Carbon capture and storage (CCS), the collection of Co2 from industrial sources and its injection underground, could contribute significantly to reductions in atmospheric emissions of this greenhouse gas (iPCC, 2005).
Possible sites for injection include coal beds, deep saline aquifers and depleted oil and gas reservoirs. in this work, we focus on Co2 storage in aquifers and oil reservoirs because aquifers have the greatest storage potential and oil reservoirs can provide additional hydrocarbon production. once Co2 has been injected, the principal public and environmental concern is related to the long-term fate of the stored Co2, i.e can it be guaranteed that the Co2 will remain underground for hundreds to thousands of years? in this chapter, we propose an injection design to ensure that the majority of Co2 injected is trapped rapidly and effectively.
injecting Co2 into depleted oil and gas reservoirs resulting in additional hydrocarbon recovery has the primary advantage of being economically beneficial (Lake, 1989). CO2 flooding is an effective tertiary recovery
mechanism that uses established injection infrastructure and the experience of the oil industry to extend the profitability of many reservoir systems.
While suitable formations are easily located, they are inequitably distributed geographically (orr, 2004). Compared with oil and gas reservoirs, deep saline aquifers are widely distributed throughout the globe, although they often have poorly characterised geology. These systems could therefore be used for the disposal of anthropogenic Co2 in locations where there are no suitable oil or gas reservoir alternatives.
according to the international energy agency (iea) Greenhouse R&D Program, oil and gas reservoirs have an estimated Co2 storage capacity of about 920 Gt while deep saline aquifers could store between 400 and 10 000 Gt (Gale, 2003). This is compared to annual global CO2 emissions of approximately 31 Gt. Although there are significant uncertainties in these estimates, geological formations clearly have a large storage potential. The Co2 will generally be injected underground as a supercritical fluid (the critical pressure of Co2 is 7.38 MPa, corresponding to normally-pressured reservoir depths of around 800 m; the critical temperature is 31 °C). Typical densities in formations of greater than 800 m depth range from 500–900 kg m–3.
The injected Co2 will be less dense than the formation fluids and this will cause the sequestered gas to migrate to the top of the rock layer because of buoyancy forces. as we are interested in the long-term trapping of the Co2 for hundreds to thousands of years, it is imperative that the Co2 cannot escape.
over hundreds to thousands of years, the Co2 will dissolve in the formation brine forming a denser phase that will sink; a weakly acidic solution results that may react over thousands to millions of years with the host rock forming solid carbonate. While these are effective storage mechanisms, the timescales for significant dissolution or reaction mean that the CO2 remains mobile in its own phase for many years and needs to be contained under an impermeable caprock (ennis-King and Paterson, 2002; Xu et al., 2003; Hesse et al., 2007). While in some, well-characterised systems, such as Sleipner (Korbứl and Kaddour, 1995), or in depleted oil and gas fields, there is some reasonable assurance that the caprock will contain buoyant Co2 for many centuries, if CCS is to be implemented at a scale to make a significant impact on atmospheric emissions, storing one or more Gt of carbon per year, it will be necessary, in many sites, to inject Co2 into deep permeable formations where the caprock integrity is highly uncertain. in these cases, another strategy is required to ensure safe long-term storage.
Simulation studies of Co2 storage have emphasised the importance of capillary trapping (see, for instance, ennis-King and Paterson, 2002; Kumar et al., 2005; obi and Blunt, 2006; Juanes et al., 2006; ide et al., 2007).
When a non-wetting phase is displaced by a wetting phase in a porous
medium, the non-wetting phase can be trapped in the larger pore spaces;
surrounded by the wetting phase, it can no longer move and is effectively trapped. Figure 6.1 shows a two-dimensional cross-section through a three- dimensional sandstone sample imaged at a scale of a few microns using micro-CT scanning. The image is obtained after water has displaced oil.
This process is well established in the oil industry: water is used to displace oil from reservoirs, but typically only around half the oil is recovered since it remains trapped in the pore space (Lake, 1989). Further water injection simply leads to excessive recycling of water from injection to production wells with little or no further oil recovery. We suggest that this mechanism could be used to trap Co2, as the non-wetting phase, in storage sites.
The Co2 would be trapped when it is displaced by water flow in aquifers (ennis-King and Paterson, 2002; Kumar et al., 2005). This could occur
1350 micrometer
6.1 Pore-scale bubbles of trapped non-wetting phase (shown in grey) surrounded by the wetting phase (white). The rock is shown in black.
This is a two-dimensional slice of a three-dimensional image of a Clashach sandstone obtained using micro-CT scanning at a resolution of approximately 5 mm.
due to a regional movement of groundwater or when a buoyant Co2 plume migrates upwards: at the trailing edge, water displaces – and potentially traps – the Co2. Juanes et al. (2006) suggested that injecting water into the aquifer would enhance this natural process, while Qi et al. (2009) proposed an injection scheme where Co2 and brine are injected together followed by chase brine. The initial water and Co2 injection – already well established in the oil industry for gas injection projects (Lake, 1989) – ensures that the Co2 has a lower effective mobility contrast with the brine in the aquifer, allowing more of the formation to be contacted by Co2, while the chase brine rapidly and effectively traps the Co2 (Qi et al., 2009).
We will now briefly review evidence for the degree of capillary trapping in the literature, and then describe the storage strategy – involving injected brine – in more detail.