Coupled Flow Simulation and Geomechanical Modeling on CO 2 Storage in a Saline Aquifer

Abstract

As an option to mitigate the increasing level of greenhouse gas emission, a number of Carbon Capture and Storage (CCS) testing and pilot projects have been brought up all over the world. In general, there are three types of CO 2 storage formations, such as deep saline aquifers, depleted oil and gas reservoirs, and un-mineable coal seams. This study is focused on the deep saline aquifer which has the largest potential for CO 2 storage. There are a lot of uncertainties associated with this type of storage, such as storage capacity, geomechanical properties, and sealing behaviour of the caprock. Pressure (and temperature) changes during CO 2 injection and storage can have significant impact on the stress and strain field and may cause relevant geomechanical problems. This paper shows a case study of a synthetic saline aquifer storage site, where a 15-year injection at a rate of 15 MT/year was simulated. Sealing performance and leakage risk were evaluated. A number of sensitivity studies were conducted to analyse the impacts of different rock properties on CO 2 leakage potentials. Coupled flow simulation and geomechanical modeling was performed to monitor stress-strain evolutions and to predict failure potentials in response to pressure changes during CO 2 injection and storage. The findings show that CO 2 leakage is most sensitive to caprock permeability. Other factors such as reservoir properties, boundary conditions, and perforation intervals also have certain degree of influence on the leakage. During the 15-year injection, there is no significant risk of potential failure; however, this may happen in local area due to formation heterogeneity.