Permeability Change during CO2 Injection in Carbonate Aquifers: Experimental Study
- Ibrahim Mohamed Mohamed (Texas A&M University) | Jia He (Texas A&M University) | Hisham A. Nasr-El-Din (Texas A&M University)
- Document ID
- Society of Petroleum Engineers
- SPE Americas E&P Health, Safety, Security, and Environmental Conference, 21-23 March, Houston, Texas, USA
- Publication Date
- Document Type
- Conference Paper
- 2011. Society of Petroleum Engineers
- 1.2.3 Rock properties, 5.4.2 Gas Injection Methods, 5.4 Enhanced Recovery, 1.8 Formation Damage, 5.3.4 Integration of geomechanics in models, 5.10.1 CO2 Capture and Sequestration, 1.6.9 Coring, Fishing, 6.5.7 Climate Change, 5.2 Reservoir Fluid Dynamics, 4.3.4 Scale
- 6 in the last 30 days
- 788 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 9.50|
|SPE Non-Member Price:||USD 28.00|
Chemical interactions between CO2/brine/rock can cause formation damage during CO2 injection. These interactions can affect injectivity during EOR operations, as well as affect storage capacity and seal integrity, which are primary concerns during CO2 sequestration. These interactions and the degree of impact are affected by several parameters, including pressure, temperature, brine salinity, CO2 injection rate, and rock characteristics.
Carbonic acid generated from dissolution of CO2 in the formation brine can dissolve carbonate rock. Concurrently, calcium concentration increases in the brine may cause calcium carbonate to reprecipitate. This paper addresses the effects of the formation temperature, and CO2 injection rate on the precipitation and the relative impact of dissolution and precipitation on well performance.
A core flood study was conducted using carbonate rock under various temperatures and injection rates. Core effluent samples were collected and the concentration of calcium was measured as the primary indicator of reactivity.
Results showed that CO2 injection increased core permeability at high temperature and injection rate. And the permeability of the inlet part of the core always increases, while the permeability of the rest of the core always decreases.
Geological storage of carbone 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 all 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 weak carbonic acid (H2CO3), its solubility increases with increasing pressure, and decreases as increasing temperature (Duan et al. 2005). Also CO2 solubility is affected by the water salinity, the solubility decreases as the salinity increases (Duan, and Sun 2002).
The primary factor that affects the well performance during CO2 injection is the rock type (carbonate, or sandstone). The sandstone and carbonate systems initially performed similarly. This was 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).
Qi et al. (2008) studied the effect of heterogeneity of an oilfield on the CO2 storage and tertiary oil recovery. They proposed that simultaneously injection of CO2 and water in WAG cycles with water more than CO2 in each cycle will help in retaining CO2 in the reservoir and postpones CO2 breakthrough.
Spycher et al. (2003; 2005) developed a thermodynamic model of CO2 and water and resulting salt precipitation. Obi and Blunt (2006) developed a streamline-based model taking into consideration rock dissolution and precipitation of reaction products and applied it to a study of CO2 sequestration in a deep saline aquifer.
The dissolution pattern was found to depend on the injection rate and brine composition; High flow rates give longer dissolution forms, while low flow rates lead to more compact dissolution. Presence of SO42- in the brine favors re-precipitation of insoluble salts leading to shorter wormholes and to permeability decrease (Egermann et al. 2005)
Bahar et al. (2008) addressed the issue of the dissolution rate of CO2 in formation water during CO2 injection in short term and for CO2 preservation at thermodynamic equilibrium in long term. And they found that the diffusion rate coefficient of CO2 in the formation water depends on the reservoir pressure and temperature, and the solubility of CO2 depends on the incubation period of contact.
|File Size||3 MB||Number of Pages||11|