Energy & Fuels最新文献

CO₂ injection process holds significant potential for reducing carbon emission and enhancing shale gas recovery. On account of the widespread presence of nanoscale pores in shale rocks, after a CO₂ injection operation, a competitive adsorption behavior between shale gas and CO₂ in nanopores can be induced, and simultaneously, a phase transition phenomenon on the shale gas is observed. In this study, we employ the method of molecular simulation to address the competitive adsorption behavior and phase equilibrium of the shale gas-CO₂ system in shale nanopores. First, the nanopore models and molecular models of typical shale fluids are constructed. Moreover, a Grand Canonical Monte Carlo (GCMC) simulation method is applied to simulate the phase behavior of pure CH₄ and the competitive adsorption behavior of CH₄/CO₂ mixture. Subsequently, considering the complicated composition of shale gas and the limitation of the GCMC method, an NPT-Gibbs ensemble Monte Carlo (NPT-GEMC) method is employed to simulate the phase behavior of the shale gas-CO₂ system, which can represent the actual fluid state after a CO₂ injection process. Thus, after model validation, the effects of pore size, pore-wall properties, and CO₂ concentration are discussed. Simultaneously, the influence mechanism of CO₂ on the phase envelope of shale gas is also addressed. Results indicate that the presence of nanopores can further enhance the effect of fluid–solid interaction on the confined behavior of fluids, which is the key factor for the critical deviation of CH₄ from the bulk phase. In comparison, CO₂ can exhibit a stronger adsorption affinity than CH₄, particularly under the conditions of a small nanopore size and low pressure. For the phase envelope, it is observed that an increase on the CO₂ concentration can significantly alter the entire phase diagram to the right side, which indicates that the duration time of the single-phase flow stage in formation is increased. Furthermore, both the nanopore size and pore-wall type can have a larger influence on the dew-point pressure than bubble-point pressure. This investigation provides some new insights into the phase transition behavior of shale gas after CO₂ injection, which is of great significance for the expansion application of CO₂ injection in shale gas resources.

Natural gas hydrates (NGHs) are methane-rich resources with great potential as a clean energy alternative, but hydrate dissociation during production weakens sediment cementation and causes reservoir subsidence and instability. To mitigate these risks and maintain reservoir integrity, reinforcing the NGH reservoir while maintaining its permeability is essential for ensuring safe and efficient gas production. Microbially induced carbonate precipitation (MICP) is a promising in situ technique that strengthens sediments while maintaining permeability. However, its coupled effects on hydrate production remain insufficiently understood. In this study, a fully coupled thermal–hydraulic–mechanical–chemical (THMC) model integrated with a biological–chemical–hydraulic (BCH) framework is developed to simulate different reservoir conditions and reinforcements, investigating their impacts on gas production and geomechanical behavior. The results reveal that intrinsic permeability exerts a dominant control on the spatial extent of hydrate dissociation and flow enhancement, whereas reservoir subsidence is primarily governed by mechanical initial stiffness rather than the dissociation rate. MICP treatment effectively reduces subsidence by 14% to 22% but slightly decreases gas production. A dimensionless gas-subsidence coefficient (η) is introduced to quantify the trade-off between productivity and deformation control. Under the current treatment scheme, optimal balance occurs at sh₀ ≥ 0.3 and k₀ = 30–50 mD, achieving effective subsidence mitigation with minimal production loss and providing theoretical guidance for optimizing MICP-reinforced hydrate reservoir.

Deep coal-measured gas has emerged as a pivotal unconventional resource, with the Upper Paleozoic in the Ordos Basin, representing a key exploration target. Recent discoveries in the Yan’an gas field, southeastern Ordos Basin, have challenged traditional models, yet a comprehensive understanding of its gas accumulation mechanisms remains limited. Our study employs geochemical analysis (TOC, Rock-Eval, stable isotopes), fluid inclusion microthermometry, and reservoir characterization, and the results delineate that (1) two discrete hydrocarbon charging episodes: an initial phase during the Early-Middle Jurassic (J₁–J₂) and a principal, likely tectonically influenced phase in the Late Jurassic-Early Cretaceous (J₃–K₁). The efficient gas accumulation in the tight sandstone reservoirs is controlled by a critical pore-throat lower limit. (2) The gas, characterized by high dryness and widespread carbon isotope reversal (δ¹³C₁ > δ¹³C₂), is confirmed to be a postmature, coal-derived product primarily sourced from the Shanxi and Benxi Formation source rocks. (3) An accumulation model is proposed: intrasource accumulation within the Shanxi and Benxi Formations and near-source accumulation in the overlying Shihezi Formation (“lower-generating/upper-storing”). (4) Crucially, the presence of an isolated compaction system formed by cap-reservoir interaction is identified as a key factor for effective preservation. These findings systematically clarify the genetic model and enrichment mechanisms, providing a robust geological foundation for optimizing exploration strategies and predicting favorable zones in the Yan’an gas field and analogous basins.

