**2. Geological background of dissolution trapping**

The International Panel on Climate Change (IPCC) (2005) has suggested several possible geological storage media, including deep saline aquifers, oil or gas reservoirs and unmineable

Dissolution Trapping of Carbon Dioxide in

Reservoir Formation Brine – A Carbon Storage Mechanism 235

project, where 1 Mt CO2/a are injected into the Utsira sandstone formation in the Norwegian sector of the North Sea at 800m depth (Iglauer 2011). This project started in 1996, and reservoir CO2 monitors confirm reservoir simulations which predict that the CO2 rises

CO2 from this rising CO2-plume dissolves in brine as it migrates upwards (Pruess and Garcia 2002, Bachu and Adams 2003). The CO2-enriched brine has a slightly higher density than the original brine (Ennis-King and Paterson 2005, Moortgat et al. 2011). This leads to gravitational flow instabilities in the reservoir (Riaz et al. 2006, Pau et al. 2010), and it is believed that the CO2-rich brine sinks in the reservoir over hundreds to millions of years (Bachu 2000, Ennis-King and Paterson 2005, Lindeberg and Wessel-Berg 1997) in the form of thick and thin fingers (cp. Figures 1 and 2), however this is an active area of research and it

Again, this storage mechanism is very safe, but if the dissolution process is a very slow process then that means that the leakage risk is high in the short term (= initial several

has been suggested that this mechanism is considerably faster (Moortgat et al. 2011).

Fig. 1. CO2-enriched brine sinks in a normalized simulated reservoir over hundreds to thousands of years (from Riaz et al. 2006 with permission from Cambridge University Press). The CO2-concentration contours are shown in greyscales. The x- and y-axis are normalized lengths, the corresponding absolute values are in the kilometer range

It has been reported that 0.9-3.6 mol% of CO2 can be dissolved in brine, depending on pressure, temperature and brine composition (Rumpf et al. 1994, Koschel et al. 2006, Bando et al.

**4. Thermodynamics of CO2 dissolution into formation brine** 

upwards and accumulates beneath the caprock (Hesse et al. 2008).

hundreds of years) since the CO2 may escape before it can dissolve.

coal seams. In case of CO2 storage in coal, a benefit is that additional methane is produced which is adsorbed on the coal surface and displaced by CO2 (so-called enhanced coal-bed methane (ECBM) production). However, CO2 injection leads to the highly detrimental effect of coal swelling which strongly deteriorates injectivity as observed from laboratory and pilot field studies (Reeves and Oudinot, 2005). This text focuses on aquifers and oil/gas reservoirs and will not discuss ECBM any further as low permeability and swelling characteristics limit the scale of exploitation of coalbeds as potential CO2 storage sinks.

In terms of CO2 storage, deep saline aquifers – too saline for drinking water or agricultural usage – are most promising, because they are geographically widespread and have large potential storage capacities. Published storage capacity estimates especially for aquifers vary widely based on the assumptions made. This is an active area of research with the objective to provide accurate basic information so that effective CCS schemes can be planned in order to store the large quantities of anthopogenic CO2 emitted (circa 30 Gt CO2/a, IPCC 2007).

To focus on dissolution trapping, the topic of this chapter, the main problem associated with it is addressed straight away: it is the slow speed of CO2 dissolution and the two-phase (CO2 and brine) reservoir flow dynamics – as long as the CO2 is in a separate supercritical state it tends to flow upwards because of buoyancy forces, and it can potentially leak to the surface. Mass transfer of CO2 from the supercritical phase into the aqueous phase is the timedetermining step in dissolution trapping which therefore also determines leakage risk. In fact CO2 is only stored safely once it is dissolved in the aqueous phase (or precipitated as a solid). Hence the study of CO2 dissolution is an essential aspect of CCS risk assessment. Mass transfer and solubilities of CO2 into brine are functions of pressure, temperature, salinity, local CO2 concentration and subsequent chemical reactions (formation and dissociation of carbonic acid and following rock dissolution/precipitation). Moreover interfacial areas scCO2-brine play a vital role in the mass transfer kinetics, and they are closely related to the two-phase flow dynamics in the reservoir. All these aspects will be discussed in this chapter. In addition several reservoir scale computer simulations will be presented which analyze fluid flow and CO2 storage in CCS schemes.

In this context it is worth noting that CO2 is a naturally abundant species in the subsurface. Rumble et al. (1982) suggested two possible chemical reactions between calcite and quartz which formed this naturally occuring CO2 over geological times. A result of this is that CO2 content in oil or gas reservoirs can be very high. In gas reservoirs CO2 content can reach concentrations larger than 90 mol% and in oil reservoirs CO2 content can be as high as 70-80 mol% (Badessich et al. 2005). As an example Ballentine et al. (2001) state that the CO2 concentration in gas fields in Texas varies from 3% to 97% depending on the geographical location.

In summary dissolution trapping is a feasible mechanism to store large quantities of CO2, and if a route could be found to quickly dissolve scCO2 into brine CO2 emissions could be dramatically, rapidly and economically reduced this way, maybe even solving the climate change problem caused by CO2 gas emitted from large point-sources. However, although CO2 contributes the largest chunk to greenhouse gas emissions, other gases such as CH4, CO, N2O, halogenated carbons, etc., also need to be eliminated to completely stop global warming. One route for disposing these gases may also be dissolution into formation brines.

