Time since injection stops years

10,000

Figure 5.9 Storage security depends on a combination of physical and geochemical trapping. Over time, the physical process of residual CO2 trapping and geochemical processes of solubility trapping and mineral trapping increase.

5.2.2.2 Physical trapping: hydrodynamic Hydrodynamic trapping can occur in saline formations that do not have a closed trap, but where fluids migrate very slowly over long distances. When CO2 is injected into a formation, it displaces saline formation water and then migrates buoyantly upwards, because it is less dense than the water. When it reaches the top of the formation, it continues to migrate as a separate phase until it is trapped as residual CO2 saturation or in local structural or stratigraphic traps within the sealing formation. In the longer term, significant quantities of CO2 dissolve in the formation water and then migrate with the groundwater. Where the distance from the deep injection site to the end of the overlying impermeable formation is hundreds of kilometres, the time scale for fluid to reach the surface from the deep basin can be millions of years (Bachu et al., 1994).

5.2.2.3 Geochemical trapping

Carbon dioxide in the subsurface can undergo a sequence of geochemical interactions with the rock and formation water that will further increase storage capacity and effectiveness. First, when CO2 dissolves in formation water, a process commonly called solubility trapping occurs. The primary benefit of solubility trapping is that once CO2 is dissolved, it no longer exists as a separate phase, thereby eliminating the buoyant forces that drive it upwards. Next, it will form ionic species as the rock dissolves, accompanied by a rise in the pH. Finally, some fraction may be converted to stable carbonate minerals (mineral trapping), the most permanent form of geological storage (Gunter et al., 1993). Mineral trapping is believed to be comparatively slow, potentially taking a thousand years or longer. Nevertheless, the permanence of mineral storage, combined with the potentially large storage capacity present in some geological settings, makes this a desirable feature of long-term storage.

Dissolution of CO2 in formation waters can be represented by the chemical reaction:

The CO2 solubility in formation water decreases as temperature and salinity increase. Dissolution is rapid when formation water and CO2 share the same pore space, but once the formation fluid is saturated with CO2, the rate slows and is controlled by diffusion and convection rates.

CO2 dissolved in water produces a weak acid, which reacts with the sodium and potassium basic silicate or calcium, magnesium and iron carbonate or silicate minerals in the reservoir or formation to form bicarbonate ions by chemical reactions approximating to:

3 K-feldspar + 2H2O + 2CO2 ^ Muscovite + 6 Quartz + 2K+ + 2HCO~

Reaction of the dissolved CO2 with minerals can be rapid (days) in the case of some carbonate minerals, but slow (hundreds to thousands of years) in the case of silicate minerals.

Formation of carbonate minerals occurs from continued reaction of the bicarbonate ions with calcium, magnesium and iron from silicate minerals such as clays, micas, chlorites and feldspars present in the rock matrix (Gunter et al., 1993, 1997).

Perkins et al. (2005) estimate that over 5000 years, all the CO2 injected into the Weyburn Oil Field will dissolve or be converted to carbonate minerals within the storage formation. Equally importantly, they show that the caprock and overlying rock formations have an even greater capacity for mineralization. This is significant for leakage risk assessment (Section 5.7) because once CO2 is dissolved, it is unavailable for leakage as a discrete phase. Modelling by Holtz (2002) suggests more than 60% of CO2 is trapped by residual CO2 trapping by the end of the injection phase (100% after 1000 years), although laboratory experiments (Section 5.2.1) suggest somewhat lower percentages. When CO2 is trapped at residual saturation, it is effectively immobile. However, should there be leakage through the caprock, then saturated brine may degas as it is depressurized, although, as illustrated in Figure 5.7 the tendency of saturated brine is to sink rather than to rise. Reaction of the CO2 with formation water and rocks may result in reaction products that affect the porosity of the rock and the

Box 5.4 Storage security mechanisms and changes over time.

When the CO2 is injected, it forms a bubble around the injection well, displacing the mobile water and oil both laterally and vertically within the injection horizon. The interactions between the water and CO2 phase allow geochemical trapping mechanisms to take effect. Over time, CO2 that is not immobilized by residual CO2 trapping can react with in situ fluid to form carbonic acid (i.e., H2CO3 called solubility trapping - dominates from tens to hundreds of years). Dissolved CO2 can eventually react with reservoir minerals if an appropriate mineralogy is encountered to form carbon-bearing ionic species (i.e., HCO3- and CO32- called ionic trapping - dominates from hundreds to thousands of years). Further breakdown of these minerals could precipitate new carbonate minerals that would fix injected CO2 in its most secure state (i.e., mineral trapping - dominates over thousands to millions of years).

Four injection scenarios are shown in Figure 5.10. Scenarios A, B and C show injection into hydrodynamic traps, essentially systems open to lateral flow of fluids and gas within the injection horizon. Scenario D represents injection into a physically restricted flow regime, similar to those of many producing and depleted oil and gas reservoirs.

In Scenario A, the injected CO2 is never physically contained laterally. The CO2 plume migrates within the injection horizon and is ultimately consumed via all types of geochemical trapping mechanisms, including carbonate mineralization. Mineral and ionic trapping dominate. The proportions of CO2 stored in each geochemical trap will depend strongly on the in situ mineralogy, pore space structure and water composition.

In Scenario B, the migration of the CO2 plume is similar to that of Scenario A, but the mineralogy and water chemistry are such that reaction of CO2 with minerals is minor and solubility trapping and hydrodynamic trapping dominate.

In Scenario C, the CO2 is injected into a zone initially similar to Scenario B. However, during lateral migration the CO2 plume migrates into a zone of physical heterogeneity in the injection horizon. This zone may be characterized by variable porosity and permeability caused by a facies change. The facies change is accompanied by a more reactive mineralogy that causes an abrupt change in path. In the final state, ionic and mineral trapping predominate.

Scenario D illustrates CO

well-

lonic & Solubility

Mineral & Ionic

Mineral lonic & Solubility

Mineral & Ionic

Mineral

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