GHGT-7 Paper ID #12 revised EVALUATION OF THE SPREAD OF ACID GAS PLUMES INJECTED IN DEEP SALINE AQUIFERS IN WESTERN CANADA AS AN ANALOGUE FOR CO2 INJECTION IN CONTINENTAL SEDIMENTARY BASINS

For the past 15 years, oil and gas producers in the Alberta basin in western Canada have increasingly turned to disposal of acid gas (H2S and CO2, with minor traces of hydrocarbons) by injection into deep geological formations. By the end of 2003, more than 4.5 Mt of acid gas, varying in composition from 2 % H2S and 95 % CO2 to 83 % H2S and 14 % CO2, have been injected at 39 locations. The acid gas is injected into deep saline aquifers at 24 sites, and into depleted oil or gas reservoirs at the remainder, at rates that vary between 1x103 and 500x103 m3/d. At in-situ conditions, the flow of the injected acid gas is driven and controlled by the hydrodynamic force due to injection and by differences in density and viscosity between the injected gas and the formation water. In a sedimentary basin extensively drilled for hydrocarbon exploration and production like the Alberta basin there are wells that penetrate the disposal aquifer in the vicinity of the injection well that can be reached by a migrating plume of acid gas. Thus, the acid-gas disposal operations in western Canada represent an analogue for CO2 storage in geological media in mature continental sedimentary basins like those in North America where oil has been discovered and produced since the 19th century and where many wells can be encountered by a plume of injected CO2. To assess the potential for upward leakage along improperly completed and/or abandoned wells, it is necessary to estimate the evolution and spread of the plume of injected acid gas and identify the existing wells within the plume’