Modeling non-Newtonian turbulent slurry flow with axial particle dispersion: application to hydraulic fracturing

Experimental study on the cross-layer propagation behavior of pulsed hydraulic fracturing in coal measure strata

Study on the guiding mechanism of controlling pore water pressure on the propagation path of hydraulic fractures

An adaptive multiscale cohesive phase-field method for hydraulic fracturing in cleat-developed coal seams

The fractured lacustrine carbonate oil reservoir in the Lower submember of Member 4 (Qian-4) of the Qianjiang Formation in the Zhongshi area, Jianghan Basin, represents an important target for hydrocarbon exploration and exhibits substantial exploration and development potential. To clarify the mechanisms by which fractures control reservoir effectiveness, this study integrates core description, thin-section petrography, petrophysical measurements, and geophysical interpretation to systematically characterize matrix properties and fracture development. Results show that the reservoir matrix is dominated by micritic carbonate rocks and grain-dominated carbonate rocks, and overall exhibits low-porosity and ultra-low-permeability characteristics, with an average porosity of 5.19% and permeability generally below 5 mD. Fractures are well developed within the matrix, mainly comprising non-tectonic bedding-parallel fractures and tectonic high-angle fractures. Fracture-related porosity averages 8.42%, and permeability can reach 10–100 mD or higher. The fracture attributes and their spatial distribution are the key controls on hydrocarbon enrichment and deliverability; the occurrence of different fracture types across lithologies and sublayers can significantly enhance reservoir flow capacity. Moreover, natural-fracture characteristics provide critical geological constraints for hydraulic fracturing design and implementation. These findings offer a theoretical basis for fine-scale exploration and development of fractured lacustrine carbonate reservoirs.

This article provides a comprehensive analysis of the effectiveness of oil production intensification methods applied at the X oil field. Within the scope of the study, the geological and physical characteristics of the field, existing production indicators, and reservoir pressure dynamics were systematically investigated. The main technological methods applied for production enhancement — waterflooding, hydraulic fracturing, acid treatment, gas injection, and chemical agent injection — were analyzed in detail, and the technological process, application mechanism, and performance indicators of each method were comparatively evaluated. The analysis revealed that the application of complex intensification measures increased reservoir permeability by 2–3 times, raised oil production in wells by an average of 35–40%, and significantly improved the reservoir pressure maintenance coefficient. The study demonstrates that the proper selection and combined application of intensification methods is of decisive importance for extending the productive life of the field and increasing economic efficiency. Keywords: oil production intensification, waterflooding, hydraulic fracturing, acid treatment, reservoir pressure, effectiveness analysis, oil field.

The principal difficulty in studying the physico-mechanical and filtration-capacity properties of coals and host rocks under laboratory conditions using core samples lies in reproducing natural thermodynamic conditions characteristic of in situ depths. To address this issue, specialized equipment and methodologies for transferring measurement results are employed, including the Hoek–Brown failure criterion, the structural weakening coefficient, and the development of thermodynamic models. The reliability and accuracy of such measurements are determined by the degree of conformity between the adopted laboratory conditions and natural in situ conditions, the number of samples representing different lithological varieties, and the adequacy of sampling procedures ensuring representativeness. Particular challenges arise when sampling cleated and fractured coals formed under natural stress–strain conditions and contain methane, which significantly influences their physical properties. These difficulties are especially pronounced in prepared-for-mining high-gas-content coal seams of the Karaganda Basin at depths of approximately 700 m, where obtaining representative samples is technically complicated. Reliable values of the physico-mechanical properties of the coal–rock mass are essential for geomechanical calculations aimed at ensuring safe mining of high-gas-content seams through risk assessment of geodynamic phenomena, particularly in zones of geological disturbances, floor heave, and roof collapse. In this context, the use of a comprehensive suite of geophysical logging data from exploration boreholes makes it possible to obtain continuous, high-precision information on physico-mechanical and filtration-capacity properties. These methods are particularly important for characterizing the coal–rock mass in operating mines, since the natural state of host rocks and prepared coal seams is altered due to stress relief caused by mine workings, preliminary degasification measures, and hydraulic fracturing. The problem addressed is the need for reliable assessment of rock and coal seam parameters under natural thermodynamic stress–strain conditions, taking into account lithological composition, structural heterogeneity, fracture development, stratigraphic differentiation, and gas saturation. The aim of this study is to ensure efficient and safe coal extraction based on geomechanical calculations utilizing physico-mechanical and filtration-capacity properties of host rocks and gas-bearing coal seams, whether prepared for mining or not yet extracted. The research methods are based on an integrated complex of geophysical logging of exploration wells, specialized software tools, and statistical processing techniques to identify patterns in physico-mechanical and filtration-capacity properties of host rocks and coal seams under natural stress–strain conditions, as well as to determine the nature of changes in these properties within coal seams and roof and floor rocks in prepared mining areas. The physico-mechanical and filtration-capacity properties of host rocks and coals from the Lenin and Kazakhstanskaya mines were determined. Regularities governing the application of these parameters to coals of different formations and depths were established; fracture orientations and characteristics were evaluated; and relationships between changes in coal seam parameters and gas content were identified. A comprehensive methodological framework for studying the physical and capacity properties of the coal–rock mass under natural thermodynamic conditions has been developed. Its primary application is the investigation of coal seams prepared for mining to support geomechanical calculations for efficient and safe coal extraction, the implementation of degasification measures for high-gas-content seams, and the assessment of gas-dynamic risks based on the character of variations in physical parameters.

