Upgrading clean energy fuels, such as biogas, natural gas, and shale gas, requires the capture of CO 2 to enhance their heating value. Ionic liquids (ILs) are promising absorbents for this purpose, but the vast number of available ILs necessitates an efficient screening method. The Comparative Absorption Factor ( CAF ) developed in our previous study can estimate the total annual cost ( TAC ) of CO 2 capture from biogas, which is a key advantage over alternative screening methods. However, CAF does not consider the effects of operating conditions such as CO 2 concentration, pressure, and temperature. To address this limitation, a modified CAF ( CAF modified ) that incorporates these factors was proposed. Given the linear relationship between the original CAF and TAC , three representative ILs ([C 10 mpy][DCA], [C 1 mim][tfo], and [C 1 py][tfo]) were selected from 490 ILs based on their melting point, viscosity, and original CAF values. Subsequently, process simulations for these ILs were conducted using Aspen Plus, considering a wider range of operating conditions: CO 2 concentrations of 30–50 vol%, temperatures of 303.15–318.15 K, and pressures of 7–15 bar. These simulations were used to determine the Aspen Plus-derived TAC , which served as the basis for proposing CAF modified . Finally, data for Aspen Plus-derived TAC from the previous study and for 6 additional ILs over a broad range of operating conditions were used to compare with the TAC values estimated by CAF modified . The results showed an average relative deviation of 16%, indicating that CAF modified is effective for screening ILs for CO 2 capture under varying operating conditions. A comparison of the total annual costs ( TAC ) calculated by the original and modified Comparative Absorption Factor ( CAF ), incorporating the effects of operating conditions. • Modified CAF factor integrates CO 2 concentration, temperature and pressure effects. • 15.82% accuracy in TAC prediction across 30–50 vol% CO 2 , 303–318 K, 7–15 bar. • Rapid ILs screening for biogas/shale/natural gas upgrading without process simulation.

Phosphatic bioclastic laminae distributed along bedding planes have been recently discovered within the Jurassic Lianggaoshan Formation shale in the eastern Sichuan Basin. However, their characteristics and potential as shale oil and gas reservoirs remain unclear. To reveal their microscopic pore structure characteristics and development model, this study focuses on samples of phosphatic bioclastic laminae obtained from drilling cores in the Fuxing area of eastern Sichuan. A multi-scale analytical approach was employed, integrating micro-X-ray fluorescence spectroscopy (μ-XRF), field emission scanning electron microscopy (FE-SEM), nitrogen adsorption, nuclear magnetic resonance (NMR), and geochemical analyses. The results indicate that the phosphatic bioclastic laminae are primarily composed of apatite and calcite and formed in a low-energy, anoxic, semi-deep to deep lacustrine environment. They exhibit an average total porosity of 4.84% and an average TOC of 1.99 mg/g. It is 14.7% and 17.8% higher than the clay laminae, and 255.9% and 109.57% higher than the calcareous bioclastic laminae. The pore system is dominated by mesopores and macropores, encompassing multiple pore types including dissolution pores, interparticle pores, interlayer pores, organic matter-hosted pores, and micro-fractures. Notably, a well-connected nanometer-scale pore network developed within fish bone fragments contributes substantially to the storage space. These intervals integrate high organic matter richness with superior reservoir properties, demonstrating typical “source-reservoir integration” characteristics. Their pore structure is synergistically regulated by sedimentary–diagenetic processes, with a core mechanism of primary biogenic pore foundation–late diagenetic dissolution enhancement–micro-fracture connectivity. This study systematically elucidates, for the first time, the reservoir formation mechanism of the phosphatic bioclast-rich laminae in the Lianggaoshan Formation. It confirms their potential as “geological-engineering” dual sweet spots for shale oil and gas exploration, providing a new basis for sweet spot prediction and exploration deployment targeting similar phosphatic bioclastic laminae in the Sichuan Basin and analogous regions.

