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The brittleness index, as the most important parameter for brittleness evaluation, directly affects the compressibility of unconventional reservoirs. Currently, there is no unified calculation method for the brittleness index. This article uses a three-axis rock mechanics servo testing system to test the rock mechanics parameters of shale oil reservoirs in Block Y of the Ordos Basin and uses an X'Pert PRO X-ray diffractometer to test the rock mineral composition. The average volume fraction of quartz minerals, feldspar, and clay minerals in 36 samples of Block Y was tested to be 22.6%, 51.6%, and 18%, respectively. Calcite, dolomite, and pyrite are only present in a few samples. When the confining pressure is 30 MPa, the elastic modulus of the Chang 7 shale in this block is 14.72–34.58 GPa, with an average value of 23.77 GPa; The Poisson's ratio ranges from 0.106 to 0.288, with an average of 0.182; The differential stress ranges from 100.8 to 260.1 MPa, with an average of 164.36 MPa; The peak strain ranges from 0.57 to 1.21, with an average of 0.91. This article compares several mainstream brittle index evaluation methods and identifies the most suitable brittle index evaluation method for Block Y. Using the Jarvie mineral composition method to calculate the brittleness index 1 (MBI), the average value of 36 experimental results is 0.5393. Using the Rickman normalized Young's modulus and Poisson's ratio average value to calculate the brittleness index 2 (EBI), the average value of 36 experimental results is 0.5204. Based on the stress-strain curve and energy method, a model for brittleness index 3 (DBI) is established, and the average value of 36 experimental results is 0.5306. The trend of the brittleness index calculated by the three methods is consistent, indicating the feasibility of the newly established brittleness evaluation method. From the perspectives of mineral composition, rock mechanics parameters, and energy, establishing a brittleness evaluation method for shale oil reservoirs and studying its evaluation method is of great significance for sweet spot prediction in reservoir engineering, providing theoretical support for the selection of fractured intervals in the Chang 7 shale oil reservoir in Block Y of the Ordos Basin. [ABSTRACT FROM AUTHOR]

The efficient development of tight gas reservoirs is significantly enhanced by multi-stage and multi-cluster fracturing techniques in conjunction with horizontal well technology, leading to substantial increases in reservoir drainage volume and individual well productivity. This study presents a tailored fine-fracturing approach for horizontal wells in tight gas reservoirs, supported by a gas–water two-phase numerical simulation model. Utilizing the orthogonal experimental design method, we simulated and optimized various fracture distribution schemes to refine fracturing parameters for maximum efficiency. The optimization was further validated through a comparison with actual well completion and development dynamics. The quantitative results highlight the optimal fracture distribution for horizontal wells, with a horizontal section length of 1400 to 1600 m and 14 to 16 fracturing stages. The pattern features a "dense at both ends and sparse in the middle" strategy, with stage spacing of 80 to 110 m, and a "longer in the middle and shorter at both ends" fracture half-length of 100 to 140 m, achieving a fracture conductivity of 30 μm2·cm. To ensure the economic feasibility of the proposed fracturing strategy, we conducted an economic evaluation using the net present value (NPV) method, which confirmed the robustness of the optimization outcomes in terms of both technical performance and economic viability. The reliability of these optimization outcomes has been confirmed through practical application in the development of horizontal wells in the study area. This research approach and methodology can provide theoretical guidance for the design of hydraulic fracturing operations and the integration of geological and engineering practices in similar unconventional oil and gas reservoirs. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]