**7. Multiphase flow in the reservoir – flow of the scCO2 phase**

The flow of the scCO2 phase affects the dissolution process as it determines interfacial areas and overall position of the CO2 in the reservoir. Reservoir models predict that the injected CO2 phase rises upwards and is stopped by the caprock (Qi et al. 2009, Juanes 2006, Hesse 2008). This behaviour has been confirmed experimentally in the Sleipner formation by seismic imaging (Iglauer 2011).

Small residual CO2 clusters at the trailing edge of the rising CO2 plume - trapped by capillary forces (Iglauer et al. 2010, Juanes et al. 2006) - strongly increase CO2-brine interfacial areas. Hence CO2 dissolution speed is predicted to be accelerated, especially if combined with convective flow of saturated/undersaturated brine. However experimental reservoir monitoring data is needed to confirm these predictions. Optimal conditions would be to bring undersaturated brine continuously into contact with residual micrometer-sized CO2 bubbles while removing saturated or highly CO2-enriched brine simultaneously. Engineering this dissolution phenomenon can be a promising topic for future research.

Moreover, and most likely even more significant in the short term - thereby strongly affecting the economics of CCS schemes are the fluid dynamics associated with CO2 injection. CO2 injectivity and CO2-wellbore effects can strongly impact CCS schemes. For

Dissolution Trapping of Carbon Dioxide in

p pressure [Pa] T temperature [K] µ viscosity [Pa.s] µCO2 viscosity of CO2 [Pa.s] µH2O viscosity of water [Pa.s] ρ density [kg/m3]

ρbrine density of brine [kg/m3]

Δρ density difference [kg/m3] g gravitational constant [m/s2]

R universal gas constant [J/mol.K]

ZD normalized reservoir height [-]

VCO2 molar volume of CO2 [m3/mol] YCO2 dissolved CO2 mass fraction [-]

αL longitudinal dispersivity [m] Ddis dispersion coefficient [m2/s]

j volumetric flux [m/s]

C∞ concentration at infinity [mol/L] A surface area of CO2 droplet [m2] k mass transfer coefficient [m/s]

u interstitial or pore flow velocity [m/s]

C0 surface concentration of droplet [mol/L]

Adamczyk, K., Premont-Schwarz, M., Pines, D., Pines, E., Nibbering, E.T.J. (2009). Real-time

observation of carbonic acid formation in aqueous solution", *Science*, 326, 1690-

y molality [mol/kg]

F fugacity coefficient [-]

H reservoir height [m]

tD dimensionless time [-]

Ra Rayleigh number [-] Re Reynolds number [-] Sh Sherwood number [-] Sc Schmidt number [-]

t time [s]

z depth [m] α dispersivity [m]

**11. References** 

1694.

2 1(0) *CO* μ

ρCO2,brine density of CO2-enriched brine [kg/m3]

standard chemical potential of CO2 [J/mol]

Vm,brine apparent molar volume of CO2 in brine [m3/mol]

λCO2-Na interaction parameter between CO2 and Na<sup>+</sup>

ζCO2-Na-Cl interaction parameter between CO2 and Na<sup>+</sup> and - Cl

DCO2-H2O diffusion coefficient of CO2 into brine [m2/s] DH2O-CO2 diffusion coefficient of H2O into scCO2 [m2/s] DCO2-HC diffusion coefficient of CO2 into hydrocarbon [m2/s] DCO2-C10 diffusion coefficient of CO2 into n-decane [m2/s]

Reservoir Formation Brine – A Carbon Storage Mechanism 257

example, flow in the reservoir is strongly influenced by changes in rock morphology and wettability, which can result in changes of relative permeabilites and capillary pressures of CO2 and brine. Relative permeability and capillary pressures however strongly influence multi-phase fluid flow in the reservoir. As an example, there is evidence that wettability (Espinoza and Santamaria 2010, Chiquet et al. 2007) and rock pore morphology – especially carbonates (Luquot and Gouze 2009) are changed by scCO2. More research work is required in this area to completely understand these changes and improve CCS risk assessment.
