Coal-measure gas co-production is a critical strategy for enhancing the single-well productivity of unconventional natural gas. However, the pronounced vertical heterogeneity and complex combinations of co-existing reservoirs create substantial asynchronous propagation behaviors during hydraulic fracturing, fundamentally limiting the accurate prediction of multi-reservoir stimulation outcomes. This study employs numerical simulation to investigate fracture development, using the reservoir combinations of the Linxing area on the northeastern margin of the Ordos Basin as a geological model. Our results show that the thickness ratio and mechanical properties of individual rock layers are primary controls on fracture propagation. Specifically, a higher coal seam thickness ratio reduces fracture half-length but increases width, while a greater sandstone layer thickness ratio decreases width and increases height. We further propose the novel concept of the fracture propagation coefficient to characterize the heterogeneity of the fracturing process. It is found that fracture development is closely related to the distance from the injection point, the physical properties of rock layers, and the mechanical property differences between adjacent strata. The distribution of fractures is governed by the coupling effect between injection point location and reservoir mechanical properties. The reservoir–fracture response relationships established in this study provide a scientific basis for optimizing reservoir selection and fracturing parameters in coal-measure gas development.
To address the unclear fracture propagation behavior and the insufficient understanding of the influence mechanisms of fracturing parameters during the hydraulic fracturing of deep coalbed methane reservoirs in the Yan’an Gas Field, Well JY1 in the No. 8 coal seam of the Benxi Formation in Block N was selected as the study object. An integrated three-dimensional geomechanics–fracture propagation model coupling geomechanical conditions, cleat characteristics, and fracture propagation was established. Fracture propagation simulations were conducted under different injection rates, fluid volumes per stage, and proppant volumes per stage. The results indicate that when main fractures intersect with cleats, they may exhibit deflection, branching, or direct crossing. Increasing the injection rate enhances the driving force at the fracture tip and improves the penetration capability of main fractures. Increasing the fluid volume improves fracture coverage and inter-cluster connectivity. Increasing the proppant volume contributes to greater residual fracture width, higher proppant placement concentration, and improved fracture conductivity. An injection rate of 19–21 m3/min, a fluid volume per stage of 2500–2700 m3, and a proppant volume per stage of 280–320 m3 provide a favorable balance between fracture network development and effective proppant support under the studied reservoir conditions.
Hydraulic fracturing is a key reservoir stimulation technology for enhancing hydrocarbon recovery from unconventional reservoirs. However, fracture initiation and propagation are governed by complex thermo-hydro-mechanical (THM) coupling processes, which strongly influence fracture geometry, propagation dynamics, and overall reservoir stimulation efficiency. In this study, a fully coupled THM numerical model is developed to investigate the multiphysics mechanisms governing hydraulic fracture initiation, propagation, and evolution under realistic reservoir conditions. Beyond hydraulic fracturing applications, the proposed framework can also be extended to analyze fracture propagation, multiphase fluid migration, and coupled rock–fluid interactions in subsurface energy systems, including geological carbon storage and geothermal energy extraction. The simulation results demonstrate that reservoir temperature and reservoir pressure significantly influence fracture propagation by altering the pressure differential between the hydraulic fracture and the in situ stress field. Elevated reservoir pressure promotes fracture extension, whereas elevated reservoir temperature suppresses fracture propagation by increasing fluid leak-off and accelerating pressure dissipation. Furthermore, molecular-scale analyses are conducted to interpret how thermodynamic conditions influence intermolecular interactions, fluid behavior, stress transfer, and fracture evolution, and the macroscopic simulation results are interpreted in light of molecular-scale hypotheses drawn from previous literature concerning intermolecular interactions, hydrogen bond network evolution and polymer adsorption. These findings provide new insights into the coupled THM mechanisms controlling fracture evolution and establish a theoretical basis for optimizing hydraulic fracturing strategies, improving energy recovery efficiency, and advancing subsurface energy engineering applications. The proposed framework also provides valuable guidance for the sustainable development of unconventional hydrocarbon resources, enhanced geothermal systems, and geological carbon storage technologies, thereby contributing to long-term energy security and sustainable energy supply.
Li-Li Wang, Yan-Ming Zhang, Zhan-Guo Ma et al.· Processes· 0 citations
Deep coalbed methane (CBM) resources are abundant and represent a critical component of future energy supply and carbon reduction strategies. However, deep coal seams are characterized by well-developed cleat systems and high Poisson’s ratios, rendering the mechanisms of hydraulic fracture initiation, propagation, and complex fracture network development insufficiently understood. In this study, deep coal rock at a burial depth of 2700 m is investigated. A finite element–based hydraulic fracturing model incorporating complex face-cleat and end-cleat networks is established by explicitly representing cleat geometry, mechanical properties, fluid leak-off behavior, and hydraulic loading conditions. Using this model, the effects of cleat inclination angle, horizontal stress difference, and displacement on fracture evolution are systematically analyzed. The results indicate that when face cleats are orthogonal to the maximum horizontal principal stress, fractures preferentially penetrate cleats and propagate along the maximum stress direction. In contrast, when face cleats form acute angles with the maximum horizontal stress, pronounced branching fractures develop along both face and end cleats, with propagation increasingly dominated by face cleats as the angle decreases. Increasing horizontal stress difference suppresses fracture branching, leading to simpler fracture networks but greater total fracture length and maximum fracture width. Moreover, under identical injection pressures, the equal-pressure fracture length increases, indicating enhanced fracture propagation capacity. With increasing displacement, fracture networks evolve from simple to complex patterns, accompanied by accelerated propagation and enlarged fracture widths; however, excessive displacement intensifies fluid leak-off, ultimately reducing the equal-pressure fracture length.