The asphaltene (ASP) aggregation during the CO₂ flooding process seriously impacts the oil recovery, which could be effectively inhibited by the additional inhibitors. In this work, the molecular dynamics (MD) simulation is utilized to investigate the mechanism of two inhibitors (nonyl phenol (NP) and tergitol nonyl phenol (TNP)) for the injected CO₂ causing the aggregation of two typical ASP (ASP1: long aliphatic chain and fewer aromatic rings; ASP2: short aliphatic chain and more aromatic rings). The number density distribution and the radial distribution function (RDF) are employed to evaluate the ASP aggregation behavior in the absence or presence of inhibitors in the kaolinite pore. The analysis of the molecular potential surfaces (electrostatic potential and van der Waals potential) and the effective free energy further illustrate the microscopic interaction (such as the hydrogen bonds, electrostatic interaction, and vdW interaction) of ASP and inhibitors, which dominates the inhibitor performance in the ASP aggregation. TNP prefers to inhibit ASP1 aggregation through vdW interaction affected by the flexible ethoxy chain of TNP and the long aliphatic chain of ASP1, while the hydrogen bonds between NP and ASP2 dominantly inhibit ASP2 aggregation. This work proposes the novel understanding about the underlying mechanism in inhibiting the ASP aggregation during the CO₂ flooding process.

This study quantifies the CO₂ adsorption behavior in six shale samples from the Eagle Ford (EF) and Marcellus (MS) formations, and establishes how the shale properties control their adsorption capacity. An integrated experimental and analytical approach is applied, including XRD, TOC, FE-SEM, BET/BJH, and volumetric CO₂ adsorption measurements at 35 °C, along with multivariate statistical evaluation via correlation analysis and principal component analysis (PCA). The objective is to identify the dominant geochemical and pore-structural parameters that influence adsorption and to provide formation-specific insights that can improve reservoir screening for CO₂ sequestration. This study uniquely integrates CO₂ adsorption experiments with multivariate statistical tools to establish quantitative formation-specific controls on adsorption an approach rarely applied in earlier shale adsorption research. The measured adsorption capacity ranges from 0.52 to 1.32 mmol/g, with one MS sample showing significantly higher uptake due to its high TOC, large surface area, and well developed micro/mesopore structure. Correlation analysis reveals that increased organic, Si, and Al contents, along with pore volume, positively affect adsorption, while Ca rich carbonates suppress uptake. The PCA further confirms these trends, clustering high-adsorption samples with siliceous–clay components and low-adsorption samples with carbonates. This integrated data set provides a clear mechanistic understanding of how organic matter, mineralogy and pore architecture jointly govern CO₂ adsorption in shale. Overall, this work offers a robust framework for evaluating shale formations for CO₂ storage and provides formation-level insights that are rarely reported in the literature. The results support improved predictive modeling and highlight the need for larger data sets and temperature-dependent adsorption tests to better represent reservoir conditions. The findings also have implications for emerging subsurface energy storage applications such as hydrogen.

