Abstract Asignificant number of large CO 2 emitters are located in central Alberta, Canada, including four coal-fired power plants in the Wabamun Lake area, with cumulative annual emissions in the order of 30 million metric tons CO 2 . To help industry and regulatory agencies in selecting and permitting sites for CO 2 storage, proper characterization is essential, covering the principal aspects of CO 2 storage: capacity, injectivity, and confinement. The sedimentary succession in the Wabamun Lake area southwest of Edmonton was identified as a potential CO 2 storage site because it would minimize transportation needs and costs from the large CO 2 sources in the vicinity. A wealth of data on stratigraphy and lithology; fluid compositions; rock properties; and geothermal, geomechanical, and pressure regimes were used to create and characterize a comprehensive three-dimensional model of the deep saline aquifers in the area that could be CO 2 storage targets. These aquifers have sufficient capacity to accept and store large volumes of supercritical CO 2 at the appropriate depth and are overlain by thick confining shale units. Initial calculations and modeling of CO 2 injection into the Devonian Nisku carbonate aquifer suggest that dissolution and residual saturation of CO 2 limit the lateral CO 2 plume spread considerably. Hypothetical injection of 12.5 million tonnes/yr of CO 2 for 30 yr would result in a maximum plume spread of less than 15 km (9 mi) in diameter. However, multiple injection wells would be needed to inject this large amount of CO 2 to maintain bottomhole injection pressures below the rock-fracturing threshold.

Abstract Sedimentary basins throughout the world are thick piles of lithified sediments that, in many cases, are the hosts for fossil fuel resources. They may become even more important in the future if they are used for the storage of anthropogenic carbon dioxide. The efficiency of CO 2 geological storage is determined by the structure of the sedimentary basins, which have an intricate plumbing system defined by the location of high and low permeability strata that control the flow of fluids throughout the basin and define ‘hydrogeological’ traps. The most secure type of hydrogeological trapping is found in ‘stratigraphic’ and ‘structural’ traps in oil and gas reservoirs that have held oil and gas for millions of years. Another form of hydrogeological trapping is ‘hydrodynamic’ trapping which has been recognized in saline aquifers of sedimentary basins that have extremely slow flow rates. A volume of carbon dioxide injected into a deep hydrodynamic trap may take millions of years to travel by buoyancy forces updip to reach the surface before it leaks back into the atmosphere. Moreover, as the carbon dioxide migrates towards the surface, it dissolves in the surrounding brine (‘solubility’ trapping) and may react geochemically with rock minerals to become permanently trapped in the sedimentary basin by ‘ionic’ or ‘mineral’ trapping. The efficiency of the CO 2 geological storage in sedimentary basins depends on many factors, among the most important being CO 2 buoyancy, formation water density, lithological heterogeneity and mineralogy. A risk analysis must be completed for each site chosen for the geological storage of CO 2 to evaluate the trapping security.

Abstract Over the past decade, oil and gas producers in the Alberta basin have been faced with a growing challenge to reduce atmospheric emissions of hydrogen sulphide (H 2 S) that is produced from ‘sour’ hydrocarbon pools. Since surface desulphurization is uneconomic, increasingly operators are turning to acid-gas disposal by injection into deep geological formations. Acid gas, a mixture of hydrogen sulphide and carbon dioxide (H 2 S and CO 2 ), is the by-product of ‘sweetening’ sour hydrocarbons. Although the purpose of the acid-gas injection operations is to dispose of H 2 S, significant quantities of CO 2 are also being injected because it is uneconomical to separate the two gases. The acid-gas injection operations in the Alberta basin represent an analogue to geological sequestration of CO 2 . Large-scale injection of CO 2 into depleted oil and gas reservoirs and into deep saline aquifers is one of the most promising methods of geological sequestration of CO 2 , and in this respect it is no different from acid-gas disposal operations. However, before implementation of greenhouse-gas geological sequestration, a series of questions need to be addressed; the most important ones relate to the short- and long-term fate of the injected CO 2 . Thus, the study of the acid-gas injection operations in Alberta provides the opportunity to learn about the safety of these operations and about the fate of the injected gases, and represents a unique opportunity to investigate the feasibility of CO 2 geological sequestration.

ABSTRACT Using the technology and experience already gained by the oil and gas industry and in groundwater resource management, sequestration of carbon dioxide (CO 2 ) in geological media is an immediately applicable option for the near- to medium-term mitigation of climate-change effects resulting from the release of anthropogenic CO 2 into the atmosphere. Based on its properties and in-situ conditions, CO 2 can be sequestered as a gas, a liquid, or in supercritical state in depleted oil and gas reservoirs, uneconomic coal beds, deep saline aquifers, and salt caverns. Using CO 2 for miscible flooding of oil reservoirs or for methane production from coal beds has an added economic benefit. The main trapping mechanisms responsible for CO 2 sequestration in geological media are geological, solubility, hydrodynamic, mineral, adsorption, and cavern trapping. Basin- scale criteria for CO 2 sequestration, such as tectonic setting, hydrodynamic and geothermal regimes, hydrocarbon potential and basin maturity, and surface infrastructure, should be used in determining sedimentary basins in the world that are suitable for CO 2 sequestration in geological media. Site-specific criteria, such as particular geological media, in-situ conditions, storage capacity, injectivity and flow dynamics, and sequestration efficiency, need to be applied to identify sites, methods, and capacity for CO 2 sequestration. Continental sedimentary basins in North America, foremost in Texas and Alberta, are the prime candidates for CO 2 sequestration in geological media, followed by circum-Atlantic shelf basins. However, a series of major issues still needs to be addressed before proceeding with full-scale implementation, such as identification of specific sites and their capacities; proper characterization of the sequestration medium and of in-situ conditions; predicting and monitoring the fate of the injected CO 2 ; surface CO 2 capture, transport, and injection; performance assessment; and, finally, general public acceptance. Nevertheless, CO 2 sequestration in geological media is a very promising option for carbon management and is in the stage of development prior to application.