Junbin Chen

Coal gangue aggregate has high water absorption and a porous microstructure, both of which can reduce the mechanical performance of coal gangue concrete (CGC). This study examined whether hooked steel fibers can compensate for this strength loss and improve the mechanical behavior of steel fiber-reinforced coal gangue concrete (STCGC). Seven mixtures were prepared by varying the coal gangue replacement ratio (0%, 25%, 50%, and 75%) and, at 50% replacement, the steel fiber content (0%, 0.5%, 1.0%, and 1.5%). In total, 210 specimens were tested at 7 d, 14 d, and 28 d by cube compression, splitting tensile, axial compression, and elastic modulus tests. Scanning electron microscopy and ABAQUS mesoscopic simulation were used to interpret the failure mechanism and verify the compressive response. The results show that increasing coal gangue replacement reduces strength because of the porous and weak aggregate structure, whereas steel fibers improve crack resistance and post-cracking integrity. Compared with the 50% CGC mixture, steel fiber addition increased the average cube compressive strength, splitting tensile strength, axial compressive strength, and measured elastic modulus by 2.26%, 24.61%, 23.26%, and 59.47% (a mixture-specific result under the present test conditions; see Results for interpretation), respectively. Under the specific baseline of 50% coal gangue replacement, the 1.0% steel fiber mixture achieved the most balanced mechanical performance among the tested series Strength-conversion equations and stress-strain constitutive relationships were fitted for the tested mixtures. The simulated cube compressive strengths followed the experimental trend, indicating that the mesoscopic model can reproduce the compressive failure pattern of STCGC within the scope of the present mixtures. This study provides a test-calibrated basis for using steel fibers to improve the mechanical performance of coal gangue aggregate concrete.

China’s deep coalbed methane (CBM) resources hold significant development potential, yet their commercial exploitation remains hindered by four interrelated reservoir challenges: substantial burial depth, elevated in situ stress, ultra-low matrix permeability, and pronounced stress-dependent permeability decline. These conditions collectively induce rapid reservoir energy depletion and flow-path deterioration, leading to characteristic production behavior—namely, high initial gas rates followed by steep decline and persistent instability in long-term output. Accordingly, a rigorously optimized production system is indispensable to suppress formation damage, sustain desorption-driven gas release, and maximize ultimate recovery efficiency. To address this, this study establishes a physics-based numerical model that integrates field-calibrated geological and operational parameters, gas–water two-phase flow dynamics, coupled desorption–diffusion–seepage processes, and quantitatively constrained stress–permeability relationships for coal. Implemented in the CMG-IMEX simulator, the model is validated through robust history matching against production data from ten representative wells. A comparative analysis of two drawdown management strategies—the conventional constant-decline approach and the progressively decreasing drawdown strategy—demonstrates clear performance differentiation in both cumulative production and reserve utilization. Under the conventional scheme, the average ultimate recovery factor at economic abandonment reaches only 36.42%, with adsorbed-gas recovery limited to 25.53%, underscoring substantial untapped resource potential. In contrast, the progressively decreasing drawdown strategy alleviates multiphase flow restrictions, improves pressure maintenance, and elevates the average ultimate recovery factor to 40.43%—a net gain of 4.43 percentage points in adsorbed-gas recovery. Sensitivity analysis further identifies an initial drawdown of 5 MPa as the optimal balance between early productivity and reservoir sustainability. The coupling among reservoir pressure, flowing bottomhole pressure, and casing pressure enables the bottomhole drawdown-control protocol to be converted into a surface-measurable casing-pressure decline-rate criterion. These findings improve the mechanistic understanding of gas–water co-production in deep CBM systems and provide an operational framework for production-system design.

To clarify how shale-reservoir heterogeneity constrains hydraulic-fracturing effectiveness in complex structural areas, this study analyzes exploration well X in the Mugan–Shoushan area, Yunnan Province, using organic geochemistry, petrology and mineralogy, reservoir-property, and rock-mechanical data from the Wufeng–Longmaxi formations. The results show pronounced vertical engineering-geological differentiation. Average clay content decreases from 42% to 8%, Average carbonate minerals increase from 16% to 50%, and quartz is anomalously enriched in the Longyi 1-1 layer of the Longmaxi Formation (Longyi 1-1; 76%). The Longyi 1-3 layer of the Longmaxi Formation has the highest porosity (9.37%) but low matrix permeability (0.013–0.019 mD); the Longyi 1-2 layer of the Longmaxi Formation is highly brittle and tight; and the Longyi 1-4 layer of the Longmaxi Formation is highly ductile and water-rich. Accordingly, four engineering geological facies are defined: Type I, organic-rich, moderately brittle, and moderately ductile composite facies; Type II, organic-rich, highly brittle, tight, and strongly stress-sensitive facies; Type III, organic-poor, highly ductile, water-rich, and strongly water-sensitive facies; and Type IV, highly brittle, fracture-developed, and high-adsorption facies. Implications for fracturing are proposed for each facies, including mixed-fluid network stimulation, acid pretreatment with controlled flowback, interval avoidance, and coordinated stimulation with adjacent main reservoirs.

