Search Results (1,525)

To improve fracturing support efficiency of terrestrial shale oil reservoirs with uneven proppant placement, this study used complex mesh flat-plate simulations and ANSYS FLUENT (2020) simulations to test four sand addition processes. Proppants were 70/140 mesh quartz sand with a density of 2650 kg/m³ and 40/70 mesh ceramic particles with a density of 2000 kg/m³, and the carrier was hydroxypropyl guar gum fracturing fluid with a viscosity of 4.46–13.4 mPa·s at 25 °C. Alternating sand addition performed best: sand-laying efficiency reached 52 percent, 10 percentage points higher than continuous sand addition and 12 percentage points higher than mixed sand addition; sand embankment void area was 1400 cm², 18.3 percent lower than continuous sand addition; proppant entry into secondary cracks increased 23.8 percent compared with reverse sand addition; at branch crack Position 2, 1.3 m from the inlet and at a 90-degree angle, its equilibrium height was 210 mm and paving rate 0.131. This study fills gaps of no systematic multi-process comparison and insufficient quantification of crack geometry–sand parameter coupling in existing research; its novelty lies in the unified visualization comparison of four processes, revealing geometry–parameter coupling and integrating experiment simulation; the optimal scheme also improves fracture support efficiency 21.5 percent compared with conventional continuous sand addition. Full article

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. Full article

Hydrocarbon-generation intensity (HGI) is a critical indicator for evaluating shale gas potential in source rocks. This study proposes a practical method to estimate HGI by integrating experimental pyrolysis data, EasyRo-based maturity transformation, kinetic modeling, and geological parameters. Using core samples from the Shanxi Formation in the eastern margin of the Ordos Basin, gold tube pyrolysis experiments were conducted under closed-system conditions to obtain gas yield data. The EasyRo model was applied to transform temperature to maturity, and a kinetic model was constructed to simulate hydrocarbon generation. Total organic carbon (TOC), maturity (Ro), thickness, and true density were used to calculate HGI at different depths. Spatial prediction of HGI was achieved using Kriging interpolation. Results indicate that although carbonaceous mudstones have higher TOC (14.2%) and gas yields (up to 155.84 mg/g TOC), black mudstones exhibit a 24.77% higher HGI due to greater thickness (average 67.2 m). This highlights the dominant role of formation thickness in controlling. Notably, black mudstones in the deeper western subregion exhibit greater gas-generation potential. These findings offer a robust quantitative basis for evaluating deep coal-measure shale gas resources in the Ordos Basin. Full article

This study presents an integrated geomechanical modeling framework for predicting multi-scale fracture networks and their activity in the Longmaxi Formation shale reservoir, northern Luzhou region, southeastern Sichuan Basin—an area shaped by complex, multi-phase tectonic deformation that poses significant challenges for resource prospecting. The workflow begins with quantitative characterization of key mechanical parameters, including uniaxial compressive strength, Young’s modulus, Poisson’s ratio, and tensile strength, obtained from core experiments and log-based inversion. These parameters form the foundation for multi-phase finite element simulations that reconstruct paleo- and present-day stress fields associated with the Indosinian (NW–SE compression), Yanshanian (NWW–SEE compression), and Himalayan (near W–E compression) deformation phases. Optimized Mohr–Coulomb and tensile failure criteria, coupled with a multi-phase stress superposition algorithm, enable quantitative prediction of fracture density, aperture, and orientation through successive tectonic cycles. The results reveal that the Longmaxi Formation’s high brittleness and lithological heterogeneity interact with evolving stress regimes to produce fracture systems that are strongly anisotropic and phase-dependent: initial NE–SW-oriented domains established during the Indosinian phase were intensified during Yanshanian reactivation, while Himalayan uplift induced regional stress attenuation with limited new fracture formation. The cumulative stress effects yield fracture networks concentrated along NE–SW fold axes, fault zones, and intersection zones. By integrating geomechanical predictions with seismic attributes and borehole observations, the study constructs a discrete fracture network that captures both large-scale tectonic fractures and small-scale features beyond seismic resolution. Fracture activity is further assessed using friction coefficient analysis, delineating zones of high activity along fold–fault intersections and stress concentration areas. This principle-driven approach demonstrates how mechanical characterization, stress field evolution, and fracture mechanics can be combined into a unified predictive tool, offering a transferable methodology for structurally complex, multi-deformation reservoirs. Beyond its relevance to shale gas development, the framework exemplifies how advanced geomechanical modeling can enhance resource prospecting efficiency and accuracy in diverse geological settings. Full article

