With the increase of shale gas resource exploitation in our country during recent decades, the situations of low gas production, fast production decline rate, and low flowback rate have been appearing in field production. It is an urgent problem to be solved in shale gas production and it is therefore necessary to study the interaction of the shale gas reservoir and the detained fracturing fluid. In this paper, the Longmaxi Formation shale samples of Sichuan Basin were selected for a water invasion experiment. The fracture propagation law, the water invasion front location, and the water invasion thickness of deep and shallow shale reservoirs after water invasion were compared and analyzed by CT scanning technology. Based on the analysis of the experimental mechanism, a numerical simulation model was established. The dimensionless permeability and thickness of the fracturing fluid invasion layer were introduced to analyze the positive and negative effects of fracturing fluid retention on the reservoir. The results show that during the hydraulic fracturing of shale gas wells, fracturing fluid can quickly enter the complex fracture network, and then slowly enter the shale matrix under various mechanisms to form the fracturing fluid invasion layer. Compared with shallow shale reservoirs, deep shale reservoirs have lower porosity and permeability, which propagates microfractures in the matrix induced by fracturing fluid retention, and results in a smaller fracturing fluid invasion layer thickness. Both the negative effect of fracturing fluid retention on shale damage and the positive effect of microfracture formation and propagation exist simultaneously. The higher the dimensionless fracturing fluid invasion layer permeability, the more complex the fracture network formed in the fractured reservoir will be, resulting in a longer stable production period and a better development effect. When the dimensionless fracturing fluid invasion layer permeability is greater than 1, that is, when the positive effect of fracturing fluid retention is greater, and the thicker the dimensionless fracturing fluid invasion layer is, the better the development effect will be. Combining reservoir characteristics and fracture development, the key to obtaining high productivity of a shale gas well is to optimize the soaking time and the speed of flowback in order to extend the stable production period. In this paper, the characteristics of the fracturing fluid invasion layer and the influence of fracturing fluid retention on gas well productivity are deeply studied, which provides a certain theoretical basis for the optimization of shale gas extraction technology and the improvement of the gas–water two-phase productivity prediction method for fractured horizontal wells.

In shale gas reservoirs, the production data analysis method is widely used to invert reservoir and fracture parameter, and productivity prediction. Compared with numerical models and semianalytical models, which have high computational cost, the analytical model is mostly used in the production data analysis method to characterize the complex fracture network formed after fracturing. However, most of the current calculation models ignore the uneven support of fractures, and most of them use a single supported fracture model to describe the flow characteristics, which magnifies the role of supported fracture to a certain extent. Therefore, in this study, firstly, the fractures are divided into supported fractures and unsupported fractures. According to the near-well supported fractures and far-well unsupported fractures, the SRV zone is divided into outer SRV and inner SRV. The four areas are characterized by different seepage models, and the analytical solutions of the models are obtained by Laplace transform and inverse transform. Secondly, the material balance pseudotime is introduced to process the production data under the conditions of variable production and variable pressure. The double logarithmic curves of normalized production rate, rate integration, the derivative of the integration, and material balance pseudotime are established, and the parameters are interpreted by fitting the theoretical curve to the measured data. Then, the accuracy of the method is verified by comparison the parameter interpretation results with well test results, and the influence of parameters such as the half-length and permeability of supported and unsupported fractures on gas production is analyzed. Finally, the proposed method is applied to four field cases in southwest China. This paper mainly establishes an analytical method for parameter interpretation after hydraulic fracturing based on the production data analysis method considering the uneven support of fractures, which is of great significance for understanding the mechanism of fracturing stimulation, optimization of fracturing parameters, and gas production forecast.

Deep oversaturated coalbed methane (CBM) reservoirs contain abundant in situ free gas, and hydraulic fracturing forms a multi-scale complex fracture network with main fractures, branch fractures, and cleats. Most current productivity models target undersaturated shallow coal seams, neglecting the coexistence of free and adsorbed gas and simplifying fractures as planar main fractures, leading to low prediction accuracy. To address this, based on dual-porosity and dual-permeability theory, this study characterizes adsorbed gas and in situ free gas in the coal matrix and free gas and formation water in natural cleats. It considers one-dimensional linear flow of free gas and fracturing fluid in hydraulic fractures and two-dimensional radial flow of adsorbed gas, free gas, and formation water in the cleat–matrix system. A multi-region coupled model is developed for three typical fracture patterns: single main fracture-cleat, main single-branch fracture-cleat, and main multiple-branch fracture-cleat. This model fully considers the conductivity attenuation mechanism of hydraulic fractures, as well as spatial overlap and interaction among stimulated zones. The model is solved by a hybrid finite difference-embedded discrete fracture method, which realizes quantitative dynamic prediction of gas and water production over the entire well life cycle, including production ramp-up, stable production, and decline for oversaturated deep shale gas wells with complex fracture networks. Sensitivity analysis reveals the effects of cleat properties, hydraulic fracture parameters, and complex multiscale fracture morphologies on gas–water two-phase productivity. The core innovation of this study is a coupled gas–water two-phase productivity model integrating adsorbed gas, free gas, and water within the multi-scale fracture–matrix system, which overcomes the limitations of conventional models in characterizing complex fracture networks and multiphase flow. This work provides theoretical support for fracturing optimization and production regulation of horizontal wells in deep oversaturated CBM reservoirs.