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Predicting apparent gas permeability (AGP) in nanopores is a major challenge for shale gas development. Considering the differences in the gas molecule-pore wall interactions in inorganic and organic nanopores, the gas transport mechanisms in shale remain unclear. In this paper, gas flow channels in shale, which are separated into inorganic pores and organic pores, are treated as nanotubes. Inorganic pores are assumed to be hydrophilic, and organic pores are assumed to be hydrophobic. In organic pores, multiple bulk free gas and surface adsorbed gas transport mechanisms are incorporated, while the bulk gas and water film are considered within inorganic pores. This paper presents a unified multiple transport mechanism model for both organic nanopores and inorganic nanopores. Unlike the earlier models, the presented models consider the absorption, stress dependence, real gas, and water storage effects on gas transport comprehensively for the entire flow regime. The results are validated with published data which is more in line with the real situation. The results show that (1) the AGP decreases gradually as the pore pressure decreases but that the decrease is sharp in small pores, (2) the AGP decreases dramatically when considering the real gas effect at 50 MPa in a 2 nm pore size, and (3) for a small pore size at the critical high-water saturation, AGP might increase suddenly as the flow regime changes from continuum flow to slip flow. The findings of this study can help for better understanding of the gas transport mechanisms for the entire flow regime in shale.

Summary Microfractures are commonly observed in shale reservoirs. During the shale gas–production process, stress sensitivity induces a change in the width of the microfractures, which is a significant factor that affects shale gas mass transport. By using research methods based on desorption theory and elastic–plastic mechanics, a shale gas mass transport model that considers the dynamic variations in the microfracture width is established in this paper. This model comprehensively fuses the surface diffusion model, slip flow model, Knudsen diffusion model, and cubic grid model. The reliability of this model is verified using molecular simulations, which do not include surface diffusion. The shale gas is considered as pure methane. Then, the different contributions of the gas mass transport mechanisms to the total mass transport are discussed in detail. The results demonstrate the following findings: (1) The studied flows are well–simulated by the proposed model. (2) Stress sensitivity results in a decrease in gas mass transport when the formation pressure exceeds 3.4 MPa, and the minimum value is approximately 0.45 times smaller than that when the width change is not considered. Moreover, stress sensitivity results in an increase in gas mass transport when the formation pressure is lower than 3.4 MPa, and the maximum value is approximately 4.5 times higher than that when the width change is not considered. (3) Shale gas mass transport is positively associated with the Young's modulus and Poisson's ratio, whereas it is negatively associated with the microfracture compressibility. When the formation pressure is less than 4 MPa, shale gas transport is positively correlated with the desorption capacity, whereas when the formation pressure exceeds 4 MPa, the effect of different desorption capacities on gas transport is nearly consistent. (4) When the microfracture width is at nanoscale and the reservoir pressure is lower than 15 MPa, surface diffusion has an obvious effect on the shale gas mass transport process. When the contribution of surface diffusion to the total shale gas mass transport is relatively small, the contributions of slip flow and Knudsen flow to shale gas mass transport exhibit the trend of “shifting each other.” When the surface diffusion contribution is larger, a reduction in its contribution leads to simultaneous initial increases in the contributions of slip flow and Knudsen flow to shale gas mass transport, and then these flows begin “shifting each other.”

The capillary spontaneous imbibition length of slick water in confined rectangular cross-sectional nanofractures is investigated in this paper. In the established model, the effective slip length, effective viscosity, wettability and nanofracture size are incorporated into the modified Hagen–Poiseuille equation. The calculated spontaneous imbibition length as a function of time, viscosity, wettability and pore size is qualitatively validated by experimental and previous theoretical Hagen–Poiseuille flow results. Our model calculation results agree well with the published experimental data. The ratio of the effective and bulk water viscosities is higher than one, and increases with an increase in the ratio of the nanofracture width to height and decreasing contact angle. The spontaneous imbibition capacity of confined water is enhanced ∼0.67–1.28 times, as determined by the Hagen–Poiseuille equation without the slip effect for various contact angles and nanofracture dimensions.

To investigate the evolution of hydraulic fractures in open-hole horizontal wells, a comprehensive experimental and analytical modeling investigation of fluid-driven fracture initiation in open-hole horizontal wells is presented in this paper. A large triaxial experimental system and a three-dimensional (3D) micro-computed tomography (micro-CT) imaging setup were used to simulate and investigate hydraulic fractures similar to those produced in field tests. We used an 8-mm-diameter and 100-mm-long hollow cylinder as a borehole within a 115 mm × 115 mm × 93 mm cement sample. The samples were first loaded in three orthogonal directions at different confining pressures to reproduce in situ reservoir conditions. Subsequently, a viscous fluid used in field operations with a viscosity of 60 mPa·s was injected into the borehole at 9 cc min−1. During the tests, the injection pressure and rate were monitored. Then, the fracture morphologies were detected by 3D micro-CT scanning. The fracture initiation pressure increases as the wellbore orientation rotates toward the minimum principal stress direction. The 3D images demonstrated that an induced hydraulic fracture first extends along the horizontal wellbore and then turns to align with the preferred fracture plane. An analytical model considering the fluid penetration effect, which is represented by the injection rate, rock permeability and fluid viscosity, was also developed to predict the fracture initiation pressure in open holes in permeable formations. The modeling results of the initiation pressure and the fracture position and orientation fit well with the experimental results. During the stimulation of a permeable formation, some of the fracturing fluid being injected into the wellbore flows from the wellbore into the surrounding formation. The infiltrating fracturing fluid increases the formation pore pressure, causing a compressive circumferential stress around the borehole. This mechanism reduces the fracture initiation pressure. The initiation pressure decreases with the rock permeability and injection rate but increases with the fracturing fluid viscosity. This result is important for petroleum engineering applications, because nearly all reservoirs are permeable to fracturing fluids, and the limitations of previous models preclude them from drawing the same conclusions.

