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To evaluate the production performance of shale gas wells accurately, a quadruple-porosity medium model based on kerogen, the inorganic matrix, and natural-fracture–hydraulic-fracture network is proposed to simulate shale gas production. This model includes an apparent-kerogen permeability model to characterize the combined effects of gas slippage, Knudsen diffusion, surface diffusion, stress sensitivity, and matrix shrinkage. The fractal theory is used to characterize the non-equidistant distribution of secondary fractures in the hydraulic fracture network quantitatively. In addition, the effect of the stress sensitivity of the hydraulic fracture network on the production is considered, and a numerical method for the quadruple-porosity model is presented. After the validation of the model with field production data, the sensitivity parameters were analyzed to study the effects of the apparent kerogen permeability, Langmuir volume, fractal dimension, primary and secondary fracture conductivities, geomechanical effect, stimulated reservoir volume (SRV), and inorganic-matrix permeability on the gas production. This study provides a theoretical model for a more accurate evaluation of the shale gas production and improves the shale gas seepage theory. [ABSTRACT FROM AUTHOR]

Influenced by natural fractures, fracture networks may be created when hydraulic fractures propagate in naturally fractured reservoirs. Simulating fracture network propagation is crucial to fracture design. In this paper, a two‐dimensional mathematical model for the direct simulation of fracture network propagation that considers fluid filtration and reservoir fluid flow is developed, and a simulation method is proposed based on the coupled flow idea of natural fractures and matrices in dual‐porosity media. The model uses dynamic coordinates to represent the extended hydraulic fracture network and static coordinates to describe natural fractures that have not been activated. The activation of natural fractures by a hydraulic fracture is determined according to the hydraulic fracture propagation scenario after an intersection with natural fractures. The geometric shape and size of the network fracture are obtained by changing the size of the simulated area and solving the mass balance, fracture width, and reservoir fluid flow equations numerically in a coupled manner. After validating the new model, a parameter sensitivity analysis is conducted to study the effects of injected fluid volume, fracture height, fracture spacing, elastic modulus, horizontal principal stress difference, pumping rate, and fracturing fluid viscosity on the fracture network shape, fracture network size, average fracture width, and fracture‐reservoir contact area. The numerical results indicate that the model can be directly used to simulate the propagation of fracture networks. The volume of injected fluid is the most critical factor affecting the fracture network size. Increasing the fluid viscosity and injection rate can increase the width of the fracture network and the average width of a secondary fracture. However, the total contact area of the reservoir and fracture will decrease, and the reservoir‐fracture contact area and fracture network size will increase with a decrease in the horizontal stress difference and increase in elastic modulus. Decreasing a fracture's height can significantly increase the size of the fracture network and reservoir‐fracture contact area. [ABSTRACT FROM AUTHOR]

Complex fracture systems including natural fractures and hydraulic fractures exist in shale gas reservoir with fractured horizontal well development. The flow of shale gas is a multi-scale flow process from microscopic nanometer pores to macroscopic large fractures. Due to the complexity of seepage mechanism and fracture parameters, it is difficult to realize fine numerical simulation for fractured horizontal wells in shale gas reservoirs. Mechanisms of adsorption–desorption on the surface of shale pores, slippage and Knudsen diffusion in the nanometer pores, Darcy and non-Darcy seepage in the matrix block and fractures are considered comprehensively in this paper. Through fine description of the complex fracture systems after horizontal well fracturing in shale gas reservoir, the problems of conventional corner point grids which are inflexible, directional, difficult to geometrically discretize arbitrarily oriented fractures are overcome. Discrete fracture network model based on unstructured perpendicular bisection grids is built in the numerical simulation. The results indicate that the discrete fracture network model can accurately describe fracture parameters including length, azimuth and density, and that the influences of fracture parameters on development effect of fractured horizontal well can be finely simulated. Cumulative production rate of shale gas is positively related to fracture half-length, fracture segments and fracture conductivity. When total fracture length is constant, fracturing effect is better if single fracture half-length or penetration ratio is relatively large and fracturing segments are moderate. Research results provide theoretical support for optimal design of fractured horizontal well in shale gas reservoir. [ABSTRACT FROM AUTHOR]

• The microscopic mechanism of fracturing fluid imbibition into illite pores was studied using molecular simulation. • The characteristics of hydrogen bonds in water imbibition were analyzed. • Influencing factors of water imbibition were studied, including pressure, pore size and water volume. Hydraulic fracturing is an important technique to develop deep shale gas. After hydraulic fracturing, a large amount of fracturing fluid fails to flow back and retains in deep shales. This phenomenon leads to fracturing fluid imbibition and significantly impacts on gas production. However, the understanding of imbibition mechanism in deep shales is very limited. In this work, the microscopic mechanism of fracturing fluid imbibition into illite pores of deep shales was studied using molecular simulation. The factors affecting imbibition were also analyzed. Results show that water imbibition in illite pores can be divided into three stages. In stage 1, the hydrogen bonds between water molecules and illite pore walls are formed, which forces water to enter the pores and becomes a water layer. In stage 2, the hydrogen bonds between water molecules and the water layer are formed, and gas begins to be displaced out of the pores by water. In stage 3, water molecules no longer enter the pores, and the system becomes equilibrium. As for the influencing factors, fugacity pressure mainly affects the imbibition time. The imbibition time becomes longer when fugacity pressure rises. Pore size plays a significant role in imbibition. Gas in illite pores can be totally displaced if the pore size is smaller than 5 nm. The imbibition is also affected by the amount of water. More gas tends to be displaced out of the pores when the ratio of water volume to pore volume (RWP) increases. [ABSTRACT FROM AUTHOR]

Due to the constraint of fresh water, the reuse of flowback and produced water (FPW) with high TDS, is critical to minimize the environmental impact of oil/gas exploration. The underlying challenge is the negative effect of salts present in FPW on the chemistry of fracking. The solution is to develop excellent fracking chemistry with salt- and temperature-resistant. Herein, we have comprehensively discussed FPW characteristics, and the technical challenges of reusing FPW; we then focus on the design strategy of developing fracturing fluids that are effective under harsh conditions. The environmental benefits and economic implications of using FPW in fracking are highlighted. In summary, we proposed that a new type of fracturing fluid should be developed in future, which contains a new functional gelling agent prepared by grafting the synthetic polymer on the biopolymer, bio-based nano-crosslinkers, cost-effective nano-breakers, and FRs with high elasticity and salt-resistance, which will have great potential for the reuse of FPW and the development of unconventional formations. We envision that this review will provide insights to stimulate new thinking and innovation in oil/gas fracking that is not only green/sustainable, but also economic/practical, while meeting the demand for high performance under harsh environments with high salt and high temperature. [Display omitted] • The characteristics and amounts of FPW were expounded. • The urgency, challenges, and solutions of reusing process water are comprehensively discussed. • Fundamentals, design principles and applications of FPW-based fracturing fluid systems are highlighted. • The potential directions for reuse/recycling FPW were pointed out. • The environmental, social, and economic benefits of reusing process water in fracking are assessed. [ABSTRACT FROM AUTHOR]