Jingyi Zhu

A deeper understanding of the effects of salt environments in zwitterionic viscoelastic surfactant (VES) fracturing fluids on micellar structural evolution, self-breaking behavior, and methane mass transfer in coal reservoirs is important for optimizing fracturing fluid formulations and coalbed methane development. In this study, VES formulations were optimized through experimental screening and rheological evaluation, yielding 3% erucamide propyl betaine (EAB) + 1.05% sodium benzenesulfonate (NABS) + 2% KCl. Molecular dynamics simulations were then performed to investigate the effects of salt components on EAB micellar self-assembly and self-breaking. The results showed that inorganic and organic salts jointly promoted the evolution of EAB micelles from spherical to rod-like structures through ionic regulation and intermolecular interactions. During light-hydrocarbon-induced self-breaking, C12 molecules entered the hydrophobic region of EAB micelles, altered hydrophobic-chain interactions, and induced micellar structural rearrangement and disintegration. Coal pore simulations showed that CH₄ was mainly physically adsorbed near the pore walls. Different VES formulations affected CH₄ diffusion differently, with the EAB/NABS/KCl system exhibiting the highest diffusion coefficient of 59.71 Ų/ps, 27.1% higher than that of the pure coal-CH₄ system. The weakened CH₄-coal interaction after VES introduction corresponded to enhanced CH₄ diffusion, indicating that VES can regulate coal-gas interfacial interactions and thereby affect CH₄ mass transfer. This study provides molecular-scale insights into salt-regulated VES behavior and its influence on CH₄ mass transfer, supporting the optimization of low-damage fracturing fluids for coalbed methane development.

In composite wellbore blockages, organic coatings on inorganic deposits can markedly restrict effective contact between conventional acids and the internal inorganic components, thereby reducing the overall removal efficiency of the blockage. Based on the characteristics of gas-well blockages from the SN Gas Field, a W/O microemulsion acid system integrating organic dispersion and inorganic dissolution was developed. A composite blockage model with compaction and cementation states similar to those of the field deposits was constructed, and its unplugging behavior was systematically evaluated and the underlying mechanism was investigated through static dissolution, dynamic displacement, and imbibition experiments. The results showed that the microemulsion acid system achieved a static dissolution percentage of 89.4%, markedly higher than the 68.9% achieved by the conventional acid system. Under dynamic displacement conditions, the permeability-restoration efficiency reached 43.72%, compared with only 21.07% for the conventional acid system. An imbibition kinetic relationship was established based on the mass change during the imbibition experiments. The apparent imbibition coefficient of the microemulsion acid system was 0.87 g·h-1/2, compared with 0.29 g·h-1/2 for the conventional acid system, indicating a stronger spontaneous imbibition capacity and facilitating the entry of the unplugging fluid into the compacted blockage medium. These effects jointly promote blockage disintegration and flow-channel restoration, providing an experimental basis and a technical approach for the integrated treatment of composite wellbore blockages.

With the continuous increase in global fossil energy consumption, conventional energy resources such as oil, natural gas, and coal are gradually being depleted (Gwyn 2001). The limited nature of co...

Injection damage in the M tight oil reservoir is controlled by the coupled effects of inorganic scaling and organic fouling at the pore scale. To clarify the governing mechanisms, this study combines long-duration core flooding, water-chemistry compatibility analysis, and thermodynamic scale prediction with NMR T₂ spectroscopy, mercury intrusion capillary pressure, SEM-EDS characterization, and factor-controlled microfluidic visualization that reproduces reservoir pore geometry and wettability. Core flooding tests reveal permeability reductions of 61 to 73 percent after 12 to 24 hours of injection, indicating progressive contraction of effective flow channels. NMR T₂ spectra demonstrate strong pore-size selectivity: small pores largely retain their porosity, 99.43 and 89.48 percent, whereas medium and large pores experience substantial losses. SEM imaging and elemental mapping show Ca and Ba co-located with carbon within pore spaces, consistent with CaCO₃ and BaSO₄ precipitation induced by mixing sulfate-rich injection water with formation brine. Microfluidic experiments further decouple the roles of oil presence, hydrocarbon type, wettability, and asphaltene content. In the presence of oil, injection pressure increases from 20.4 to 93.6 kPa, compared with 1.3 to 13.4 kPa without oil, while pore-space retention decreases to 73 percent versus 92 percent. Inorganic scale alone causes only moderate injectivity impairment, whereas oil-mediated deposition raises total pore blockage to approximately 27 percent, accounting for nearly two-thirds of the overall injectivity decline. Heavier n-tetradecane generates larger aggregates and higher pressures than n-hexane. Oil-wet surfaces promote more continuous deposits, faster pressure escalation, and greater loss of open flow area than hydrophilic substrates. Increasing the asphaltene surrogate concentration from 2 to 6 percent accelerates inlet bank formation and early throat occlusion, reducing pore-space retention from 98.0 to 67.9 percent and increasing pressure from 59.09 to 78.23 kPa.

With the progressive depletion of conventional oil and gas resources and the increasing demand for alternative energy, organic-rich sedimentary rock—oil shale—has attracted widespread attention as a key unconventional hydrocarbon resource. Pyrolysis is the essential process for converting the organic matter in oil shale into recoverable hydrocarbons, and a detailed understanding of its behavior is crucial for improving development efficiency. This review systematically summarizes the research progress on the pyrolysis characteristics of oil shale under laboratory conditions. It focuses on the applications of thermogravimetric analysis (TGA) and differential scanning calorimetry (DSC) in identifying pyrolysis stages, extracting kinetic parameters, and analyzing thermal effects; the role of coupled spectroscopic techniques (e.g., TG-FTIR, TG-MS) in elucidating the evolution of gaseous products; and the effects of key parameters such as pyrolysis temperature, heating rate, particle size, and reaction atmosphere on product distribution and yield. Furthermore, the mechanisms and effects of three distinct heating strategies—conventional heating, microwave heating, and autothermic pyrolysis—are compared, and the influence of inherent minerals and external catalysts on reaction pathways is discussed. Despite significant advances, challenges remain in quantitatively describing reaction mechanisms, accurately predicting product yields, and generalizing kinetic models. Future research should integrate multiscale experiments, in situ characterization, and molecular simulations to construct pyrolysis mechanism models tailored to various oil shale types, thereby providing theoretical support for the development of efficient and environmentally friendly oil shale conversion technologies.