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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.

Introduction
Geological storage of carbon dioxide is one of the major options to avoid the global warming problems that had the interest of the scientists in the last decade. Saline aquifers have the highest storage capacity among other types of underground storage reservoir. Understanding the chemical interactions between CO2, formation fluids, and reservoir rock are one of the main factors to obtain a successful storage operation.

CO2 is soluble in water and forms carbonic acid (H2CO3), its solubility increases with increasing pressure, and decreases with temperature (Duan et al. 2005). Also CO2 solubility is affected by the water salinity, the solubility diminishes as the salinity increases (Duan and Sun 2002).

The primary factor that affects well performance during CO2 injection is the rock type (carbonate or sandstone). The sandstone and carbonate systems initially performed similarly. This is changed when dissolution of the rock matrix takes place; solution channel was formed in the limestone, creating a dominant flow path that significantly altered the flow behavior (Grigg et al. 2008). Increases in Ca2+, Mg2+, HCO3-, and CO2 concentrations are noticed during the monitoring the produced aqueous fluids and gases confirms the dissolution effect noted during CO2 injection (Raistrick et al. 2009).

Brine salinity and composition play important roles in the chemical reaction between CO2/water/rock during CO2 sequestration. In affect the solubility of CO2 in water, and the solubility of reaction products as well. Mohamed et al. (2011) showed that injecting high salinity brines with CO2 more calcium were noticed in the core effluent samples comparing to low salinity brines.