The mechanical response of the target formations during Carbon geological storage strongly depends to the fluid pore pressure alterations in the formation. The storage formations must have sufficient capacity and could avoid migration of CO2 to the surface. When the highly pressurized CO2 is injected into the geological repository the fluid pressure increases in the formation, which results in changes in stresses and deformation of the medium. From geomechanics point of view, the pressure caused by CO2o injection, should not exceed the formation strength and should not cause activation of existing faults. Therefore, finding a realistic estimation of alteration of stresses during the CO2 injection job, has been subject of several studies in the literature. Most of the analytical methods available in the literature to calculate the stress distribution are well established for single-phase flows, but it requires extension when a second fluid, in this case CO2, is also flowing. In the current work, an approximate analytical model is developed for calculating different stresses caused by injection of CO2 in a saline formation, assuming two phase flow pressure regime. Here, we investigated the stress regime under induced fluid pressure and temperature alterations during the injection time.


Carbon dioxide storage or carbon dioxide sequestration refers to the processes by which captured CO2 is securely stored in deep geologic formations. Carbon dioxide storage in geologic formations includes oil and gas reservoirs, unmineable coal seams, and deep saline reservoirs. It has been reported by The Intergovernmental Panel on Climate Change (IPCC) that the global capacity of deep saline storage sites is more than thousands of gigatons of CO2, which is hundreds of times greater than the annual CO2 emissions from industrial sources [1–3]. Therefore studying the behavior of CO2 when stored in these sites are crucial for the industry.

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