Improved numerical models for gas flow in shale

Shale gas has rapidly changed the energy market in the USA and is poised to do so elsewhere in the world. Despite this success there remains massive uncertainty regarding how gas flows in the small pores within shale. Unlike conventional reservoirs, gas flow is not likely to occur by continuum flow (i.e. Darcy’s Law). Instead other gas flow mechanisms e.g. slippage and Knudsen diffusion are likely to dominate. Current models for gas flow in shale are so complex that it has proved difficult to use them to interpret experimental data and extrapolate the results to subsurface conditions. Over the last three years, staff at the Wolfson multiphase flow lab at Leeds have collected a lot of experimental data on gas flow in shales. The samples on which the experiments have been conducted have been thoroughly characterized to provide information on their pore structure, surface area and mineralogy. Here we propose to develop a new model for gas flow in shales that will make use of this unique dataset. It is proposed that pore-scale modelling techniques, e.g. Lattice Boltzmann method, are used to improve understanding of the controls on gas flow at the pore scale. This understanding will then be incorporated into a 3D continuum model (e.g. finite volume) and coupled to inversion algorithms (e.g. NAG subroutines, nearest neighbour algorithm) to invert experimental data and provide the industry with a new method for characterizing subsurface samples from shale resource plays.