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Chapter 5: Underground geological storage 205 controls? (Sections 5.2 and 5.3) • How long can CO2 remain stored underground? (Section allowing CO2 to enter the pore spaces initially occupied by the in situ formation fluids. The amount and spatial distribution of pressure buildup in the formation will depend on the rate of injection, the permeability and thickness of the injection formation, the presence or absence of permeability barriers within it and the geometry of the regional underground water (hydrogeological) system. 5.2) • How much and where can CO2 be stored in the subsurface, locally, regionally, globally? Is it a modest niche opportunity or is the total storage capacity sufficient to contain a large proportion of the CO2 currently emitted to the atmosphere? (Section 5.3) Once injected into the formation, the primary flow and transport mechanisms that control the spread of CO2 include: • Fluid flow (migration) in response to pressure gradients • Are there significant opportunities for CO2-enhanced oil and gas recovery? (Section 5.3) • How is a suitable storage site identified and what are its geological characteristics? (see Section 5.4) created by the injection process; • Fluid flow in response to natural hydraulic gradients; • Buoyancy caused by the density differences between CO2 • What technologies are currently available for geological storage of CO2? (Section 5.5) and the formation fluids; • Diffusion; • Can we monitor CO2 once it is geologically stored? (Section 5.6) • Dispersion and fingering caused by formation heterogeneities and mobility contrast between CO2 and formation fluid; • Will a storage site leak and what would be the likely consequences? (Sections 5.6 and 5.7) • Dissolution into the formation fluid; • Mineralization; • Pore space (relative permeability) trapping; • Adsorption of CO2 onto organic material. • Can a CO2 storage site be remediated if something does go wrong? (Sections 5.6 and 5.7) • Can a geological storage site be operated safely and if so, how? (Section 5.7) • Are there legal and regulatory issues for geological storage and is there a legal/regulatory framework that enables it to be undertaken? (Section 5.8) The rate of fluid flow depends on the number and properties of the fluid phases present in the formation. When two or more fluids mix in any proportion, they are referred to as miscible fluids. If they do not mix, they are referred to as immiscible. The presence of several different phases may decrease the permeability and slow the rate of migration. If CO2 is injected into a gas reservoir, a single miscible fluid phase consisting of natural gas and CO2 is formed locally. When CO2 is injected into a deep saline formation in a liquid or liquid-like supercritical dense phase, it is immiscible in water. Carbon dioxide injected into an oil reservoir may be miscible or immiscible, depending on the oil composition and the pressure and temperature of the system (Section 5.3.2). When CO2 is injected into coal beds, in addition to some of the processes listed above, adsorption and desorption of gases (particularly methane) previously adsorbed on the coal take place, as well as swelling or shrinkage of the coal itself (Section 5.3.4). • What is the likely cost of geological storage of CO2? (Section 5.9) • After reviewing our current state of knowledge, are there things that we still need to know? What are these gaps in knowledge? (Section 5.10). The remainder of this chapter seeks to address these questions. 5.2 Storage mechanisms and storage security Geological formations in the subsurface are composed of transported and deposited rock grains organic material and minerals that form after the rocks are deposited. The pore space between grains or minerals is occupied by fluid (mostly water, with proportionally minute occurrences of oil and gas). Open fractures and cavities are also filled with fluid. Injection of CO2 into the pore space and fractures of a permeable formation can displace the in situ fluid or the CO2 may dissolve in or mix with the fluid or react with the mineral grains or there may be some combination of these processes. This section examines these processes and their influence on geological storage of CO2. 5.2.1 CO2 flow and transport processes Injection of fluids into deep geological formations is achieved by pumping fluids down into a well (see Section 5.5). The part of the well in the storage zone is either perforated or covered with a permeable screen to enable the CO2 to enter the formation. The perforated or screened interval is usually on the order of 10–100 m thick, depending on the permeability and thickness of the formation. Injection raises the pressure near the well, Because supercritical CO2 is much less viscous than water and oil (by an order of magnitude or more), migration is controlled by the contrast in mobility of CO2 and the in situ formation fluids (Celia et al., 2005; Nordbotten et al., 2005a). Because of the comparatively high mobility of CO2, only some of the oil or water will be displaced, leading to an average saturation of CO2 in the range of 30–60%. Viscous fingering can cause CO2 to bypass much of the pore space, depending on the heterogeneity and anisotropy of rock permeability (van der Meer, 1995; Ennis-King and Paterson, 2001; Flett et al., 2005). In natural gas reservoirs, CO2 is more viscous than natural gas, so the ‘front’ will be stable and viscous fingering limited. The magnitude of the buoyancy forces that drive vertical flow depends on the type of fluid in the formation. In saline formations, the comparatively large density difference (30– 50%) between CO2 and formation water creates strong buoyancy forces that drive CO2 upwards. In oil reservoirs, the densityPDF Image | CARBON DIOXIDE CAPTURE AND STORAGE
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