Modeling Long-Term CO2 Storage in Aquifer With a Black-Oil Reservoir Simulator

Abstract

Abstract This paper presents results of modeling long-term CO2 storage in a shallow saline aquifer with a commercial black-oil reservoir simulator. Realistic CO2/water phase behavior (pVT properties) covering all pressure, temperature and compositional conditions accounted for during the simulations have been used. The pressure and temperature in the aquifer is above the CO2 supercritical conditions giving rise to the existence of a two-phase fluid system of CO2 as a supercritical fluid ("gas") and CO2 dissolved in the aqueous phase. The objective was to model scenarios of CO2 storage in aquifer with emphasis on the sensitivity of CO2 distribution in the deposit with respect to critical CO2 saturations during the injection period and to residual CO2 saturation for water reentering CO2 filled volumes (hysteresis in fluid saturations). The re-distribution of water occurs after stop of CO2 injection due to gravity segregation of dense CO2 saturated water and CO2-free water. The impact of various reservoir parameters has been studied, including average permeability, vertical to horizontal permeability ratio (kv/kh), relative permeability, and capillary pressure. For the saturation functions the main focus has been on end points and hysteresis effects. It is observed that storage of CO2 as residual gas is most important for low kv/kh ratios. Introduction The concentration of carbon dioxide (CO2) continues to increase in the atmosphere as a result of CO2 release from anthropogenic sources including burning of fossil fuels. The atmospheric concentration of CO2 has increased from the pre-industrial age level of about 280 ppm to 370 ppm today¹. This value is higher than the concentrations observed over the last 400 000 years. The current emissions of CO2 into the atmosphere exceed the capacity of the natural CO2 cycling system to absorb the emissions. Accumulation of CO2 and other greenhouse gases in the atmosphere results in an accompanying increase of global atmospheric temperature. Reduction of the pH of the upper ocean level is another result of accumulation of CO2 in the atmosphere. Large-scale storage of CO2 in geologic formations will contribute to meet the challenge of stabilizing the concentration of CO2 in the atmosphere. Oil, gas and condensate reservoirs are relevant locations to consider for CO2 storage because their proven geologic seal that trapped the buoyant hydrocarbon over a geological timescale and because of the already acquired geologic description. A pre-requisite is that the geologic seal has not been damaged during the production and that the abandoned wells do not leak CO2 to the surface2. In lack of petroleum reservoir for CO2 storage purpose, deep saline formations are possible alternatives. They are more common worldwide and thus constitute a larger potential storage volume. The disadvantage is that they usually are much less characterized than petroleum reservoirs. Especially, there is normally no proven seal before injection starts. Characterization of the aquifer is an important part of the total evaluation of the aquifer as a reliable long-term CO2 deposit site. Detection and proper description in the simulation model of potential vertical flow barriers, topography of cap rock, faults, and other potential pathways for flow that will dominate the storage capacity and reliability of the aquifer must be considered carefully. This paper is about storage mechanisms of CO2 in deep saline aquifers. Gravity segregation of CO2 towards the top of the aquifer will dominate the flow caused by the density difference between injected CO2 and brine unless flow barriers in the aquifer restrict the vertical segregation. Large volume aquifers with reasonable permeability (to allow good injectivity), high thickness, and good communication over long distances will be the most attractive. In this setting large volumes of CO2 can be injected without a risk of significant rise of the aquifer pressure. The injected CO2 will on a 1000 years time-scale diffuse into the underlying aquifer column. The resulting brine/CO2 mixture is slightly denser than the virgin brine. This density difference will cause instability and induce convective currents in the aquifer enhancing the dissolution rate of CO2 into the aqueous phase. The CO2-saturated brine segregates downwards the aquifer and mixes with fresh brine. Provided a good vertical communication in the aquifer, the CO2 will eventually dissolve in the aqueous phase and the dissolution is mainly controlled by the induced convective currents3.