It is widely accepted that a fracture can be induced at a wellbore surface when the fluid pressure overcomes the rock tensile strength. However, few models of this phenomenon account for the fluid penetration effect. A rock is a typical permeable, porous medium, and the transmission of pressure from a wellbore to the surrounding rock temporally and spatially perturbs the effective stresses. In addition, these induced stresses influence the fracture initiation pressure. To gain a better understanding of the penetration effect on the initiation pressure of a permeable formation, a comprehensive formula is presented to study the effects of the in situ stresses, rock mechanical properties, injection rate, rock permeability, fluid viscosity, fluid compressibility and wellbore size on the magnitude of the initiation pressure during fracturing of an open-hole wellbore. In this context, the penetration effect is treated as a consequence of the interaction among these parameters by using Darcy's law of radial flow. A fully coupled analytical procedure is developed to show how the fracturing fluid infiltrates the rock around the wellbore and considerably reduces the magnitude of the initiation pressure. Moreover, the calculation results are validated by hydraulic fracturing experiments in hydrostone. An exhaustive sensitivity study is performed, indicating that the local fluid pressure induced from a seepage effect strongly influences the fracture evolution. For permeable reservoirs, a low injection rate and a low viscosity of the injected fluid have a significant impact on the fracture initiation pressure. In this case, the Hubbert and Haimson equations to predict the fracture initiation pressure are not valid. The open-hole fracture initiation pressure increases with the fracturing fluid viscosity and fluid compressibility, while it decreases as the rock permeability, injection rate and wellbore size increase.

Horizontal well drilling accompanied by multicluster fracturing is unlocking shale gas resources. It is essential to create a large-scale fracture network connecting the reservoir to the wellbore by activating the preexisting natural fractures (NFs) through well completion optimization. Coupling the geomechanical characteristics of a shale formation to achieve the maximum stimulated reservoir volume (SRV), we develop a new completion optimization pattern for a single horizontal wellbore called modified alternate fracturing. The new model is a combination of conventional simultaneous and alternate fracturing. Unlike the previous studies that mainly concentrated on predicting the quasistatic dilation of NF failure, the presented paper assesses the dynamic evolution progression of NF growth under different failure criteria. Additionally, an analysis of how the modified alternate fracturing influences the fracture network is performed. The results demonstrate that a NF may be crossed, opened or slipped by an approaching hydraulic fracture (HF), depending on the tensile or shear stresses exerted on the NF. The combination of perforation parameter optimization and injection rate real-time control is able to utilize induced stresses to form a complex fracture network. A field application reveals that the modified well completion pattern performed better than conventional simultaneous fracturing due to increasing the near-wellbore and far-field fracture complexity. In addition, no additional equipment such as bridge plugs or coiled tubingis needed during operation, reducing potential issues.

After volume fracturing, shale reservoirs can be divided into nonlinear seepage areas controlled by micro- or nanoporous media and Darcy seepage areas controlled by complex fracture networks. In this paper, firstly, on the basis of calculating complex fracture network permeability in a stimulated zone, the steady-state productivity model is established by comprehensively considering the multi-scale flowing states, shale gas desorption and diffusion after shale fracturing coupling flows in matrix and stimulated region. Then, according to the principle of material balance, a transient productivity calculation model is established with the succession pseudo-steady state (SPSS) method, which considers the unstable propagation of pressure waves, and the factors affecting the transient productivity of fractured wells in shale gas areas are analyzed. The numerical model simulation results verify the reliability of the transient productivity model. The results show that: (1) the productivity prediction model based on the SPSS method provides a theoretical basis for the transient productivity calculation of shale fractured horizontal well, and it has the characteristics of simple solution process, fast computation speed and good agreement with numerical simulation results, (2) the pressure wave propagates from the bottom of the well to the outer boundary of the volume fracturing zone, and then propagates from the outer boundary of the fracturing zone to the reservoir boundary, (3) with the increase of fracturing zone radius, the initial average aperture of fractures, maximum fracture length, the productivity of shale gas increases, and the increase rate gradually decreases. When the fracturing zone radius is 150 m, the daily output is approximately twice as much as that of 75 m. If the initial average aperture of fractures is 50 μm, the daily output is about half of that when the initial average aperture is 100 μm. When the maximum fracture length increases from 50 m to 100 m, the daily output only increases about by 25%. (4) When the Langmuir volume is relatively large, the daily outputs of different Langmuir volumes are almost identical, and the effect of Langmuir volume on the desorption output can almost be ignored.