Hydraulic-fracture transmission across lithologic interfaces governs fracture-height growth and reservoir connectivity in shale–sandstone interbedded reservoirs, yet the coupled effects of mechanical contrast, interface properties, layer geometry, and operational parameters remain insufficiently quantified. A two-dimensional plane-strain hydraulic-fracturing model was developed in ABAQUS by coupling Biot poroelasticity, cohesive-zone damage, and fracture-fluid flow. The model explicitly represents thin, alternating continental shale–sandstone layers, lithology-dependent in situ stress and stiffness, and cohesive interfaces; its implementation was assessed against the KGD solution and published layered-rock fracture morphologies. Under the simulated conditions, increasing the shale-to-sandstone elastic-modulus ratio from 0.4–0.5 to 0.6–0.8 reduced the number of penetrated layers from eight to six. Increasing tensile strength from 4 to 16 MPa reduced the number of penetrated layers from ten to six and the final fracture length from 32 to 21 m, while increasing the maximum aperture from 6.75 to 9.02 mm. A sandstone interlayer thickness of approximately 3 m marked a transition in the present parameter set rather than a universal threshold. Sandstone-centered perforation and higher injection rates promoted vertical connectivity, whereas very high fluid viscosity increased near-wellbore aperture but restricted long-distance fracture-height growth. These results provide a mechanics-based framework for optimizing perforation placement and stage-specific fluid design in continental interbedded shale reservoirs.
Hydraulic fracturing (HF) remains the primary stimulation technique, and for low-permeability reservoirs it is a prerequisite for economically viable development. At the same time, the production gain delivered by the treatment sharply increases the risk of fracture breakthrough into water- and gas-saturated intervals, which in turn degrades recovery efficiency. Minimizing such risks calls for robust, physically sound HF designs that prevent out-of-zone height growth while sustaining high well productivity.Since fracture geometry is controlled largely by elastic properties (Young’s modulus, Poisson’s ratio) and stress gradients, the key task reduces to ensuring the reliability of these parameters. This raises the question of using not generic reference values, but rather data derived from site- and formation-specific logging and testing. Core tests from target intervals are calibrated against acoustic logging data (compressional and shear wave times) with subsequent conversion from dynamic to static elastic parameters.The proposed approach was validated on a field in Western Siberia. Within the pilot area, a set of typical challenges was identified, research objectives were formulated, and a geomechanical model was constructed. For the initial geomechanical model, data from neighbouring fields were utilized. Within the distinguished mechanical facies of the section, the well-log curves involved in the calculations underwent filtering, correction, and reconstruction. In addition, core-based correlation relationships were employed for the computations. On this basis, continuous profiles of elastic-strength properties, overburden and pore pressures, and in-situ stress components were calculated.The derived relationships were incorporated into the geomechanical property library of a frac simulator. As a result, elastic and strength characteristics can now be estimated using only the lithological subdivision obtained from standard log interpretation data (RIGIS) and the pore pressure gradient at the time of treatment planning. Directions for future work have been outlined, and a comparative analysis of conventional HF design practices versus the geomechanics-based approach has been performed.
A. M. Kazantseva, S. Shalnev, N. Zakirov· Petroleum Engineering· 0 citations
Sequential injection of fluids with contrasting mobility in porous media causes the leading fluid's pressure history to reshape the permeability field, which then governs the seepage and fracture propagation of the following fluid. Using a cross-scale model that couples seepage and discrete element fracturing and distinguishes the flow behaviors of CO2 and water, this study investigates CO2 pre-injection enhanced hydraulic fracturing in coal, capturing permeability evolution driven by CO2 pressure diffusion and subsequent hydraulic fracture propagation. The CO2 pressurization rate controls the time for pressure diffusion, thereby determining permeability uniformity; an intermediate rate creates a moderately heterogeneous field, maximizing fracture length, area, and fractal dimension, while lower and higher rates, respectively, over-homogenize and over-localize the field, reducing complexity. CO2 pre-injection pressure governs the magnitude and heterogeneity of permeability enhancement, transitioning fracture propagation from length-dominated to complexity-dominated. Constant pressure duration regulates the spatial extent of CO2 diffusion, longer durations homogenizing the field and favoring primary fracture extension over complexity. Water injection pressure governs the driving pressure gradient and the shift from branching networks to localized channel flow. Below this threshold, the gradient cannot fully penetrate the CO2-treated zone, limiting fracture complexity; above it, faster flow suppresses branching, widens fractures, and reduces the fractal dimension. Orthogonal analysis reveals a hierarchical control: water pressure has the greatest influence, followed by CO2 pressure, water pressurization rate, constant pressure duration, and CO2 pressurization rate. These findings link pore pressure diffusion and permeability evolution to fracture complexity, providing a theoretical basis for the optimization of process parameters.
Shuo Dai, Xin-Wei Zhang, Zhaolong Ge et al.· The Physics of Fluids· 0 citations
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