From core-scale experiment to reservoir-scale modeling: A scale-up approach to investigate reaction-induced permeability evolution of CO2 storage reservoir and caprock at a U.S. CO2 storage site. (April 2019)

• Record Type: Journal Article
• Authors: Wang, Yan; Zhang, Liwei; Soong, Yee; Dilmore, Robert; Liu, Hejuan; Lei, Hongwu; Li, Xiaochun
• Is Part Of: Computers & geosciences. Volume 125(2019)
• Page Start: 55
• Page End: 68
• Publication Date: 2019-04
• Subjects: CO2 storage -- Mineral dissolution -- Mineral precipitation -- Permeability -- pH buffering -- Numerical environmental models; Environmental policy -- Periodicals; 550.5
• DOI: 10.1016/j.cageo.2019.01.006
• Languages: English
• ISSNs: 0098-3004

Abstract

Abstract: 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. Highlights: A 3-step approach to model permeability change induced by CO2 reaction is developed. pH buffering causes discrepancy between core- and reservoir-scale modeling results. SiO2 (am) is a key mineral that governs permeability change of CO2 storage formation.