In this study, a simulation model of fracture network geometry in fractured and porous elastic reservoirs is established based on the globally embedded three‐dimensional cohesive zone model (3D CZM). The effects of stress interference between natural fractures (NFs), horizontal stress difference (HSD), injection rate, and fluid viscosity on fracture geometry were studied and the phenomenon of rapid failure of unconventional reservoir productivity was explained from a coupling fluid flow/geomechanics perspective. The intersection behavior of hydraulic fracture (HF) and NF is simulated; the simulation results are in good agreement with Blanton's criterion, proving the reliability of the 3D CZM. The research results show that in the process of hydraulic fracturing, in addition to the strong stress interference between HFs, there is also strong stress interference between NFs. Stress interference has an important impact on the traction separation of cohesive elements (CEs) and a continuous dynamic impact on the NF opening. For reservoirs with a small HSD, higher injection rate and fluid viscosity produce smaller stimulated reservoir volume (SRV) length, but larger SRV width. Complex fracture networks tend to develop in the vicinity of horizontal wellbores, which leads to rapid failure of productivity. For this kind of reservoir, minimizing the impact of stress interference with a small injection rate is recommended instead of maximizing the injection rate and fluid viscosity. For reservoirs with a large HSD, lower injection rate and fluid viscosity produce larger SRV length and smaller SRV width. The fracture geometries tend to develop simple straight fractures, which leads to low initial productivity. Thus, adopting a relatively large injection rate and fluid viscosity is recommended to make full use of stress interference effects to increase the development of complex fractures near horizontal wellbores. The results of this study can serve as a guide in evaluating fracture complexity, SRV, proppant migration, drainage reservoir volume (DRV), and well completion design; they can also promote the in‐depth understanding of the coupling effect between fluid flow and geomechanics.

This paper uses the finite-discrete element method (FDEM) to establish a fluid–solid coupling model for the propagation of multi-cluster hydraulic fractures. The validity of the proposed model is verified using the analytical solution and onsite microseismic data. The results show that with the approach angle increases, the propagation of hydraulic fracture transitions from a single capture mode to the mixed modes of capture, crossing and blocking. The total length of hydraulic fractures is negatively correlated with the approach angle and cohesion of natural fracture, and positively correlated with the distribution density and bandwidth of natural fracture. The length of shear fractures initially increases and then decreases with the increase in approach angle, showing negatively, positively, and positively correlated with cohesion, length, and bandwidth, respectively, while the trend of tensile fracture length is opposite to it. The tortuosity of hydraulic fractures (which is used to characterize the complexity of fracture morphology) initially decreases and then increases with the increase in the approach angle, negatively correlated with the cohesion of natural fracture, and positively correlated with the distribution density and bandwidth of natural fractures. Comparatively, the fracture propagation morphology is the most complex at the approach angle of 45°, which is more conducive to full reservoir enhancement. Conversely, under conditions of high cohesion, narrow width, and low-density distribution of natural fractures, the fracture morphology is relatively simple, all of which are unfavorable for reservoir enhancement in the target segment.

China has surpassed the US to become the largest energy consumer in the world, and it is projected that China's demand for energy will increase from 97 quadrillion Btus in 2010 to 142 quadrillion by 2040 (ExxonMobil 2013), a 46% increase. EIA estimated China has 1,115 Tcf of risked technically recoverable shale gas resources (EIA 2013), making it an important resource for China's future energy demand. Currently, the majority of China's shale gas exploration and development are focused on three marine shales in and around Sichuan basin: the Silurian Longmaxi, the Cambrian age Qiongzhusi, and Niutitang. Of these, it is estimated that the Longmaxi has the highest risked recoverable shale gas (EIA 2013). However, because of its complex paleo tectonic movement, the Longmaxi formation is a highly fractured and faulted system, which makes it challenging to drill and fracture. This paper is a case study of operational challenges encountered when fracturing the Longmaxi formation. A brief geological review of Sichuan basin geology is discussed to present the origin of the geological complexity. The diagnostic fracture injection test (DFIT), hydraulic fracture job charts, log analysis, and microseismic data during fracture stimulation of a horizontal Longmaxi well is analyzed as an example to show the difficulty operators could experience when fracturing a shale formation developed in such a complex geological environment. Possible solutions are discussed as lesson learnt. The production is also detailed.

Unconventional shale gas reservoirs are a vital component of oil and gas exploration and development, and hydraulic fracturing is typically required to enhance reservoir permeability. Deep shale reservoirs are characterized by numerous thin layers, complex layer interfaces, and significant property variations between layers, which severely restrict the process of hydraulic fracture propagation. Currently, the propagation patterns of hydraulic fractures under the influence of interlayers and interfaces with varying properties remain unclear. In this study, based on the primary characteristics of deep shale reservoirs in the southern Sichuan Basin, a three-dimensional (3D) fracture propagation model that incorporates the effects of interlayers and interfaces was established using the discrete lattice method. Numerical simulations were conducted to investigate hydraulic fracture propagation under various conditions of interlayer thickness, interface strength, and dilation angle. The study found that interlayers and interfaces hinder the vertical propagation of hydraulic fractures, with shear failure occurring primarily at the interfaces and tensile failure dominating in the surrounding matrix. With the increase in interface tensile strength, friction angle, and cohesion, the hydraulic fracture changes from propagating along the interface to penetrating the interface. When the interface tensile strength is 5 MPa, the friction angle is 35°, and the cohesion is 10 MPa, the hydraulic fracture penetrates the interface significantly, with only a small part propagating along the interface. As the interface dilation angle increases, the ability of hydraulic fractures to penetrate the interface gradually weakens. When the interface dilation angle is greater than 10°, the hydraulic fracture is completely blocked. The research results can provide a theoretical basis for controlling fracture height and hydraulic fracture layer-crossing during on-site fracturing operations, contributing to efficient fracturing and reservoir stimulation.