### **3. Reservoir fluid dynamics**

In actual ongoing CCS projects large quantities of CO2 are injected deep underground. The largest injection time for a pure CCS project has been achieved in Norway in the Sleipner

coal seams. In case of CO2 storage in coal, a benefit is that additional methane is produced which is adsorbed on the coal surface and displaced by CO2 (so-called enhanced coal-bed methane (ECBM) production). However, CO2 injection leads to the highly detrimental effect of coal swelling which strongly deteriorates injectivity as observed from laboratory and pilot field studies (Reeves and Oudinot, 2005). This text focuses on aquifers and oil/gas reservoirs and will not discuss ECBM any further as low permeability and swelling characteristics

In terms of CO2 storage, deep saline aquifers – too saline for drinking water or agricultural usage – are most promising, because they are geographically widespread and have large potential storage capacities. Published storage capacity estimates especially for aquifers vary widely based on the assumptions made. This is an active area of research with the objective to provide accurate basic information so that effective CCS schemes can be planned in order to store the large quantities of anthopogenic CO2 emitted (circa 30 Gt CO2/a, IPCC 2007). To focus on dissolution trapping, the topic of this chapter, the main problem associated with it is addressed straight away: it is the slow speed of CO2 dissolution and the two-phase (CO2 and brine) reservoir flow dynamics – as long as the CO2 is in a separate supercritical state it tends to flow upwards because of buoyancy forces, and it can potentially leak to the surface. Mass transfer of CO2 from the supercritical phase into the aqueous phase is the timedetermining step in dissolution trapping which therefore also determines leakage risk. In fact CO2 is only stored safely once it is dissolved in the aqueous phase (or precipitated as a solid). Hence the study of CO2 dissolution is an essential aspect of CCS risk assessment. Mass transfer and solubilities of CO2 into brine are functions of pressure, temperature, salinity, local CO2 concentration and subsequent chemical reactions (formation and dissociation of carbonic acid and following rock dissolution/precipitation). Moreover interfacial areas scCO2-brine play a vital role in the mass transfer kinetics, and they are closely related to the two-phase flow dynamics in the reservoir. All these aspects will be discussed in this chapter. In addition several reservoir scale computer simulations will be

In this context it is worth noting that CO2 is a naturally abundant species in the subsurface. Rumble et al. (1982) suggested two possible chemical reactions between calcite and quartz which formed this naturally occuring CO2 over geological times. A result of this is that CO2 content in oil or gas reservoirs can be very high. In gas reservoirs CO2 content can reach concentrations larger than 90 mol% and in oil reservoirs CO2 content can be as high as 70-80 mol% (Badessich et al. 2005). As an example Ballentine et al. (2001) state that the CO2 concentration in gas fields in Texas varies from 3% to 97% depending on the geographical

In summary dissolution trapping is a feasible mechanism to store large quantities of CO2, and if a route could be found to quickly dissolve scCO2 into brine CO2 emissions could be dramatically, rapidly and economically reduced this way, maybe even solving the climate change problem caused by CO2 gas emitted from large point-sources. However, although CO2 contributes the largest chunk to greenhouse gas emissions, other gases such as CH4, CO, N2O, halogenated carbons, etc., also need to be eliminated to completely stop global warming. One route for disposing these gases may also be dissolution into formation brines.

In actual ongoing CCS projects large quantities of CO2 are injected deep underground. The largest injection time for a pure CCS project has been achieved in Norway in the Sleipner

limit the scale of exploitation of coalbeds as potential CO2 storage sinks.

presented which analyze fluid flow and CO2 storage in CCS schemes.

location.

**3. Reservoir fluid dynamics** 

project, where 1 Mt CO2/a are injected into the Utsira sandstone formation in the Norwegian sector of the North Sea at 800m depth (Iglauer 2011). This project started in 1996, and reservoir CO2 monitors confirm reservoir simulations which predict that the CO2 rises upwards and accumulates beneath the caprock (Hesse et al. 2008).

CO2 from this rising CO2-plume dissolves in brine as it migrates upwards (Pruess and Garcia 2002, Bachu and Adams 2003). The CO2-enriched brine has a slightly higher density than the original brine (Ennis-King and Paterson 2005, Moortgat et al. 2011). This leads to gravitational flow instabilities in the reservoir (Riaz et al. 2006, Pau et al. 2010), and it is believed that the CO2-rich brine sinks in the reservoir over hundreds to millions of years (Bachu 2000, Ennis-King and Paterson 2005, Lindeberg and Wessel-Berg 1997) in the form of thick and thin fingers (cp. Figures 1 and 2), however this is an active area of research and it has been suggested that this mechanism is considerably faster (Moortgat et al. 2011).

Again, this storage mechanism is very safe, but if the dissolution process is a very slow process then that means that the leakage risk is high in the short term (= initial several hundreds of years) since the CO2 may escape before it can dissolve.

Fig. 1. CO2-enriched brine sinks in a normalized simulated reservoir over hundreds to thousands of years (from Riaz et al. 2006 with permission from Cambridge University Press). The CO2-concentration contours are shown in greyscales. The x- and y-axis are normalized lengths, the corresponding absolute values are in the kilometer range
