Abstract
Injection of CO2 into saline storage aquifers is often accompanied by drying of the formation water and salt precipitation. Subsequent salt clogging of a well bore and the near wellbore rock matrix may lead to injectivity impairment. In this paper we present medium-scale experiments on salt precipitation in the near-well region during a dry CO2 injection. In an effort to better simulate the geometry and the flow conditions in the field situation our purpose-designed experimental setup enables (1) realistic radial geometry of CO2 flow, and (2) opened boundary conditions for brine inflow allowing capillary and diffusive flux of brine components from and to practically infinite source of formation water.During the course of injection, no significant pressure build-up was observed across the rock specimen, indicating that permeable flow paths were not completely clogged. Post-test analysis of the specimen included X-ray computed tomography, powder X-ray diffraction and scanning electron microscopy in order to quantify fluid saturation, brine salinity and halite precipitation. The analysis provided indication of the most probable flow patterns of supercritical CO2 and CO2 rich brine in the system. The resulting drying and precipitation is discussed in light of the different drying regimes created under the present flow conditions.
Highlights
Storage in subsurface geological formations is one method to mitigate increasing CO2 concentrations in the atmosphere
During the course of injection, no significant pressure build-up was observed across the rock specimen, indicating that permeable flow paths were not completely clogged
Several physical mechanisms have to be considered in order to adequately model propagation of dry-out front and the extent of salt precipitation (Miri and Hellevang, 2016): (1) displacement of brine by the injected CO2; (2) evaporation of water into the CO2 stream which leads to residual brine oversaturation and salt precipitation; (3) back-flow of brine driven by the capillary forces toward the dried out regions; (4) diffusion of salts within the aqueous phase driven by osmotic pressure; (5) enhanced evaporation of water from near interface polycrystalline aggregates due to enhanced surface area – self-enhancing effect (Miri et al, 2015); (6) preferential flow of less dense fluid on the top of a reservoir unit
Summary
Storage in subsurface geological formations is one method to mitigate increasing CO2 concentrations in the atmosphere. Injectivity is primarily dependent on formation permeability and volume, pilot CO2 storage projects have revealed other factors which may negatively affect injectivity. Among these factors are: presence of bacteria that produce biofilms, or scaling that will plug the formation (Morozova et al, 2011; Zettlitzer et al, 2010) and mineral precipitation due to water evaporation during dry CO2 injection into saline aquifers (Baumann et al, 2014; Eiken et al, 2011; Grude et al, 2014; Hansen et al, 2013; Martens et al, 2014). Several physical mechanisms have to be considered in order to adequately model propagation of dry-out front and the extent of salt precipitation (Miri and Hellevang, 2016): (1) displacement of brine by the injected CO2; (2) evaporation of water into the CO2 stream which leads to residual brine oversaturation and salt precipitation; (3) back-flow of brine driven by the capillary forces toward the dried out regions; (4) diffusion of salts within the aqueous phase driven by osmotic pressure; (5) enhanced evaporation of water from near interface polycrystalline aggregates due to enhanced surface area – self-enhancing effect (Miri et al, 2015); (6) preferential flow of less dense fluid on the top of a reservoir unit (gravity override)
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