A new dual-scale pore network model with triple-pores for shale gas simulation

Abstract

Fluid flow in shale is governed by various flow mechanisms in different pores, which can be attributed to the complex pore structure within the matrix and the surrounding mineral composition. Accurate characterization of the pore structure and simulation of gas flow within the matrix are imperative for optimizing gas production. In this work, we propose a new dual-scale pore network model (PNM) that incorporates triple-type pores, addressing diverse flow mechanisms for a more precise prediction of gas flow in shale. This is crucial for reliable estimations of gas production and effective resource exploitation. The PNM is constructed by incorporating N2 adsorption/mercury intrusion porosimetry (MIP) data and focused ion beam/scanning electron microscope (FIB/SEM) data, allowing differentiation between inorganic pores with and without clay, as well as organic pores. The proposed model is validated by comparing predicted permeability values with experimental results. Subsequently, we analyze factors influencing permeability. Analysis reveals that permeability respectively declines from 1.70 × 10−20 to 1.57 × 10−20 m2, from 2.00 × 10−20 to 1.69 × 10−20 m2, from 1.78 × 10−20 to 1.52 × 10−20 m2, from 1.69 × 10−20 to 1.63 × 10−21 m2, and from 4.30 × 10−20 to 7.24 × 10−21 m2 with increasing maximum organic pore radius, roughness, clay content, water film thickness, and tortuosity. Conversely, permeability respectively rises from 5.86 × 10−21 to 1.76 × 10−20 m2 and from 1.71 × 10−20 to 2.17 × 10−18 m2 with elevated total organic carbon content (TOC) and connectivity. These factors are crucial for shale gas production, underscoring the need for constructing a more accurate pore model of shale.