The dynamic changes in shale pore structure due to tectonic uplift are crucial for understanding the processes of shale gas enrichment and accumulation, particularly in complex tectonic regions. To explore the heterogeneous changes in pore structure and their influencing factors during the last tectonic uplift of Longmaxi shale, triaxial creep experiments were performed under varying confining pressure conditions. In addition, FE-SEM, MIP, LN2GA, and LCO2GA experiments were employed to both qualitatively and quantitatively characterize the pore structure of three distinct groups of Longmaxi shale samples. To further investigate pore heterogeneity, the multifractal dimension was applied to examine the evolution of the shale pore structure under the influence of the last tectonic uplift. The results revealed that the primary pore types in Longmaxi shale include organic matter pores, microfractures, intergranular pores, and intragranular pores. The shale’s mechanical properties and mineral content have a significant impact on the heterogeneity of these pores. Notably, the shale pores exhibit distinct multifractal characteristics, highlighting the complex nature of pore heterogeneity. The singular index (α₀) and ten other multifractal dimension parameters provide valuable insights into the heterogeneity characteristics of shale pores from various perspectives. Additionally, dynamic changes in pore heterogeneity are primarily controlled by the mineral composition. Under identical creep pressure variation conditions, significant differences are observed in the pore rebound behavior of Longmaxi shale with different mineral compositions. Under high-pressure conditions, the content of TOC and quartz plays a dominant role in controlling pore heterogeneity, with their influence initially decreasing and then increasing as pressure decreases. The reduction in creep pressure emphasizes the controlling effect of TOC, quartz, and feldspar content on pore connectivity. This study introduces high-pressure triaxial creep experiments to simulate the stress response behavior of pore structures during tectonic uplift, offering a more comprehensive reflection of pore evolution in organic-rich shale under realistic geological conditions. Full article

Compared with conventional gas reservoirs, deep shale gas reservoirs are characterized by developed faults and fractures, strong heterogeneity, high stress sensitivity, and complex in situ stress distribution. To address traditional 3D static models’ inability to predict in situ stress changes in strongly heterogeneous reservoirs during fracturing, this study takes the deep shale gas in the Zigong block of the Sichuan Basin as an example. By comprehensively considering the heterogeneity and anisotropy of geomechanical parameters and natural fractures in shale gas reservoirs, a 4D in situ stress multi-physics coupling model for shale gas reservoirs based on geology–engineering integration is established. Through coupling geomechanical parameters with fracturing operation data, the dynamic evolution laws of multi-scale stress fields from single-stage to platform-scale during large-scale fracturing of horizontal wells in deep shale gas reservoirs are systematically studied. The research results show the following: (1) The fracturing process has a significant impact on the magnitude and direction of the stress field. With the injection of fracturing fluid, both the minimum and maximum horizontal principal stresses increase, with the minimum horizontal principal stress rising by 1.8–6.4 MPa and the maximum horizontal principal stress by 1.1–3.2 MPa; near the wellbore, there is an obvious deflection in the direction of in situ stress. (2) As the number of fracturing stages increases, the minimum horizontal principal stress shows an obvious cumulative growth trend, with a more significant increase in the later stages, and there is a phenomenon of stress accumulation along the wellbore, with the stress difference decreasing from 15 MPa to 11 MPa. (3) The on-site adoption of the fracturing operation method featuring overall flush advancement and inter-well staggered fracture placement has achieved good stress balance; comparative analysis shows that the stress communication degree of the 400 m well spacing is weaker than that of the 300 m well spacing. This study provides a more reasonable simulation method for large-scale fracturing development of deep shale gas, which can more accurately predict and evaluate the dynamic stress field changes during fracturing, thereby guiding fracturing operations in actual production. Full article

