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Abstract
The effect of completion techniques and reservoir heterogeneity on CO2 storage
and injectivity in saline aquifers has been studied using a compositional
reservoir simulator CMG-GEM. Two reservoir models were built using data
extracted from publications, to represent a deep saline aquifer and a shallow
aquifer. The effect of completion methods, including partial perforation of the
reservoir net pay (partial completion), well geometry, orientation, location
and length, on CO2 storage are discussed. Heterogeneity effect has been
addressed considering three parameters: mean permeability, vertical to
horizontal permeability ratio, and permeability variation. Sensitivity analysis
was carried out using design of experiments (DOE) to determine the dominant
factors affecting CO2 storage capacity and CO2 injectivity. Simulation results
show that completing all layers, using horizontal wells set in upper layers
with a length around 250-300 m are the most favorable choices for CO2 storage
capacity in the aquifer examined.
Mean permeability affects CO2 storage capacity and injectivity the most; kv/kh
affects CO2 injectivity storage capacity more than permeability variation, Vk.
More CO2 can be stored in the heterogeneous reservoirs with low mean
permeability; however, high injectivity can be achieved in the uniform
reservoirs with high mean permeability.
Introduction
Carbon sequestration in saline aquifers has been identified as a promising
method of reducing atmospheric CO2 in response to growing concerns over climate
change. Saline aquifers are attractive for such sequestration because of their
large capacity and broad distribution (IPCC, 2005; Hesse et al., 2006; Bryant,
2007; Gibson-Poole et al., 2007). Many projects have been carried out and have
demonstrated the viability of CO2 sequestration in saline aquifers since the
early 1990s (Pruess et al., 2003; Jikich et al., 2003; Sengul, 2006).
Saline aquifers are defined as porous and permeable reservoir rocks that
contain saline fluid in the pore spaces between the rock grains. Carbon dioxide
can be trapped in saline aquifers through a combination of physical and
chemical processes, which can be classified into structural and stratigraphic
trapping, solubility trapping, mineral trapping, and hydrodynamic trapping
(Koide et al., 1992; Gunter et al., 1993; Holtz, 2002; Flett et al., 2005;
Bachu et al., 2007). When injected, CO2 moves upward to fill the geological
traps, parts of CO2 dissolves, some interacts with formation water and rock
minerals, and some trapped by capillary forces as a residual phase.
The potential of CO2 storage in saline aquifers is largely determined by
aquifer properties (Cinar et al., 2007), and much work has been performed to
determine the effect of aquifer properties on CO2 storage. The properties
include seal area, formation dip, reservoir heterogeneity, porosity and
permeability, temperature, pressure, salinity, and mineralogy (Kumar et al.,
2005; Bachu et al., 2007; Hurter et al., 2007; Ülker et al., 2007; Yang et al,
2010). Among them, heterogeneity plays an important role because the spatial
correlation of permeability determines the preferential CO2 flow paths and the
complex migration paths resulted from heterogeneity enhance solution and
residual gas trapping (Bryant et al., 2006). Although there are studies on mean
permeability, the vertical to horizontal permeability ratio, and permeability
variation, those studies were reported separately and only focus on deep saline
aquifers.
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