Energy & Fuels最新文献

To address the limited understanding of microscopic displacement mechanisms of nanoemulsions in enhanced oil recovery, this study systematically investigated the microscale oil displacement behavior and patterns of a nanoemulsion using in situ computed tomography (CT) scanning technology, combined with performance evaluation and core flooding experiments. The results show that the nanoemulsion has a particle size distribution of 190–280 nm and can reduce the oil–water interfacial tension to the order of 10^–3 mN/m. It effectively emulsifies crude oil, reducing the emulsion droplet size to 0.72 μm, and alters wettability by decreasing the contact angle from 111.1° to 6.8°. Core flooding experiments reveal that the oil recovery during primary water flooding increases with a greater permeability contrast and higher displacement rates. In contrast, the recovery during the nanoemulsion flooding stage decreases with increasing permeability but increases with higher displacement rates. The subsequent water flooding stage shows reduced recovery as both the permeability contrast and displacement rate increase. In situ CT analysis indicates that primary water flooding mainly displaces oil along pore margins, while the nanoemulsion exhibits varying displacement efficiency across the pores of different scales, promoting oil phase dispersion and mobilization. Permeability contrast and displacement rate significantly influence the nanoemulsion’s effectiveness in different pore sizes, with lower permeability contrast and lower displacement rates proving more favorable for improving overall oil recovery. These findings provide valuable guidance for the design of nanoemulsion flooding in low-permeability reservoirs.

This study investigates the permeability of gas hydrate-bearing sediments based on nuclear magnetic resonance (NMR) transverse (or spin–spin) (T₂) relaxation measurements obtained from both pressure core samples and downhole logging in the Alaska North Slope. Seven core samples from the B1 sand (unit B)─the reservoir interval of a recent extended-duration gas production test under the JOGMEC-DOE-USGS Collaborative Gas Hydrate R&D Project in Alaska─were analyzed to measure T₂ distributions, grain size, and both effective and intrinsic permeabilities under in situ stress conditions. These data were used to evaluate the predictive accuracy of several NMR-based permeability models, including the Timur–Coates (TC) and Schlumberger-Doll Research (SDR) models, as well as the hydraulic radius model. Among these, the hydraulic radius model using laboratory based NMR signals exhibited the best agreement with laboratory-measured permeabilities in sand-rich hydrate-bearing sediments, highlighting its robustness and practical applicability without fitting parameters. The modified TC model performed well even with a fixed parameter (α = 0.6) using NMR signals of hydrate-bearing sediments, uniquely allows for intrinsic permeability prediction for simulating hydrate dissociation. In contrast, the TC and SDR models showed greater deviations. Moreover, since T₂ distributions after hydrate dissociation cannot be obtained in wireline logging, intrinsic permeability cannot be predicted in practice using the TC and SDR models. In fine-grained, hydrate-free seal layer samples, the SDR model outperformed the hydraulic radius model, which tended to overestimate laboratory-derived permeability by about an order of magnitude. These findings emphasize the importance of selecting appropriate models based on sediment type and reservoir conditions.

Accurate prediction of CO₂ solubility in brine is critical for evaluating the capacity and safety of geological carbon storage. While machine learning offers promise, existing studies are constrained by limited data sets that seldom encompass multicomponent impure CO₂ (containing CH₄ and N₂) in pure water and NaCl brine and often overlook computational efficiency in model optimization. To address these gaps, this study introduces a novel hybrid framework that integrates the LightGBM model with two advanced metaheuristic optimizers─the Ivy Algorithm (IVYA) and the Gaussian-mapping-enhanced Hiking Optimization Algorithm (GHOA). These optimizers are specifically employed to efficiently navigate the high-dimensional, nonconvex hyperparameter space of tree-based models, enhancing global search capability and mitigating premature convergence. Trained on a comprehensive impurity-inclusive brine database, the resulting IVYA-LightGBM model achieved the best performance on the test set (R² = 0.9920, MAE = 0.0008 mol/mol, AARD = 7.23%, RMSE = 0.0016 mol/mol) and demonstrated the most outstanding runtime performance and minimal memory consumption. SHAP analysis identified pressure, solute system, and temperature as the dominant factors governing solubility. This work highlights that coupling large-scale, complex-system data with next-generation optimization algorithms is key to developing highly accurate and efficient predictive tools for CO₂ sequestration.

