Abstract

Carbon capture and storage (CCS) has been proposed to mitigate the accumulation of the CO2 in the atmosphere. Although CO2 is captured from large point source and stored in underground formations (depleted oil reservoir, water aquifer, and salt cavern) as a mitigation of global warming, CO2 has been injected for various purposes like in enhanced oil recovery (EOR), and enhanced coal bed methane (ECBM) recovery. Water alternating gas (WAG) technique is used to inject CO2 into underground formation either in sequestration or in EOR. Injected CO2 dissolves into the water, generating carbonic acid which dissolves carbonate rock.

The composition of the water is a critical factor that affects the rock dissolution and the formation permeability change during sequestration, especially while using sea water that contains sodium sulfate. This paper addresses the effect of brine salinity and salt type on the formation during sequestration.

A core flood study was conducted using limestone cores. The CO2 was injected under supercritical conditions. Core effluent samples were collected and concentrations of calcium and magnesium, and sodium were measured. Cores permeability was measured before and after the experiment.

The results showed that no change in permeability noted when NaCl brine was injected. Calcium chloride has the main effect in calcium dissolution and change in core permeability. Also, increasing the concentration of magnesium chloride caused more damage to the core. The experimental data was used to develop an empirical correlation to calculate the maximum calcium concentration in the core effluent, which gives good indications on various reactions that might occur inside the core.

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