The high-yield industrial gas from Sichuan Basin’s Wujiaping (P₃w) shale reveals a new unconventional exploration play. Due to the strong heterogeneity of shale gas, its enrichment and exploration potential remain unclear. Geochemical and other experiments conducted on this layer have shown that: (1) The third member of the P₃w (P₃w³) shale has optimal quality, with large thickness and wide distribution. The average TOC value is 6.09%, and the organic matter type is II₁~II₂. (2) Shale gas in the P₃w is supplied by organic-rich shale; enrichment is promoted by siliceous/clay shale interbedding, with storage in organic matter pores and fractures. (3) Comparative analyses with the Wufeng–Longmaxi shales (O₃w-S₁l) show that P₃w³ is the layer with the greatest potential for shale gas exploration. Full article

The characteristics and evolution of fibrous calcite veins in organic-rich shales have gained significant attention due to the recent advancements in shale oil and gas exploration. However, the fibrous calcite veins in the Upper Permian Dalong Formation remain lacking in awareness. To investigate the formation and significance of bedding-parallel fibrous calcite veins in the Dalong Formation, we conducted an extensive study utilizing petrography, geochemistry, isotopic analysis, and fluid inclusion studies on outcrops of the Dalong Formation in South China. Our findings reveal that fibrous calcite veins predominantly develop in the middle section of the Dalong Formation, specifically within the transitional interval between siliceous and calcareous shales, characterized by symmetric, antitaxial fibrous calcite veins. The δ¹³C values of these veins exhibit a broad range (−4.53‰ to +3.39‰) and display a decreasing trend in the directions of fiber growth from the central part, indicating an increased contribution of organic carbon to the calcite veins. Additionally, a consistent increase in trace element concentrations from the central part toward the fiber growth directions suggests a singular fluid source in a relatively closed environment, while other samples exhibit no distinct pattern, possibly due to the mixing of fluids from multiple layers resulting from repeated opening and closing of bedding-parallel fractures in the shales. The notable difference in δEu between the fibers on either side of the median zone indicates that previously formed veins acted as barriers, impeding the mixing of fluids, with the variation in δEu reflecting the differing sedimentary properties of the surrounding rocks. The in situ U-Pb dating of fibrous calcite veins yields an absolute age of 211 ± 23 Ma, signifying formation during the Late Triassic, which correlates with a shale maturity of 1.0‰ to 1.25‰. This integrated study suggests that the geochemical records of fibrous calcite veins document the processes related to overpressure generation and the opening and healing of bedding-parallel fractures within the Dalong Formation. Full article