Pt-loaded mesoporous carbon (Pt/MPC) is a representative unit of the cathode catalyst layer (CCL) in a proton exchange membrane fuel cell (PEMFC). However, the distribution and transport of water and protons in Pt/MPC, key to the electrochemical properties of the CCL, are largely unknown due to the lack of effective experimental probes at the mesoscale and the inadequacy of the homogeneity assumption within the volume-averaged modeling framework. The penetration of ionomers into mesopores also remains a controversial issue. Herein, molecular dynamics (MD) is employed to unveil the distribution of ionomers, water, and protons as well as the transport properties of water and protons in a Pt-loaded mesopore. The effects of functional groups and platinum oxide (PtO) are examined. The results indicate that ionomers do not penetrate into mesopores with a diameter of 4 nm. Both the quantity and connectivity of water and protons within the pore increase with the introduction of hydrophilic functional groups, as well as the PtO surface charge, which may be conducive to the performance. However, the presence of functional groups also restricts water and proton diffusion, which may be detrimental. These findings provide molecular insights for optimizing catalyst support materials in the PEMFC cathode.

Hydrate blockage represents a critical challenge to flow assurance in deep-water oil production. This research systematically investigates the effects of hydrocarbon chain length (nC6, nC10, nC14, nC15), water content and surfactant concentration on CH₄ hydrate formation and aggregation in oil-dominated emulsions. Experimental results reveal that hydrocarbon chain length not only affects hydrate growth rate and particle aggregation behavior but also influences CH₄ occupancy within the cage-like cavities of crystals. Shorter-chain hydrocarbons enhance CH₄ consumption rates and total CH₄ consumption. CH₄ consumption is strongly influenced by water content, and the emulsion containing 30 vol % water exhibits the highest total CH₄ consumption. Surfactant addition enhances hydrate growth while partially inhibiting particle aggregation. Notably, the system with 1.0 wt % sodium secondary alkyl sulfonate shows optimal slurry fluidity after 7 h. The inhibition of hydrate growth by n-tetradecane and n-pentadecane is affected by the chain length of liquid hydrocarbons. The presence of n-tetradecane and n-pentadecane reduces CH₄ occupancy in large cages, with particularly significant inhibition observed in systems containing n-pentadecane. These findings provide critical insights into hydrate management strategies for multiphase flow systems.

Oil exploration and development is increasingly advancing into deep, high-temperature, and high-pressure (HTHP) formations, making the control of drilling fluid solid-phase content extremely critical, which can effectively prevent the decline in reservoir permeability caused by solid phase invasion. To address the challenges of poor salt resistance, low thermal stability, and limited filtration control efficiency of filtration loss reducers used in high density saturated divalent brine drill-in fluids, a novel filtration loss reducer (THOD) was successfully synthesized using N,N-dimethylacrylamide (DMAA), diallyldimethylammonium chloride (DMDAAC) and the zwitterionic monomer 3-(1-vinyl-3-imidazolio)-propanesulfonate (SBVI) as raw materials. THOD exhibites excellent solubility and thermal stability in saturated CaCl₂ (1.4 g/cm³) and CaBr₂ (1.8 g/cm³) brines. Even at a dosage of 2%, the brine solutions remain clear and transparent without phase separation or flocculation, with the transmittances reaching 78% and 92.3%, respectively. The THOD polymer tightly fills the pores in the acid-soluble CaCO₃ filter cake skeleton through deformation and adsorption, forming a continuous, dense membrane that reduces brine filtration loss. After hot rolling at 190 °C for 16 h, the filtration loss of the drill-in fluid system could still be controlled within 15 mL. Furthermore, after hot rolling at 200 °C for 16 h, the saturated CaBr₂ brine system exhibited an API filtration loss of only 3.2 mL and an HTHP filtration loss of 15 mL. In addition, the filter cake formed by the drill-in fluids can be completely dissolved in 2% HCl solution, with a reservoir permeability recovery rate up to 85%, significantly improving the reservoir protection effect. The research results provide a new solution for the filtration control of high-temperature and high-density brine reservoir drilling fluids and is expected to provide technical support for safe and efficient drilling and reservoir protection under complex geological conditions, such as deep and ultradeep wells.