In recent years, screen pipe scaling and blockage have occurred in dozens of wells in the Fuling Shale Gas Field, seriously affecting the normal production of gas wells. Investigations show that similar problems exist in the Weirong Shale Gas Field of Sinopec Southwest Branch, and the Changning and Weiyuan Shale Gas Fields of PetroChina. Although well production has been restored through pipe inspection operations, key issues specific to shale gas wells remain unresolved, including the scaling mechanism under gas–liquid two-phase flow regimes unique to horizontal shale gas wells, the scale deposition law at screen pipes caused by complex flow direction changes, and the targeted prevention technologies for high-hardness BaSO4 scale in high-salinity produced water. By jointly conducting research on the scaling mechanism and prevention technology of shale gas wellbores with Southwest Petroleum University, the Fuling Shale Gas Field has identified the reasons why the amount of BaSO4 scaling increases with the decrease in pressure and temperature, while it increases with the increase in gas–water ratio. It has clarified the influencing characteristics of factors such as pressure, temperature, gas–water ratio and pipe wall roughness. The amount of scaling on the tubing wall of shale gas wells in this area is very small, and blockage mainly occurs at and near the screen pipe. Due to the complex flow direction change in gas and water in the screen pipe, the precipitated tiny scale particles separate, settle and accumulate, forming variable-diameter steps that continue to grow. Two agents have been developed: the LPPAS scale inhibitor and the barium-strontium-sulfate-chelating plug-removing agent, with a scale inhibition rate as high as over 90% and a scale dissolution rate over 70%, respectively, laying a foundation for the efficient and stable production of shale gas wells.

The low-temperature direct conversion of ethane is more appealing for the utilization of shale gas. Dual-atom catalysts have attracted considerable attention due to their unique cooperative effects. Herein, we report a porous organic polymer-supported Rh1-Cu1 dual-site catalyst (Rh1-Cu1@POPs-PPh3) for the selective oxidation of ethane to ethanol, acetaldehyde, and acetic acid with auto-selective oxygen mechanism. The optimized Rh1-Cu1 centers deliver a productivity of ca. 250mol molRh -1 h-1 based on Rh with 65% acetaldehyde selectivity at 423 K, representing a four-fold improvement over the single-Rh-site catalyst. Through isotopic labeling and in situ characterizations, we uncover an auto-selective oxygen source mechanism in which dehydrogenated species of ethane with different grades possess self-selectivity for the combined oxygen source. Oxygen species derived from O2 activate ethane and subsequently couple with the ethyl fragment to produce ethanol. While OH radicals from H2O dissociation react with ethyl intermediates from ethane dehydrogenation to yield acetaldehyde. Concurrently, oxygen species recombine with reactive hydrogen species to regenerate new H2O, completing the catalytic oxidation cycle. The density functional theory (DFT) calculations reveal that the Rh-Cl-Cu configuration lowers the lowest unoccupied molecular orbital (LUMO) energy of Rh1, thereby strengthening adsorbate-metal interactions, weakening the C─H bond, and facilitating its activation.

Volume stimulation technique is currently the primary engineering approach for effectively enhancing shale gas productivity. However, in post-fracturing reservoirs, multi-media coupling is prominent, and fracture conductivity exhibits strong heterogeneity. This necessitates further characterization of heterogeneous spatial distribution of complex fractures, as well as multiple flow mechanism. This study develops a multiscale coupled matrix-fracture flow in porous media model based on the post-fracturing reservoir geometry to precisely describe production dynamics in fractured shale gas reservoirs. Heterogeneity in hydraulic fracture geometry and stimulated reservoir volume (SRV) permeability was simulated using continuous gradient functions. Analytical solutions for the multi-stage fractured shale gas reservoir model were derived through multi-linear flow model and perturbation methods. By integrating simulated annealing and particle swarm optimization algorithms, the C++ code was enhanced to achieve automated history matching and production forecasting. Results indicate that hydraulic fracture damage predominantly affects early-stage production, with near-tip fracture blocking leading to reduced overall gas production. Mid-to-late production is more significantly influenced by SRV permeability -gradual permeability variations exhibit minor impacts, whereas abrupt permeability changes substantially decrease total gas production. Based on an analysis of dynamic production data from two wells in the oilfield, this study achieves optimal matching of unknown reservoir parameters, thereby enabling reliable production performance prediction. The proposed model demonstrates high rationality and practicality in reservoir parameter inversion and shale gas well performance forecasting, providing novel insights to critical challenges in shale gas production.