The Mugan Syncline in northeastern Yunnan represents a significant relay area for shale gas exploration in China. However, due to the combined effects of tectonic superimposition and sedimentary heterogeneity, systematic investigations into the intervals hosting high-quality shales and the coupling relationships among microfacies, reservoir quality, and gas-bearing properties remain insufficient. The core objective of this study is to establish a high-resolution microfacies framework and to quantitatively elucidate the multi-parameter coupling mechanisms by which microfacies control organic matter enrichment, pore development, and gas storage capacity in this structurally complex, basin-margin setting. By integrating core observations, thin-section petrography, scanning electron microscopy (SEM), whole-rock X-ray diffraction (XRD), total organic carbon (TOC) analysis, trace-element geochemistry, and well-logging data, we establish a stratigraphic subdivision and cross-well correlation framework for the Wufeng (WF) Formation and the Long11 submember. Furthermore, a lithofacies (microfacies) identification scheme based on a “TOC + siliceous (quartz + feldspar)–carbonate–clay” ternary classification is applied. The results reveal the following: (1) Based on the locally developed erosional contact at the boundary between the Longmaxi (LMX) Formation and the underlying Guanyinqiao Formation, the WF Formation in the study area can be subdivided into two submembers, whereas the Long11 submember comprises four sublayers. The thicknesses of the Long11-1 through Long11-3 sublayers range from 21.42 to 25.47 m, exhibiting a subtle northward-thickening trend. In contrast, the Long11-4 sublayer displays a relatively uniform thickness and high stratigraphic continuity of shale deposition. (2) Based on TOC content and ternary mineral composition, the shales are classified into four lithofacies associations and sixteen lithofacies subtypes. The main favorable microfacies assemblages are identified as high-carbon siliceous/calcareous shale (C-1), high-carbon calcareous/siliceous mixed shale (M-1), carbon-rich argillaceous siliceous shale (S-3), and high-carbon siliceous/argillaceous mixed shale (M-2). (3) High-quality shales (TOC > 2%) are predominantly developed in the upper member of the WF Formation and in the Long11-1 through Long11-4 sublayers. Their lateral distribution is markedly controlled by variations in paleotopography and terrigenous sediment supply. (4) The microfacies exert a synergistic control on shale gas enrichment. Carbon-rich argillaceous siliceous and siliceous-rich microfacies generally correspond to higher TOC contents and better-developed organic-matter pores. Siliceous-rich and mixed microfacies exert a positive influence on pore preservation and rock brittleness. The gas-bearing properties are influenced not only by TOC content but also by pore structure, mineral composition, and tectonic preservation conditions. The findings of this study provide a scientific basis for the prediction of shale gas sweet spots and the optimization of target intervals in the Mugan Syncline and other structurally and sedimentologically complex regions of northeastern Yunnan.

Continental shale oil fracturing dynamics are governed by interactions between hydraulic fractures and pre-existing natural fractures. This study establishes a fluid–solid coupling model using globally embedded cohesive elements to simulate fracture propagation in naturally fractured reservoirs. Key factors affecting fracture network complexity were quantified: (1) Weakly cemented natural fractures (bond strength coefficient 3/min enhances the stimulated volume by 90% through improved fracture dimensions. The findings provide mechanistic insights for optimizing fracture network complexity in shale reservoirs.

A radial well has a unique wellbore configuration. Fracture propagation in radial well deflagration fracturing is studied rarely. The mechanism of interaction between deflagration fractures, natural fractures, and micro-fractures is still unknown. Based on continuum mechanics, damage mechanics, and variational principles, a numerical model of fracture propagation in deflagration fracturing is established with the Hamilton principle and phase-field fracture theory. The effects of horizontal principal stress difference, natural fracture distribution, and micro-fractures around the wellbore on fracture propagation in deflagration fracturing are studied. First, when no natural fractures are developed around the radial well, fractures are initiated at both ends of the radial well. Second, when there are three natural fractures around the radial well, the created fractures have the morphology of shorter fractures in the middle and longer fractures on both sides under stress interference mechanisms. Third, a larger density of natural fractures causes obvious stress superposition, changes the initiation points of radial wells and fracture morphology, and increases fracture width and reservoir stimulation volume. Fourth, as the micro-fractures increase, their interference and induction effects on deflagration fractures are enhanced gradually, and the deflection angle of fractures increases by 38.7%. The study provides a reference for optimizing deflagration fracturing in a radial well.