A numerical calculation method is developed to investigate the influence of carbonate precipitation to the relative permeability of the reservoirs during CO2 storage. A rock pores of Berea sandstone are reconstructed from the micro-CT scanned images. The fluid velocity field inside the reservoir rock is calculated by the lattice Boltzmann method (LBM), while the species transport with calcite deposition in porous media is modeled by an advection–reaction formulation. To increase the computation efficiency, the GPU (graphics processor unit) parallel computing technique has been applied to accelerate the simulation. Consequently, the high resolution simulation requiring high computational cost become available. We consider a single phase flow and validate Darcy's law from the linear dependence of the flux on the fluid pressure exerted. The relative permeability of the sample rock is then calculated by a highly optimized two phase color gradient model. To evaluate the porosity change caused by the carbonate deposit, we first adjust the gray scale threshold value of CT images to qualitatively mimic the porosity decreasing process. In the second approach, we modeled the precipitated rock by transferring the fluid node to solid node according to the calcium concentration level. The permeability change due to the carbonate precipitation is then evaluated and discussed. It is found that the CO2 precipitation induced pore structure evolution influences the absolute permeability significantly, while only affects the relative permeability of non-wetting phase at low water saturation conditions.
|Title of host publication||Proceedings of the 11th SEGJ International Symposium|
|Publication status||Published - Nov 21 2013|