Abstract
This paper presents a method to quantitatively characterize natural Fractures Intensity (FI) and proposes a Comprehensive Permeability Model (CPM) coupling gas transfer mechanisms in natural fractures and matrix for shale gas reservoirs. Firstly, the Scanning Electron Microscope (SEM) images of natural shale cores are used to quantitatively characterize FI, such as the aperture, length, spacing, general fracture distribution described by Fisher orientation dispersion value (K), and the Angle between the mean pole of Fractures and the Scan-line (AFS). Secondly, the corresponding relationship between the AFS and K, which can be used to evaluate the length of fracture traces per unit area of trace plane and the area of fractures per unit volume of rock, is built based on the numerical simulation results. Then, we can obtain the natural fracture distribution state and quantitatively distinguish the natural fracture volume from the matrix. Finally, the CPM is proposed by combining the FI and matrix pore parameters based on the series-parallel circuit theory. The CPM is not only verified by the numerical simulation in which the Boundary Element Method (BEM) is adopted to simulate the fractures' influence, but also in good agreement with the lab measurements of shale samples from the Cambrian Niutitang formation in South Sichuan Basin, China. The FI evaluation method and the CPM proposed in this paper provide a new approach to quantitatively understand the natural fracture distribution and the contribution to the shale reservoir percolation capability. In turn, this will enable engineers better understand the shale gas transport mechanisms and develop the simulation in a more practical way.