Molecular dynamics simulation of CO2 utilization for enhanced recovery and carbon storage in shale gas

Influence of initial cell counts on the microbiologically influenced corrosion of L245N steel in shale gas environments.

A fully coupled geomechanical-fluid flow model for fracture interference induced by large-scale natural fracture zones in deep shale gas wells

Treatment of shale gas wastewater using pre-oxidation coupled membrane bioreactor: Organic matter removal and composition characteristics analysis

Erosion mechanism and zirconia erosion-resistant protection of shale gas gathering pipelines under dynamic gas-liquid-solid flow conditions

A microstructural characterization of temperature-dependent microbial corrosion of 5Cr-0.5Cu steel in simulated SRB-containing shale gas field produced water

Integrated biofiltration – gravity-driven membrane system for efficient treatment of shale gas wastewater: Roles of filter media and microbial synergy

Treatment of shale gas fracturing flowback fluid using a novel multistage flocculation reactor: Energy-matching mechanism and field validation

Electrode-engineered photocatalytic fuel cell: synergistic effect of sulfide oxidation and oxygen reduction driven sulfide wastewater treatment and valorization.

With the development of unconventional oil and gas resources (such as shale gas and tight oil/gas), the widespread application of multistage fracturing technology has significantly increased the difficulty of wellbore integrity maintaining. The cement sheath serves as the core barrier for preserving wellbore integrity, particularly at the first interface (cement–casing) and the second interface (cement–formation). The high temperature, high pressure, and cyclic dynamic loading imposed by multistage fracturing represent severe challenges to the integrity of cement sheath. To simulate underground conditions realistically, a high-temperature, complex stress path loading system coupled with real-time gas flow monitoring was developed. Using this system, gas leakage monitoring and displacement-controlled cyclic loading tests were conducted on cement–steel (simulating the first interface) and cement–shale (simulating the second interface) composite specimens. It focused on investigating the effects of different temperatures, cyclic stress levels, and cycle counts on the sealing performance of the cement–steel and cement–shale composites. The findings reveal that elevated temperatures significantly degrade cement properties and accelerate damage accumulation. Cyclic stress levels and cycle counts are core drivers of interface fatigue failure, exhibiting synergistic destructive effects with temperature. The first interface is more prone to seal failure due to material property differences and a relatively high stress level. This research elucidates the cumulative damage mechanism underlying interfacial seal failure. It is of significant engineering implications for enhancing well safety and development efficiency.

In this study, shale samples with diverse lithofacies from the Lower Silurian Longmaxi Formation in the Fuling Field were investigated to evaluate the variations in pore characteristics and methane adsorption capacity (MAC) of different shale lithofacies. A set of experiments were performed, such as total organic carbon (TOC) content, X-ray diffraction (XRD), field emission–scanning electron microscopy (FE-SEM), low-pressure gas (CO2/N2) adsorption, and high-pressure methane adsorption. Combined with TOC content and mineral composition, three types of shale lithofacies were identified, including organic-rich (OR) argillaceous-rich siliceous (S-3) shale lithofacies, organic-moderate (OM) argillaceous/siliceous mixed (M-2) shale lithofacies, and organic-lean (OL) siliceous-rich argillaceous (CM-1) shale lithofacies. Through detailed comparative analyses, we found that OR S-3 shales possess the maximum TOC content, the most developed heterogeneous organic micro-mesopores, the largest pore volume (PV), and the highest pore surface area (PSA); consequently, they display the strongest MAC. Conversely, OL CM-1 shales have the lowest TOC content and the highest clay content, and thus the smallest PSA and the poorest methane adsorption performance. In conclusion, considering the excellent gas storage potential, sustained shale gas production, and brittle response to hydraulic fracturing, OR S-3 shales are superior to shale gas exploration and exploitation compared with OM M-2 and OL CM-1 shales.

