The microstructure of oil shale plays a vital role in the seepage and production of shale oil and gas and can be modified by microwave irradiation. In this study, the experimental work aims to visualize and analyze the microstructure of oil shale under microwave heating with different heating parameters by traditional two‐dimensional (optical microscope and scanning electron microscope) and advanced three‐dimensional (micro‐CT) methods. Volumetric reconstructions of oil shale before and after microwave heating were completed to directly visualize the pore structure and fracture network of the samples. The similarities and differences between microwave heating and conventional heating were also investigated. Finally, based on the three‐dimensional CT data, the porosity and the degree of anisotropy of the samples were calculated. Traditional two‐dimensional imaging methods showed that microwave heating led to more pores and fractures due to the differential thermal stress caused by rapid heating, which differed from conventional heating. Porosity calculations based on the CT image data indicated that a long heating time and a high output power could lead to a large porosity value. Oil shale obtained by drilling horizontally into the bedding plane showed the largest porosity and lowest heterogeneity of pore distribution after heating and had a different fracture morphology. The results from this study are important for the exploitation of oil shale using microwave heating, and the application of these analytical techniques is useful for the evaluation of the flow behavior of transformation products.

Supercritical carbon dioxide fracturing is an environmentally friendly anhydrous method. To study the propagation process during supercritical carbon dioxide fracturing, a full three‐dimensional model, coupled rock deformation, fluid transport, heat conduction, dynamic changes of carbon dioxide physical parameters, to investigate the process of fracture propagation during supercritical carbon dioxide fracturing, is established by the three‐dimensional boundary element method, the finite volume method, and finite difference method. And to solve the multiple physics coupling problems, a fully implicit solution and Newton‐Raphson iteration method are used. On the basis of this model established in this paper, the influential factors of supercritical carbon dioxide fracturing are analyzed. The results show that both of the reservoir temperature and the original in situ stress are important for carbon dioxide fracturing; The higher the reservoir temperature and the lower the initial in situ stress is, the longer and wider the fracture will be. The temperature of carbon dioxide at bottom is of no significance to the fracture length, fracture width, and the bottom hole pressure. A growing injection rate will lead to the increase of the fracture length and fracture width. This study would provide a reference for the fluid phase control of supercritical carbon dioxide fracturing technology.

A new three‐dimensional fluid‐solid coupling fracture propagation model of synchronous fracturing was established to study the dynamic propagation process of simultaneous hydraulic fracturing. In this paper, we used an improved three‐dimensional boundary element method and a finite difference method, respectively, for calculating the deformation of the reservoir rock and the flow of the fracturing fluid during the fracturing process. The interaction between hydraulic fractures and nature fractures was also considered. Sensitivity analysis showed that during synchronous fracturing, the fractures between the wells attracted each other and injected with more fluid due to interference between the fractures. Affected by natural fractures, the trajectory of hydraulic fractures was more tortuous. Besides, the width and height of hydraulic fractures captured by natural fractures were reduced. In order to reduce the difference in length between individual fractures, smaller well spacing and larger cluster spacing should be used.

Proppants are being increasingly used in hydraulic fracturing, which keep the fractures open. Progress has been made in developing hollow proppants that can be transported to the far end of the fractures to improve propped fracture conductivity. Two primary mechanisms by which proppants are damaged under closure stress are embedment and crushing, leading to a remarkable reduction in fracture conductivity. In this study, finite element model (FEM), considering rock plasticity, was used to study the embedment and crushing of a hollow proppant. After comparison with the existing model and experimental data, the proposed FEM was employed to conduct sensitivity studies. The effects of the following parameters on embedment and crushing were analyzed: closure stress, distance coefficient, Young's modulus of rock and proppant, proppant size, and hollow structure. The results show that the most sensitive environmental factor is the distance coefficient, followed by closure stress and Young's modulus of rock. The embedment depth increases approximately linearly with the proppant size, and proppants with different sizes have similar crushing rates. The hollow structure has little effect on proppant embedment but significantly affects proppant crushing. Based on the data normalization method, the optimal ratio of hollow radius to proppant radius was designed to be 0.7. These results can guide the preparation of hollow proppants.

The application of horizontal wells with multistage hydraulic fracturing technologies has made the development of shale gas reservoirs become a worldwide economical hotspot in recent years. The gas transport mechanisms in shale gas reservoirs are complicated, due to the multiple types of pores with complex pore structure and special process of gas accumulation and transport. Although there have been many attempts to come up with a suitable and practical mathematical model to characterize the shale gas flow process, no unified model has yet been accepted by academia. In this paper, a comprehensive literature review on the mathematical models developed in recent years for describing gas flow in shale gas reservoirs is summarized. Five models incorporating different transport mechanisms are reviewed, including gas viscous flow in natural fractures or macropores, gas ad-desorption on shale organic, gas slippage, diffusion (Knudsen diffusion, Fick diffusion, and surface diffusion), stress dependence, real gas effect, and adsorption layer effect in the nanoshale matrix system, which is quite different from conventional gas reservoir. This review is very helpful to understand the complex gas flow behaviors in shale gas reservoirs and guide the efficient development of shale gas. In addition to the model description, we depicted the type curves of fractured horizontal well with different seepage models. From the review, it can be found that there is some misunderstanding about the essence of Knudsen/Fick diffusion and slippage, which makes different scholars adopt different weighting methods to consider them. Besides, the contribution of each mechanism on the transport mechanisms is still controversial, which needs further in-depth study in the future.