Effects of CO2 Density and Solubility on Storage Behavior in Saline Aquifers
- T. Takasawa (Waseda University) | Ryusuke Matsuyama (Waseda University) | Norio Arihara (Waseda University)
- Document ID
- Society of Petroleum Engineers
- SPE Asia Pacific Oil and Gas Conference and Exhibition, 18-20 October, Brisbane, Queensland, Australia
- Publication Date
- Document Type
- Conference Paper
- 2010. Society of Petroleum Engineers
- 5.3.2 Multiphase Flow, 4.3.4 Scale, 5.2.2 Fluid Modeling, Equations of State, 5.2.1 Phase Behavior and PVT Measurements, 6.5.3 Waste Management, 5.4.2 Gas Injection Methods, 1.2.3 Rock properties, 5.10.1 CO2 Capture and Sequestration, 6.5.1 Air Emissions, 5.8.8 Gas-condensate reservoirs, 5.4 Enhanced Recovery, 5.1.2 Faults and Fracture Characterisation, 5.5 Reservoir Simulation, 5.1.1 Exploration, Development, Structural Geology
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CO2 sequestration in deep saline aquifers is an essential and quick-remedial measure to reduce CO2 emissions to atmosphere. At conditions of 800 to 4000 meters deep aquifers, CO2 is supercritical and a liquid-like fluid of which density and solubility into water are strong functions of pressure and temperature. In geological sequestration of CO2, behavior of the injected CO2 undergoes multi-phase flow, dissolution into the aqueous phase, and reaction with rock. In aquifers of the closed boundary or open boundary with weak regional groundwater flow, densities of CO2 in its own phase and CO2-dissolved water dominantly influence the extent of horizontal and vertical CO2 migration. In this study, we investigated effects of CO2 and aqueous-phase densities on the migration extent for a long time scale after injection.
In order to simulate advection, dissolution, and precipitation processes, we first developed a streamline-based model assuming incompressible and immiscible two-phase flow of CO2 and water. Procedures of the common streamline method were followed. Along streamlines, 1-dimensional flow equations were solved for CO2 in its own phase and CO2 concentration in aqueous phase, where reaction of dissolved CO2 is accounted for in the latter equation. CO2 flow due to gravity was calculated on the underlying grid, and so were permeability changes.
After validating the model, we performed simulations of CO2 sequestration in 3-dimensional homogeneous and heterogeneous aquifers. CO2 migration at a long timescale depends on the aquifer pressure and temperature that directly influences density, viscosity, and solubility of CO2 phase. The gravity segregation is controlled equally by aquifer pressure and temperature, and by vertical permeability, while the advective migration is less affected by the pressure and temperature, but more by heterogeneity. As precipitation, that is the ultimate form of sequestration, is directly related to migration extents of CO2 and aqueous phases, CO2 injection schemes need to be appropriately designed in accordance with the aquifer pressure, temperature, and heterogeneity.
Although CO2 EOR technologies have been developed and widely implemented in fields since early 1980's, carbon capture and storage (CCS) is a recent concept that has not been fully tested in fields for data and experiences.1, 2 As interests and needs in CCS are increasing, research efforts are being greatly intensified to address issues associated with CO2 storage from broad aspects. The simulation technology for underground fluid flow is extremely useful to identify and examine issues and to investigate solutions. The capability of simulation has been demonstarated in modeling the phase and flow behavior of CO2 in saline aquifers, and in finding controlling mechanisms in CO2 storage.
Previous studies have identified four principal physical processes that influence CO2 storage making the injected CO2 immobile or trapped: structural trapping, residual gas trapping, solubility trapping, and mineral trapping.3-6 The injected CO2, that is a super-critical fluid in most cases, migrates upward due to buoyancy and latarally due to regional flow, while dissolving some parts into water and immobilizing as residual gas in pores. In the longer time-scale, the dissolved CO2 reacts with the minerals and precipitates in place. To avoid possible leakage through cap rock or sealing faults, the amount of CO2 should be maximized in the forms of the latter three mechanisms.
To study about possible fingers in buoyance-driven displacement that cause more CO2 reach the structure top, Bryant et al.7 used fine-grid numerical simulations to examine effects of heterogeneity and dip angle on buoyant instability, and confirmed that CO2 migration does not develop fingers, and is strongly affected by heterogeneous rock properties such as permeability changes, anisotropy, and capillary pressure as well as by formation dipping.
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