Abstract
CO2 storage in fractured reservoirs may lead to fast CO2 flow through interconnected fracture networks; but the role of isolated fractures on brine-CO2 multiphase flow systems remains unclear. We present the results of a brine-CO2 flow-through experiment in which we assess the change in transport properties of a synthetic sandstone plug (a surrogate of a saline siliciclastic CO2 reservoir) containing non-connected fractures aligned 45° from its axis. The test was performed at 40 MPa of constant hydrostatic confining pressure and ~11 MPa of pore pressure, at room temperature (~19.5 °C), using pure liquid-CO2 and 35 g L−1 NaCl salt solution. The injected CO2-brine volume fraction was increased from 0 to 1 in 0.2 units-steps (drainage). Upon achievement of the maximum CO2 saturation (SCO2 ~0.6), the plug was flushed-back with the original brine (imbibition). During the test, we monitored simultaneously pore pressure, temperature, axial and radial strains, and bulk electrical resistivity. The fractured sample showed lower values of cross- and end-points in the relative permeability curves to CO2 compared to non-fractured samples, from comparable experiments performed at similar pressure and brine salinity conditions, but different temperature. Our results suggest that a non-connected fracture network affects the mobility of the individual phases, favouring the trapping of CO2 in the porous medium and improving the storage efficiency of the reservoir. These evidences show the need of a better understanding of fracture connectivity prior to discard fractured reservoirs as unsuitable geological formations for CO2 storage.
Highlights
The success of large-scale CO2 geosequestration and long-term storage highly depends on the capacity of the reservoir to avoid potential CO2 leakage to the surface along permeable underground pathways
We focus on assessing the transport properties of non-connected fractured saline siliciclastic CO2 storage reservoirs, by analysing CO2-induced changes in electrical resistivity and relative permeability
Pp is higher during imbibition than during the original drainage (100% brine) episode, which can be related to the presence of a residual CO2 fraction in the porous medium
Summary
The success of large-scale CO2 geosequestration and long-term storage highly depends on the capacity of the reservoir to avoid potential CO2 leakage to the surface along permeable underground pathways. Depleted oil and gas reservoirs, saline aquifers, and coal seams have been recognized as suitable formations for CO2 storage (IPCC, 2005). Saline aquifers are the most attracting sites due to its worldwide distribution, high potential storage capacity and low reactivity to CO2. Even in reservoirs with low potential reactivity to CO2 (e.g., sandstone), CO2-induced salt precipitation can significantly affect the injection efficiency in the CO2 storage site, as observed in Ketzin (Baumann et al, 2014) or in the Tubåen Formation at the Snøhvit Field (Grude et al, 2014). Changes in permeability caused by mineral dissolution/precipitation strongly depend on the specific location where these processes occur (i.e. at open pore spaces or in necks or throats; Canal et al (2013); Stack et al (2014)) in connection to the main flow paths
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