Numerical Modeling of Shale Gas Reservoir Extraction Considering Stress Field Sensitivity

Abstract

Shale gas extraction relies on horizontal drilling and multistage fracturing that involve intricate flow dynamics. Thus, it is crucial to evaluate the impacts of stress, thermal expansion, and desorption on reservoir matrix deformation, as they cause dynamic porosity and permeability changes. As contemporary simulation techniques struggle to precisely represent these processes, we present a thermo–hydro–mechanical (THM) coupling model that incorporates the dynamic fluctuations in porosity and permeability. The THM model simulates the mechanical deformation, the adsorption, desorption, diffusion, and flow of gas, and the heat transfer among the shale matrix, hydraulic cracks, and wellbore. The finite element method is employed to resolve and corroborate the THM model with production data from the Marcellus shale. In addition, computational models and orthogonal experiments are employed to evaluate the effects of stress field parameters on gas production and wellbore temperature. Results suggest that the stress field strongly affects gas production and wellbore temperature, and disregarding stress field coupling effects overstates gas production by around 12.9%. Porosity and Langmuir volume correlate positively with wellbore temperature, while permeability, Young’s modulus, Langmuir pressure, thermal expansion coefficient, and adsorption strain exhibit negative correlations. Thus, porosity, permeability, and adsorption strain are the principal factors influencing the wellbore temperature profile. These findings contribute to the accurate simulation and optimization of shale gas reservoir exploitation.