Dawei Zhou's research while affiliated with China University of Petroleum - Beijing and other places

The widely distributed microfractures play an important role in shale gas production. However, limited studies focus on gas flow behavior in microfractures, and ignore the complex transport mechanisms, leading to a large error for gas permeability evaluation. In this work, a newly dynamic apparent permeability (AP) model, coupling poromechanics, sorption-induced strain, and gas slippage, has been proposed to effectively reveal the gas flow mechanisms through microfractures of shale. Specifically, a dynamic aperture is innovatively incorporated into the Navier-Stokes (N–S) equation using the second-order slip boundary condition to calculate the gas velocity and volume flux in single microfracture. Based on that, the gas transport model for microfracture networks considering the distributions of aperture and tortuosity is derived using the fractal theory. The newly developed model is verified well with experimental data and network simulation. Results indicate that the gas conductance highly depends on the structure of microfracture networks (i.e., the maximum aperture and fractal dimensions). There are three different AP evolutions under various boundary conditions (i.e., constant confining pressure (Pc), constant pore pressure (Pp), and constant effective stress (σeff)) resulting from the coupling transport mechanisms. The AP presents a similar shape of “V” at reservoir conditions (i.e., constant Pc ), indicating the “negative contribution” of poromechanics at an early stage, and the “positive contribution” for both gas slippage and sorption-induced strain at the late stage should be underlined during gas production. Moreover, the “negative factor” of poromechanics is positively correlated with fracture compressibility coefficient but negatively associated with Biot's coefficient at high pressures (>15 [MPa]). Increasing gas desorption capacity, fracture spacing, and internal swelling coefficient can enhance the “positive factor” of sorption-induced strain at low pressures (<15 [MPa]). This work provides a theoretical guidance to develop shale gas effectively.

A new gaseous hydrocarbon transport model, considering pore geometry, multiphase pore fluid occupancy, and porous deformation, has been developed to characterize the real gas flow in both nanoscale organic and inorganic porous media. To do so, Navier-Stokes equations were solved with modified second-order slip boundary conditions in nanocapillaries of organic matter (OM) and nanoslits of inorganic matrix (iOM). Due to gas adsorption, both surface diffusion and bulk gas flow affect the apparent gas permeability (AGP) of OM. Particularly, the Langmuir-slip model is used for the calculation of boundary velocity of bulk gas. In contrast, gas flow in a single nanoslit of iOM accounts for the impact of adsorbed water film with a certain thickness quantified by Li's model [15]. Additionally, porous deformation and real gas effect are included in both models of OM and iOM. As such, a unified AGP model of shale matrix is formulated based on the total organic carbon (TOC) content including contributions of both OM and iOM. Results show that, under depressurization condition, the AGP of OM/iOM with a large pore size distribution (PSD) presents a similar shape of “V”, while the AGP of iOM with a small PSD increases monotonously. The total flow capacity of OM is contributed by competitive mechanisms of surface diffusion, induced- and pure- bulk gas flow under various PSDs and pressure. For gas flow capacity in iOM with a small PSD, it can be weakened by adsorbed water film but compensated by nanoscale effect considerably at low pressures. Moreover, a higher relative humidity (RH) leads to a thicker water film resulting in a lower gas conductance. The AGP of shale matrix can be reduced or enhanced by the TOC content when accounting for gas adsorption and adsorbed water film. Besides, the real gas effect enhances flow capacity significantly in small pores with a high pressure. The proposed model provides a comprehensive understanding of the gas flow mechanism in shale nanopores under reservoir conditions.