Increasing atmospheric CO₂ levels call for secure, large-scale storage methods, and deep brine reservoirs represent the most widely available and scalable option. However, accurately predicting long-term CO₂ dissolution in these systems remains challenging and difficult because of the complex chemistry of temperature, heterogeneity, capillary forces, and geochemical reactions. This research employs advanced numerical simulations to evaluate these effects on the dissolution of CO₂ in heterogeneous, finite saline aquifers. A key novelty is the integration of experimentally derived diffusion coefficients, extended to higher temperatures via Arrhenius-based predictions, into the CMG simulator, thereby strengthening the linkage between laboratory data and reservoir-scale modeling. The simulations examine CO₂ dissolution across a wide temperature range (35–100 °C) while systematically evaluating the roles of capillary forces, aquifer heterogeneity, salinity, brine density evolution, and mineral–fluid reactions on plume morphology and trapping. To reduce computational complexity, three representative temperature levels (low, medium, and high ranges) were selected for the sensitivity analysis. Results reveal that at 35 °C, capillary forces enhance CO₂ dissolution efficiency by roughly 7%, driven by lower molecular kinetic energy and stronger interfacial interactions within confined pore spaces. Nonetheless, this effect diminishes at 100 °C due to the increased molecular energy and lower interfacial tension. Without geochemical interactions, dissolution efficiency increases by roughly 20% with temperature, from 45% at 35 °C to 70% at 100 °C. With geochemistry considered, redistribution of dissolved CO₂ into ionic and mineral-associated species reduces the apparent efficiency to around 36 and 47% at 35 and 100 °C, respectively. Finally, the findings demonstrate the necessity of accurate diffusion parametrization and the coupled consideration of temperature, capillary forces, geochemistry, and heterogeneity for predicting long-term CO₂ dissolution and trapping in deep saline aquifers.

The increasing development of synthetic aviation fuels from alternative feedstocks requires fuels that not only meet stringent combustion performance standards but are also compatible with existing infrastructure. Combustion properties, such as ignition delay, and combustor operating regimes, such as gas turbine lean blowout, are strongly influenced by parameters including cetane number (CN), viscosity, and volatility. Because jet fuels do not have a specification for CN, synthetic fuels often exhibit lower CN values, leading to longer ignition delays. They also exhibit reduced lubricity relative to conventional petroleum-based jet fuels, as hydrocracking removes oxygen-, sulfur-, and nitrogen-containing compounds from the fuels. These limitations can be addressed through additive use or strategic blending. To streamline certification processes and reduce associated costs, reliable prescreening tools capable of predicting fuel properties are essential for compliance with ASTM fast-track certification protocols. In this work, we present a generalized low-volume screening and kinetic modeling strategy, demonstrated using isoparaffinic kerosene (IPK) produced by Sasol, to enable efficient combustion characterization of synthetic and conventional fuels. Single-pulse shock tube experiments were conducted at 50 atm pressure, 13 ms reaction time, and temperatures ranging from 800 to 1400 K under equivalence ratios of 1.0 and 0.5. Post-shock species were quantified using gas chromatography (GC). Comprehensive compositional analysis via GC × GC-TOFMS/FID revealed that IPK is composed predominantly of C₉–C₁₄ isoparaffins. A chemical functional group optimization (CFGO) approach was applied to formulate surrogate mixtures by matching functional group distributions and the experimentally measured derived cetane number (DCN = 31.52, determined via IQT). The surrogate mechanism, based on the CRECK kinetic model, demonstrated good agreement with experimental speciation data. Rate-of-production, sensitivity, and reaction pathway analyses identified the dominant reaction channels governing fuel oxidation. The results demonstrate the capability of surrogate-based models to accurately capture the combustion characteristics of complex synthetic fuels. Moreover, it is desirable that such surrogates, composed of commercially available components, can also enable experimental evaluation of other key combustion metrics, such as atomization, droplet size, and spray behavior, which typically require large quantities of fuel. This capability facilitates efficient, low-volume screening of novel synthetic fuels prior to large-scale production.

