From core-scale experiment to reservoir-scale modeling: A scale-up approach to investigate reaction-induced permeability evolution of CO_2 storage reservoir and caprock at a U.S. CO_2 storage site

摘要

Mineral dissolution and secondary mineral precipitation can cause porosity and permeability changes of CO2 storage reservoirs and caprocks after injection of CO2. In this paper, a 3-step approach (core-scale experiment - core-scale modeling - reservoir-scale modeling) is developed to simulate reservoir-scale porosity and permeability evolution of CO2 storage formation and caprock at a model CO2 storage site. The model site is based on characteristics of a real site in Mississippi, USA. Important chemical and permeability modeling parameters in the reservoir-scale model are validated by core-scale experimental and reactive transport modeling results. The reservoir-scale model predicts a maximum 3.2% permeability increase of the CO2 storage formation and a maximum 1.1% permeability increase of the caprock after 1000 years of exposure to CO2-rich brine, while the core-scale model predicts 7% permeability decrease for a small CO2 storage formation core and 296% permeability increase for a small caprock core after 180-day exposure to CO2-rich brine. The discrepancy between permeability results of reservoir-scale model and core-scale model is attributed to strong pH buffering effect of CO2 storage formation with large mass of H+-consuming minerals. Therefore, using core-scale experiments/models only is not sufficient to elucidate reservoir-scale permeability evolution. Variations of key model parameters have a small effect on permeability evolution of both CO2 storage formation and caprock, except for variations of K-eq (SiO2 (am)) and the exponent n in permeability-porosity correlation. SiO2 (am) is a key mineral that governs permeability evolution of CO2 storage formation and caprock, given the characteristics of the model CO2 storage site.