A productivity simulation for hydraulically fractured wells with complex fracture geometry involves a heavy computational burden and is therefore not suitable for engineering-scale fracture-optimization designs and production-analysis applications. This paper develops a productivity-prediction surrogate model based on a deep convolution–bidirectional gated recurrent unit temporal network (DC-BiGRU) framework where a deep convolutional neural network is used to extract features from fracture images, while a BiGRU model was designed to fully capture valuable information from the production sequence. Some additional inputs, e.g., cluster spacing and stage spacing, that account for different fracture-placement designs in horizontal wells were also considered. A large number of shale-gas production data samples at different times were generated using a fractured-horizontal-well productivity simulator under diverse hydraulic-fracture geometries and bottom-hole flowing pressures. The surrogate model had relative errors below 10% with an average error of about 6%. Compared to high-fidelity capacity prediction simulators, the computational efficiency of the deep learning surrogate models was improved by two to three orders of magnitude. The runtime of the high-fidelity numerical simulator was about 20 min, while the surrogate model, which was run on an NVIDIA Tesla P100 GPU (NVIDIA, Santa Clara, CA, USA), took less than 1 s, which is almost negligible. The proposed surrogate model resolved the low efficiency of the productivity simulation for complex-fracture hydraulic fracturing wells in unconventional reservoirs, enabling rapid dynamic forecasting of fractured-well productivity.

Impact of Multiscale Pore Structure and Mineralogy on Fracturing Fluid Imbibition in Marine–Continental Transitional Shale Gas Reservoirs

With the increasingly stringent environmental regulations, the development of high-performance and eco-friendly shale inhibitors for water-sensitive formations has become an urgent priority. Chitosan, a renewable biopolymer derived from chitin, has inherent potential as a shale inhibitor but is limited by low water solubility and suboptimal inhibition efficiency. To overcome these limitations, cationic quaternary ammonium groups were grafted onto chitosan through etherification with 3-chloro-2-hydroxypropyltrimethylammonium chloride (CHA), yielding chitosan quaternary ammonium chloride (QASC). Systematic evaluation through linear swelling, rolling recovery, and bentonite inhibition tests revealed QASC's superior performance. Notably, 1% QASC reduced bentonite swelling to 28.1% after 16 h, outperforming 5% KCl (48.2%) and 1% polyetheramine (41.1%). Remarkably, QASC achieved 88.4% shale recovery at 150 °C significantly exceeding the values for polyetheramine (52%) and pure water (13.2%). Mechanistic analysis revealed that QASC inhibits clay hydration through dual mechanisms: (1) electrostatic and hydrogen-bond mediated adsorption on clay surfaces, effectively neutralizing surface charges and diminishing hydration films; (2) intercalation into clay interlayers to create a physical barrier against water invasion. This synergistic combination ensures stable inhibitory performance under elevated temperatures. Given its enhanced biodegradability, QASC emerges as a sustainable alternative to conventional inhibitors, effectively addressing the dual challenges of technical performance and environmental compatibility in shale gas drilling operations.

The organic-rich shales of the Upper Ordovician–Lower Silurian Renheqiao Formation in Yunnan, China, represent a valuable target for understanding marine hydrocarbon systems and offshore oil and gas exploration. To decipher its organic matter (OM) accumulation patterns and offer perspectives relevant to the assessment of marine resources, this study employs an integrated petroleum geological, sedimentological, and palynological approach. Our findings indicate that organic-rich intervals (cumulative thickness 74–84.5 m) are concentrated in the R1–lower R6 and upper R6–R9 graptolite biozones, exhibiting high total organic carbon (TOC) content and graptolite reflectance values indicative of high to post-maturity thermal evolution, which confirms significant shale gas potential. Sedimentary evolution shows broad similarities with the Yangtze region’s Longmaxi Formation but with finer-scale differences. Due to its restricted paleogeographic setting on the Sibumasu Block, the Baoshan region responded to global sea-level changes with a lag, favoring sustained OM accumulation. Palynological analysis identified microphytoplankton, acritarchs, macroalgae, and animal-derived OM. Hydrocarbon-generating assemblages are divided into three stages: the first (R1–lower R6) and third (upper R6–R9) stages are favorable intervals with high TOC, dominated by microphytoplankton and acritarchs; the second stage (middle R6) shows lower enrichment, with increased macroalgae/animal-derived debris. Our analysis indicates that high abundances of primary producers (microphytoplankton/acritarchs) are strongly associated with organic enrichment. In contrast, higher abundances of secondary consumers (e.g., graptolites) show a significant negative correlation with TOC, suggesting their presence may coincide with conditions less favorable for accumulation or that they actively inhibit it.