Permian shale gas is a kind of energy resource with commercial development potential. The characteristics of its organic source and enrichment have received extensive attention in recent years. This study systematically analyzed the variations in types and assemblages of hydrocarbon-forming organisms across different stratigraphic layers of Permian shale in western Hubei through scanning electron microscopy (SEM) and microscopic observations. Moreover, the source characteristics and enrichment mechanisms of organic matter in Permian shale were identified. Hydrocarbon generation in Permian shale is primarily attributed to planktonic algae-derived acritarchs, supplemented by higher plants and green algae, based on the observation under the SEM and microscope. The hydrocarbon-forming microorganisms in the Gufeng Formation are predominantly characterized by acritarchs. A notable decrease in acritarch content is observed at the bottom of the Wujiaping Formation, accompanied by a significant increase in higher plant constituents and a slight rise in green algae abundance. Subsequently, from the middle-upper members of the Wujiaping Formation through the Dalong Formation, acritarch concentrations rebound while higher plants and green algae contributions diminish. The organic matter in the studied layer is predominantly generated from planktonic algae (acritarchs and green algae), with subordinate contributions from terrestrial higher plants. During the sedimentary stage of the Gufeng Formation, rising sea levels sustained a deep siliceous shelf environment in the E’xi Trough, where organic matter was primarily sourced from acritarchs, with limited terrigenous input. The regressive phase at the bottom of the Wujiaping Formation resulted in coastal marsh throughout the E’xi Trough, creating a mixed organic matter assemblage of aquatic planktonic algae and enhanced terrestrial higher plant material. As sedimentation progressed into the middle-upper Wujiaping Formation and Dalong Formation, the E’xi Trough evolved into a deep siliceous shelf and platform-margin slope environment. During this stage, organic matter was again predominantly supplied by planktonic algae (mainly acritarchs), with reduced terrestrial organic input. These findings provide valuable theoretical insights for guiding Permian shale gas exploration and development strategies. Full article

Based on mechanical experiments conducted on bulk raw coal and coal of different types in order to explore the correlations between the fractal dimension and the grain size gradation and strength parameters of coal samples, the fractal statistics method was used to statistically analyze the grain size distribution characteristics of tectonic soft coal, while fractal theory was applied to study the grain size fractal characteristics of tectonic soft coals of categories III–V. The results of this study show that coal types III–V have increasing fractal dimension numbers, and the content of coarse particles decreases with an increasing fractal dimension number. Within this sampling range, the Class V coal is better graded, and the fractal dimension number decreases as the distance of the sampling point from the fault zone increases. In the direct shear experiments, the internal friction angle of the bulk raw coal decreased linearly with an increasing fractal dimension number, and the regularity of the cohesive force and the fractal dimension number was not strong, but the adhesion cohesion of the types of coal exhibited a positive exponential relationship with the fractal dimension, and the relationship between the internal friction angle and the fractal dimension was not strong. There was a positive exponential relationship, and the internal friction angle was relatively stable. The uniaxial compressive strength of the types of coal exhibited a good correlation with the coefficient of firmness of the coal samples and the fractal dimension, and the coefficient of firmness of the coal samples was the main factor influencing the uniaxial compressive strength of the types of coal compared with the particle size gradation. Full article

Wellhead choke performance is critical for flowback choke-size managements in unconventional gas wells. Most existing empirical correlations were originally developed for oil and gas flow, and their accuracy for gas/water multiphase flowback remains uncertain. This study presents a data-driven approach to examine the choke–performance relationship during multiphase flowback. We compiled a flowback dataset containing 18,660 surface measurements from 37 shale gas wells in the Horn River Basin. Using machine learning, we modeled choke performance based on flowback features including water rate, gas/water ratio, wellhead and separator pressures and temperatures, and choke size. The models achieved strong predictive accuracy. Based on the machine learning results, we developed a new choke–performance correlation tailored to multiphase flowback. This model was validated against field data and showed reliable performance. The findings provide a useful tool for optimizing choke-size strategies during flowback in hydraulically fractured gas wells, especially in unconventional reservoirs. Full article