Fracturing fluid invasion in a marine–continental transitional shale gas reservoir could lead to low gas productivity and even groundwater contamination. However, the unique mineral composition and pore structure of transitional shales result in complex fracturing fluid imbibition behavior, which remains insufficiently understood compared with marine shales. In this study, nuclear magnetic resonance (NMR) techniques, including T₂ spectrum and T₁–T₂ 2D spectrum, were employed for in situ monitoring of spontaneous/forced imbibition on transitional shales with differing mineral compositions. Scanning electron microscopy (SEM) and X-ray diffraction (XRD) were used for mineral and pore structure characterization. The results showed that organic pores of transitional shales were underdeveloped, while clay mineral pores dominated and were concentrated in the 10–50 nm range. Kaolinite, a characteristic mineral with a 1:1 layered structure, enhanced pore connectivity through lamellar and intercrystalline fractures, promoted fluid access to 10–100 nm pores, and maintained pore stability due to its low cation exchange capacity and weak hydration swelling. Spontaneous imbibition enriched fluid in 10–50 nm pores, while forced imbibition drove fluid into smaller pores, and induced clay dispersion and migration after 8 h to amplify hydroxyl signals. A 2D NMR fluid occurrence state identification spectrum of transitional shales was established, where 4 signal regions were defined. Near-wellbore forced imbibition, dominated by differential pressure, saturates fractures and continuously supplies the matrix, whereas far-wellbore spontaneous imbibition, controlled by capillary and osmotic forces, maintains unsaturated fractures and dynamic equilibrium. These findings clarify the mechanisms governing fracturing fluid imbibition in transitional shales and provide insights for optimizing hydraulic fracturing designs and mitigating groundwater contamination.

Grooved gas diffusion layers (GDLs) have garnered significant attention due to their superior gas–liquid transport potential. However, existing studies lack systematic exploration of the mass transfer mechanism and liquid water distribution uniformity. In this work, a three-dimensional two-phase full-scale cell model is constructed to systematically investigate the electrochemical performance and gas–liquid transport characteristics of perpendicularly grooved GDLs. The results demonstrate that perpendicularly grooved GDLs outperform groove-free GDLs, with the optimal groove width of 200 μm achieving a current density of 1.664 A/cm² at 0.4 V, representing a 4.9% improvement. The core mechanism lies in the capillary pressure gradient (∇P_C) and Sherwood number (Sh) in the GDL region beneath the gas flow channel (GFC), which are significantly increased. ∇P_C and Sh are enhanced by 46.89% and 3.40%, respectively. However, it is notably found that the gas–liquid transport efficiency in the GDL region beneath the rib fails to be enhanced synchronously. The sectionalized transport mechanism leads to a 142.7% increase in liquid water distribution unevenness compared to groove-free GDLs. Therefore, a novel diagonally grooved GDL structure with high reaction uniformity is proposed. By connecting different regions of GDL, the diagonal grooves break the limitation of traditional sectionalized transport, reducing the unevenness of liquid water distribution by 70.6% compared to perpendicularly grooved GDLs. The study also finds the diagonal grooves further reduce the unevenness of liquid water distribution through improving mass transfer between adjacent channels in three-channel cell fuels. This study provides theoretical guidance for the analysis of gas–liquid mass transfer mechanisms and structural optimization of grooved GDLs. It is of great significance for achieving the synergistic optimization of GDL performance and durability.

International field trials have demonstrated that sand production and control are crucial issues that need to be addressed and resolved to achieve the commercial exploitation of natural gas hydrate (NGH). The objective of this study is to investigate sand migration and control in sediments with different particle size distributions during depressurization-induced hydrate exploitation. A 50PPI (pores per linear inch) polyurethane foam was chosen as the sand control material to further explore its performance under conditions closer to actual field reservoirs, which is the continuation and extension of previous investigations. Experimental results confirm that the 50 PPI polyurethane foam demonstrates good sand control effectiveness for reservoirs with a median particle size (D₅₀) of quartz sands ranging from 10 to 100 μm, even under material extrusion deformation. Under comparable reservoir conditions, finer and more heterogeneous sediments increase sand control requirements. Meanwhile, no definitive correlation between internal sand migration and actual sand production was observed. In reservoirs with fine quartz sand, sand production manifests as consolidated sediment migration after hydrate exploitation, while heterogeneous quartz sand reservoirs undergo significant internal changes before and after the NGH exploitation, accompanied by a evident decrease in gas production rate. Based on the experimental study, a theoretical framework for sand migration and production mechanisms during NGH exploitation is proposed, defining three distinct states. The state of sand migration shifts when local blockages reach a threshold, transitioning from particle migration to block displacement.

Levulinic acid and furfural are two renewable platform chemicals with great potential for the future of the chemical industry. However, during the development of their production processes, many researchers have encountered challenges due to the formation of humins. Humins are generally considered waste products formed during the conversion of carbohydrate to levulinic acid and furfural under severe reaction conditions, typically associated with high temperatures (above 160–200 °C), acidic catalysts, and prolonged residence times. This account examines how humins form, the conditions that favor their formation, and the problems they pose for catalyst recovery and product purification. It also discusses strategies that combine mitigation with valorization. Rather than focusing only on kinetics, this work brings together reaction mechanisms, process design, and economic aspects to point out where improvements can be made. By examining 146 studies published between 1962 and 2025, we show that moving toward integrated process designs that include humin valorization is not only beneficial but also necessary to make biorefineries both more cost-competitive and environmentally sustainable.