Shale oil reservoirs are characterized by ultra-low matrix permeability. After large-scale hydraulic fracturing is applied to horizontal wells, fluid transport becomes highly complex, posing major challenges for accurately predicting production performance. In this study, a coupled multi-mechanism numerical model is developed for shale oil reservoirs with complex fracture networks. Using the Embedded Discrete Fracture Model (EDFM), the mass transport between the fracture and matrix and within the hydraulic fracture network can be accurately quantified. Based on core analysis and fluid experimental data, the dynamic evolution of rock and fluid properties is characterized by incorporating nanopore confinement effects, stress sensitivity, and threshold pressure gradient behavior. Numerical simulations are then conducted to investigate the impacts of multiple mechanisms, including nanopore confinement effects, stress sensitivity, and threshold pressure gradient, as well as their coupling effects on shale oil production. A field application is carried out using Well H1 in the Qingcheng shale oil reservoir. Simulation results indicate that nanopore confinement reduces bubble-point pressure, leading to a 3.60% increase in cumulative oil production and a noticeable reduction in the producing gas–oil ratio. Stress sensitivity causes a 2.68% decrease in cumulative oil production and suppresses gas production. The threshold pressure gradient exerts the strongest negative impact, resulting in an 8.01% reduction in cumulative oil production and a slight decrease in gas–oil ratio. When all mechanisms are simultaneously considered, strong nonlinear interactions emerge, yielding a 7.09% reduction in cumulative oil production—significantly different from the linear superposition of individual effects. These results demonstrate the necessity of accounting for multi-mechanism coupling to achieve reliable production forecasting in fractured shale oil reservoirs.

It is of great significance to clarify the evolution law and control mechanism of fracture conductivity in different production stages for the efficient development of coalbed methane. However, research on fracture conductivity in coal–rock remains limited, and the existing models are inadequate for predicting fracture conductivity with a consideration of staged proppant crushing. To address this gap, long-term conductivity tests were conducted on deep coal–rock under varying closure pressures and proppant gradation ratios. Within a coupled computational fluid dynamics and discrete element method (CFD-DEM) framework, a particle substitution scheme was integrated with the energy-based breakage model (Tavares breakage model) to develop a fracture conductivity predictor that incorporates proppant crushing and captures the time-dependent kinetics of proppant breakage during fracture conductivity evaluation. The model’s predictions align well with the experimental data, with an average error of less than 5%. The results indicate that fracture conductivity evolution can be delineated into three stages according to particle-breakage characteristics, (i) proppant pack compaction, (ii) the primary crushing of coarse proppant grains, and (iii) the secondary crushing of proppant fines, and the contributions of these three stages to the total conductivity loss are approximately 60%, 30%, and 10%, respectively. At a low closure pressure, fracture conductivity varies markedly among proppant packs with different particle sizes; once the closure pressure exceeds 40 MPa, the proppant pack enters the fines-breakage stage, and the conductivity differences among various particle size blends become marginal. Furthermore, a semi-empirical prediction model incorporating a composite crushing factor (CCF) was developed based on the Kozeny–Carman relationship, enabling a rapid evaluation of fracture conductivity in deep coal–rock fractures. Overall, these results provide a practical basis for fracture conductivity prediction and hydraulic fracturing parameter optimization in coal–rock reservoirs.

Controlling Bottom-Water Coning Using a Degradable Temporary Barrier During Plugging and Conductivity Loss After Hydraulic Fracturing

Experimental and Mechanistic Investigation on Time-Delayed Initiation of Hydraulic Fractures in Shale Under Constant Pressure Injection

Placement of sand and granular activated carbon in hydraulic fractures for contaminant remediation in low-permeability formations.

Fluid flow and heat transfer during staged multi-cluster fracturing treatments along horizontal wells — Application for hydraulic fracture characterization using distributed temperature sensing

Study on the gradient distribution of coal seam stress and the mechanism of hydraulic fracture damage propagation

Rational design of perlite-bauxite-based low-density ceramic proppants for hydraulic fracturing

Microseismic monitoring and hydro-mechanical-damage simulation of vertical-well hydraulic fracturing in extra-thick hard roof strata

Coupling of peridynamics and MRST for simulation of hydraulic fracturing in porous media

Study on the initiation and propagation law of hydraulic fractures in tight reservoirs with cemented natural fractures for clean natural gas production

Accurate evaluation of fracability in unconventional reservoirs is essential for optimizing fracturing intervals and assessing productivity. Traditional fracability models, typically based on linear weighted and geometric average methods, suffer from subjective biases and neglect the correlation of factors. It is difficult to characterize and quantify the fracture network modification and the actual fracturing effect. To address these limitations, a new comprehensive fracability evaluation model was proposed based on multiplicative synthesis, incorporating the coupling effects of rock mineral properties, mechanical characteristics, in situ stress, and natural structural planes. The novelty lies in avoiding the weight calculations of factors, ensuring easy distinction of evaluation grades, continuous and monotonous results, and significant practicality and superiority. Brittle mineral content, elastic modulus, and Poisson's ratio were utilized to characterize the mineral and mechanical brittleness. The degree of natural fracture development was quantified through fractal dimensions and grid coverage methods. True triaxial hydraulic fracturing experiments and finite-element-based numerical simulations were used to analyze the spatial morphology and stimulated reservoir volume of hydraulic fractures influenced by fracability, and the model accuracy was validated with on-site microseismic and electromagnetic monitoring. The method was applied to the continuous fracability grading evaluation and sweet-spot prediction of deep sandstone reservoirs in the Junggar Basin. In addition, a three-dimensional block model of lateral heterogeneous fracability based on the distance power inverse method was established, enabling precise identification of geological sweet spots and optimal perforation intervals. The findings provide critical insights for accurately evaluating unconventional reservoir fracability and optimizing fracturing designs.

Mathematical foundations for play-agnostic thermo-poro-hydro-mechanical modeling of hydraulic fracture initiations from perforated wells: Towards a predictive tool