Salting-out effect during CO2 storage in deep saline aquifers can have severe consequences during carbon capture and storage operations in terms of CO2 injectivity. The impact and physical mechanisms of salt precipitation in the vicinity of injection area is not fully clear. Core flooding experiments were conducted to investigate the effects of different brine-saturated sandstones during CO2 injection. The reported findings are directly relevant for CO2 sequestration operations as well as enhanced gas and oil recovery technologies (EGR, EOR). The characterisation and core analysis of the core samples to validate the petrophysical properties (Porosity, Permeability) of the core sample was carried out before core flooding using Helium Porosimetry. The brine solutions were prepared from different salts (NaCl, CaCl2, KCl, MgCl2), which represent the salt composition of a typical deep saline aquifers. The core samples were saturated with different brine salinities (5, 10, 15, 20, 25, wt.% Salt) and core flooding process was conducted at a simulated reservoir pressure of 1500 psig, temperature of 45°C, with a constant injection rate of 3 ml/min. The salting out effect was greater in MgCl2 and CaCl2 as compared to monovalent salt (NaCl and KCl). Porosity decreased by 0.5% to 7% while permeability was decreased by up to 50% in all the tested scenarios. CO2 solubility was evaluated in a pressure decay test, which in turn affects injectivity. The results from this study showed that the magnitude of CO2 injectivity impairment is dependent on both the concentration and type of salt. The findings provide basic understanding of the different salt concentration inducing salt precipitation during CO2 injection into core samples completely saturated with the formation brine. The insight gained in this study could be useful in designing an operating condition for CO2 sequestration in deep saline aquifers and minimising injectivity problems.

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