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Abstract: The use of CO2 as a working fluid in place of formation brines in Enhanced Geothermal Systems (EGS) could allow, in addition to CO2 sequestration, a more efficient recovery of reservoir heat for any given pressure gradient between injection and production wells. We simulate an idealized low-salinity brine-filled reservoir in which we inject CO2. We produce heat from the extracted fluid that is at first just brine, later brine + CO2, and finally CO2 only. As the CO2 plume develops the aquifer dries out, precipitating salt and inducing clogging of the fractures in proximity to the production well. To mitigate this effect, we have simulated combined brine and CO2 injection that, at specific mass fractions, doubles the life of the well but limits the rate of heat extraction. The total heat extracted over the life of the well is 40% larger than in the dry CO2 case. Simulation of more realistic geologic settings with involvement of chemical reactions would be necessary to evaluate the feasibility of CO2-EGS in any particular geothermal system. [Copyright &y& Elsevier]

Abstract: We present recent results of coupled non-isothermal, fluid flow and geomechanical modeling associated with the In Salah CO2 storage operation at the Krechba gas field, Algeria. Much recent modeling efforts have been dedicated to analyze satellite based measurements of ground surface uplift at one of the injection wells where a double-lobe uplift pattern has been observed. Both semi-analytical inverse deformation analyses and coupled numerical modeling have indicated that the observed double-lobe uplift pattern can be explained by injection-induced deformation in a deep vertical fracture zone or fault intersecting the injection well and extending a few hundred meters above the injection zone (up to a depth below 1600 m). Recently, a 3D seismic survey indicated that such a fault or fracture zone may indeed intersect the well with the orientation originally predicted by the semi-analytical inverse deformation analysis. A coupled numerical analysis indicates that observed progressive uplift during active CO2 injection and relatively slower subsidence rate during a subsequent shut-in period could be modeled as an elastic response, i.e. indicating elastic deformation of an existing geological feature rather than the creation of a new hydraulic fracture. Finally, we analyzed the simulation results in terms of reservoir stress evolution and the potential for injection-induced micro-seismicity at Krechba. Our analysis shows that the highest potential for injection-induced micro-seismicity occurs along the horizontal injection wells caused by the combined effects of injection-induced cooling and pressure. However, for the best-estimated present-day strike-slip stress regime at Krechba, our analysis indicates a relatively low potential for injection-induced micro-seismicity. [Copyright &y& Elsevier]