This study investigates geothermal clusters in the middle reaches of the Dawen River Basin, focusing on the developmental characteristics and genetic mechanisms of typical geothermal water exposures at key sites, including Daidaoan (Taishan), Qiaogou (Culai Town), and Anjiazhuang (Feicheng). Utilizing hydrogeochemical and environmental isotope analyses, we identify a dual groundwater recharge mechanism: (1) rapid infiltration via preferential flow through fissure media and (2) slow seepage with evaporative loss along gas-bearing zones. Ion sources are influenced by water–rock interactions and positive cation exchange. The hydrochemical types of surface water and geothermal water can be divided into five categories, with little difference within the same geothermal area. The thermal reservoir temperatures range from 53.54 to 101.49 °C, with the Anjiazhuang and Qiaogou geothermal areas displaying higher temperatures than the Daidaoan area. Isotope calculations indicate that the recharge elevation ranges from 2865.76 to 4126.69 m. The proportion of cold water mixed in the shallow part is relatively large. A comparative analysis of the genetic models of the three geothermal water groups shows that they share the common feature of being controlled by fault zones. However, they differ in that the Daidao’an geothermal area in Mount Tai is of the karst spring type with a relatively low geothermal water temperature, whereas the Qiaogou geothermal area in Culai Town and the Anjiazhuang geothermal area in Feicheng are of the gravel or sandy shale spring types with a relatively high geothermal water temperature. Full article

The accurate estimation of methane reserves in closed coal mines is crucial for supporting clean energy recovery and reducing greenhouse gas emissions. This study addresses the technical challenges associated with complex geological conditions and limited post-closure data in China’s closed mines. Three mainstream estimation methods—the material balance, resource composition, and decline curve—are systematically reviewed and applied to a case study in the Huoxi Coalfield. Results indicate that the material balance method provides upper-bound estimates but is highly sensitive to incomplete historical data, whereas the resource composition method yields more conservative and geologically realistic values. Although the decline curve method is not applied in this case, it offers potential for forecasting when long-term monitoring data are available. A multi-method integration approach, supported by enhanced data archiving and uncertainty assessments, is recommended to improve the accuracy and reliability of methane reserve evaluations in post-mining environments. Full article

The Jiaoshiba area, as an important production capacity contribution block for the Fuling shale gas field, is of great significance for its long-term stable production. This study is based on continuous coring, and uses methods such as whole-rock mineral analysis, porosity and permeability analysis, gas content analysis, and organic geochemistry to systematically analyze the influencing factors of reservoir properties and gas content in the studied interval. Combined with the variation law of TOC and other parameters with depth, the target reservoir is comprehensively evaluated, and the evaluation results are verified based on actual production data. The results show that the influence of minerals on permeability is very weak, and cracks can greatly improve permeability, but their contribution to porosity is not significant. Porosity has a certain impact on gas content, but it is not the main controlling factor. The pores related to quartz (organic silicon) are mostly organic pores, which host a large amount of shale gas, while clay minerals are not conducive to the occurrence of shale gas. Organic matter (OM) maturity contributes more to porosity than OM abundance, but OM abundance has a stronger impact on gas content than its maturity. The research intervals can be divided into four categories: Class I (①–③) is the best, followed by Class II (⑦–⑨); Class III (④–⑥) is poor, and Class IV (top, non-gas-bearing layer) is the worst. Full article

In recent years, the accurate evaluation of artificial fracture networks has become a key challenge in enhancing the effectiveness of reservoir stimulation in shale gas development. This paper systematically reviews the research progress on evaluation methods for artificial fracture networks in shale gas horizontal wells, covering two major technical systems: direct monitoring and dynamic inversion. Direct monitoring methods focus on technologies such as microseismic monitoring, tracers, wide-field electromagnetic methods, and distributed fiber optics. Dynamic inversion methods utilize data from fracturing construction curves, shut-in water hammer effects, and flowback production, and combine numerical simulations with artificial intelligence algorithms to infer fracture network parameters, although the issue of non-uniqueness in solutions remains to be addressed. Research shows that no single technology can comprehensively characterize fracture network features. Future directions should involve the integration of multi-source data (geophysical, chemical, fiber-optic, and dynamic production data) to construct intelligent evaluation frameworks, validated by field experiments and dynamic data simulations. The introduction of artificial intelligence and big data technologies provides new ideas for fracture network parameter inversion, but their effectiveness still requires support from more case studies. This paper provides theoretical guidance and practical reference for the optimization and integration of fracture network evaluation technologies in efficient shale gas development. Full article