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Abstract
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.
Introduction
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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