinforcing filler. The copolymers (α-co-β-P) were produced through cationic copolymerization, using AlCl₃ as a catalyst. The structural characterization of the resulting copolymer was validated through FT-IR, ¹H-NMR spectroscopy, and differential scanning calorimetry (DSC). The molecular weight of the obtained polymer is determined by Gel Permeation Chromatography (GPC) analysis and is about 4500 g/mol. Nanocomposites (α-co-β-P/Clay 2, 5, 8, and 10% by weight of nano-clay) were synthesized by combining clay and α-co-β-P copolymer in solution using ultrasonic irradiation. This ultrasound-assisted method was employed to enhance and assess the structural, morphological, and thermal properties of the pure copolymer. The morphology of the resultant nanocomposites was characterized using infrared spectroscopy (FT-IR), X-ray diffraction (XRD), scanning electron microscopy (SEM) and transmission electron microscopy (TEM). Thermogravimetric analysis (TGA) revealed that the nanocomposites exhibit a higher degradation temperature compared to the pure copolymer. The analyses provided evidence of the chemical modification of nano-clay layers and their uniform dispersion in the α-co-β-P copolymer matrix. Exfoliated structures were achieved for lower clay concentration (2% by weight), while intercalated structures and immiscible regions were observed for higher clay concentrations (5, 8, and 10% by weight). The antioxidant activity of α-pinene, β-pinene, and the obtained nanocomposites were studied using DPPH (2,2-diphenyl-1-picrylhydrazyl) as a model free-radical. The results demonstrate a significant antioxidant potential of the nanocomposites, showcasing their ability to effectively neutralize free-radicals. Finally, a novel procedure was devised for the rapid synthesis of copolymers and nanocomposites using α- and β-pinene. 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

CO₂ flooding technology has been established as a key technique that is both economically viable and environmentally sustainable, achieving enhanced oil recovery (EOR) while advancing CCUS objectives. This study addresses the challenge of optimizing CO₂ flooding well patterns in tight oil reservoirs through a geological–engineering integrated approach. A semi-analytical model incorporating startup pressure gradients and miscible/immiscible two-phase flow was developed to dynamically adjust injection intensity. An effective driving coefficient model considering reservoir heterogeneity and fracture orientation was proposed to determine well pattern boundaries. Field data from Blocks A and B were used to validate the models, with the results indicating optimal injection intensities of 0.39 t/d/m and 0.63 t/d/m, respectively. Numerical simulations confirmed that inverted five-spot patterns with well spacings of 240 m (Block A) and 260 m (Block B) achieved the highest incremental oil production (3621.6 t/well and 4213.1 t/well) while reducing the gas channeling risk by 35–47%. The proposed methodology provides a robust framework for enhancing recovery efficiency in low-permeability reservoirs under varying geological conditions. Full article

The Cuyu gold deposit in central Jilin Province in Northeast China is located in the eastern segment of the northern margin of the North China Craton (NCC), as well as the eastern segment of the Xing’an–Mongolian Orogenic Belt (XMOB). Gold ore-bodies are controlled by NW-trending faults and mainly occur in late Hercynian granodiorite. The mineralization process in the Cuyu deposit can be divided into three stages: quartz + coarse grained arsenopyrite + pyrite (stage I), quartz + sericite + pyrite + arsenopyrite + electrum + chalcopyrite + sphalerite (stage II), and quartz + calcite ± pyrite (stage III). Stage II is the most important for gold mineralization. We conducted analyses including petrography, microthermometry, laser Raman spectroscopy of fluid inclusions, and H–O–S–Pb isotopic analysis to elucidate the mineralization processes in the Cuyu deposit. Five types of primary fluid inclusions (FIs) are present in the hydrothermal quartz and calcite grains of the ore: liquid-rich two-phase aqueous fluid inclusions (L-type), vapor-rich two-phase aqueous fluid inclusions (V-type), CO₂-bearing two- or three-phase inclusions (C1-type), CO₂-rich two- or three-phase inclusions (C2-type), and pure CO₂ mono-phase inclusions (C3-type). From stages I to III, the fluid inclusion assemblages changed from L-, C2-, and C3-types to L-, V-, C1-, C2-, and C3-types and, finally, to L-types only. The corresponding homogenization temperatures for stages I to III were 242–326 °C, 202–298 °C, and 106–188 °C, and the salinities were 4.69–9.73, 1.63–7.30, and 1.39–3.53 wt.% NaCl equiv., respectively. The ore-forming fluid system evolved from a NaCl-H₂O-CO₂ ± CH₄ ± H₂S fluid system in stage I and II with immiscible characteristics to a homogeneous NaC-H₂O fluid system in stage III. Microthermometric data for stages I to III show a decreasing trend in homogenization temperatures and salinities. The mineral assemblages, fluid inclusions, and H–O–S–Pb isotopes indicate that the initial ore-forming fluids of stage I were exsolved from diorite porphyrite and characterized by a high temperature and low salinity. The addition of meteoric water in large quantities led to decreases in temperature and pressure, resulting in a NaCl-H₂O-CO₂ ± CH₄ ± H₂S fluid system with significant immiscibility in stage II, facilitating the deposition of gold and associated polymetallic sulfides. The Cuyu gold deposit has a similar ore genesis to those of gold deposits in the Jiapigou–Haigou gold belt (JHGB) of southeastern Jilin Province indicating potential for gold prospecting in the northwest-trending seam of the JHGB. Full article