In this study, we successfully prepared polyurethane microcapsules with regular morphology, uniform particle size and excellent monodispersity by means of microfluidic technology. The microcapsules use surfactant as the core material and polyurethane as the wall material, which significantly improves the controllability and repeatability of the traditional microcapsule preparation method. The prepared microcapsules not only have a minimum particle size of 44.5 μm, but also have a narrow particle size distribution (65–71 μm) and an average diameter of 67.4 μm, fully demonstrating excellent morphology control ability. In terms of performance evaluation, these microcapsules showed rapid targeted release characteristics in both light oil and heavy oil, especially in heavy oil, which could be completely dissolved within 10 s, indicating that they had good compatibility with oil molecules. Furthermore, the microcapsules encapsulated with AEO-3 surfactant can significantly reduce the oil–water interfacial tension from 27.68 mN·m^–1 to 6.67 mN·m^–1, which significantly enhances the peeling ability of oil droplets from the rock surface. In particular, when the concentration of microcapsules was 0.1 wt %, the Zeta potential of the dispersion system was −36.12 ± 0.7 mV, indicating that the system had high stability and effectively prevented the aggregation or precipitation of microcapsules. In addition, the microcapsules can maintain morphological integrity under high salt (10 wt % NaCl, 7 wt % CaCl₂) and high temperature (80 °C) conditions, showing excellent temperature and pressure resistance. Microscopic oil displacement experiments show that microcapsules can effectively enhance oil recovery by reducing oil–water interfacial tension and changing rock wettability, showing its great application potential in the field of enhanced oil recovery (EOR). These research results not only verify the advantages of microfluidic technology in the preparation of microcapsules, but also provide strong support for the development of intelligent oil displacement agents.

The main active components in kinetic hydrate inhibitor (KHI) formulations are one or more key polymers. Designing the polymers to be effective requires consideration of two main topics: first, some basic structural features of the polymer need to be optimized, and second, how the polymer structure behaves in the aqueous environment under laboratory and field conditions. A review series structured into three independent parts systematically summarizes the key factors affecting KHI performance. This paper serves as the stand-alone first part of the review series, which sums up the structural features that must necessarily be considered in designing an effective KHI polymer. This review comprehensively discusses the critical structural features of KHI polymers, mainly including the amphiphilic functional groups in the repeating units, optimal polymer chain length, stereochemical configuration, functional end-capping groups, linear/branched chain structures, and monomer sequencing in copolymers. The potential inhibition mechanisms associated with the key molecular structural factors governing KHI efficacy are further clarified. The synergistic effect exhibited by these structural features enables KHI polymers to exert dual functional roles: first, perturbing the molecular behavior of the water phase, and second, adsorbing onto the surface of hydrate crystals. These combined actions collectively contribute to the kinetic inhibition of hydrate nucleation and subsequent crystal growth. This review synthesizes current understanding into a coherent framework to enable the rational design of high-performance KHIs.

The increasing development of synthetic aviation fuels from alternative feedstocks requires fuels that not only meet stringent combustion performance standards but are also compatible with existing infrastructure. Combustion properties, such as ignition delay, and combustor operating regimes, such as gas turbine lean blowout, are strongly influenced by parameters including cetane number (CN), viscosity, and volatility. Because jet fuels do not have a specification for CN, synthetic fuels often exhibit lower CN values, leading to longer ignition delays. They also exhibit reduced lubricity relative to conventional petroleum-based jet fuels, as hydrocracking removes oxygen-, sulfur-, and nitrogen-containing compounds from the fuels. These limitations can be addressed through additive use or strategic blending. To streamline certification processes and reduce associated costs, reliable prescreening tools capable of predicting fuel properties are essential for compliance with ASTM fast-track certification protocols. In this work, we present a generalized low-volume screening and kinetic modeling strategy, demonstrated using isoparaffinic kerosene (IPK) produced by Sasol, to enable efficient combustion characterization of synthetic and conventional fuels. Single-pulse shock tube experiments were conducted at 50 atm pressure, 13 ms reaction time, and temperatures ranging from 800 to 1400 K under equivalence ratios of 1.0 and 0.5. Post-shock species were quantified using gas chromatography (GC). Comprehensive compositional analysis via GC × GC-TOFMS/FID revealed that IPK is composed predominantly of C₉–C₁₄ isoparaffins. A chemical functional group optimization (CFGO) approach was applied to formulate surrogate mixtures by matching functional group distributions and the experimentally measured derived cetane number (DCN = 31.52, determined via IQT). The surrogate mechanism, based on the CRECK kinetic model, demonstrated good agreement with experimental speciation data. Rate-of-production, sensitivity, and reaction pathway analyses identified the dominant reaction channels governing fuel oxidation. The results demonstrate the capability of surrogate-based models to accurately capture the combustion characteristics of complex synthetic fuels. Moreover, it is desirable that such surrogates, composed of commercially available components, can also enable experimental evaluation of other key combustion metrics, such as atomization, droplet size, and spray behavior, which typically require large quantities of fuel. This capability facilitates efficient, low-volume screening of novel synthetic fuels prior to large-scale production.