GEOLOGICAL ASPECTS OF CO2 SEQUESTRATION AND ITS RISK ASSESSMENT

Abstract

Continuous emission of carbon dioxide in the atmosphere resulted in global warming, which requires mitigation techniques such as CO2 capture and its subsequent sequestration. Geological storage of CO2 in deep subsurface formations is one of the promising sequestration techniques to control carbon concentration in our atmosphere. The geological strata suitable for CO2 storage should be permeable enough situated at a depth of 800-1000 m and must be covered with an impervious caprock. The potential geological formations for sequestering CO2 are unmineable coal seams, depleted oil and gas reservoirs, and deep saline aquifers. Amongst these, CO2 sequestration in deep saline aquifers is getting more attention in countries like India due to their widespread availability and enormous storage potential. During the course of CO2 geosequestration, the receiving saline aquifers are exposed to cyclic CO2-brine flooding. Therefore, successful implementation of CO2 sequestration in saline formations requires a thorough investigation of interactions of CO2 with the receiving rock formation and brine. The focus of this study is to understand the multiple-phase flow behavior of CO2 taking place during its sequestration in saline formations under in-situ reservoir conditions using a series of practical experiments and numerical modeling. Risk assessment related to the geological sequestration of CO2 under varying injection rates and pressure is an additional focus of this study. The suitable saline deep aquifers for the sequestration of CO2 are mostly comprised of sandstones, shales, and carbonates. Planning of CO2 geosequestration in these formations requires an assessment of CO2 behavior under high salinity and pressure conditions as these factors play a major role in retaining injected CO2 in different trapping forms. Thus, in this research work, practical experiments along with numerical modeling are conducted to investigate the migration of CO2 through carbonates under in-situ reservoir pressure and salinity levels. The practical experiments are performed using core flooding apparatus on two different cores of carbonates, which are quite reactive and have complex pore structures as compared with other saline formations. Risk assessment is performed for saline carbonates and compared with the other formations. The flooding experiments were conducted using Edward White and Edward Yellow cores of carbonate formation to estimate the effect of salinity and injection pressure on CO2 sequestration along with the influence of cyclic brine-CO2 flooding on properties of the selected rock. These experiments were performed considering 3% and 7.5% level of salinity under two different injection pressures of 8 and 10 MPa for evaluating the effects of these hydro-geological parameters on multiphase flow behavior and sequestration capacity of the carbonate formations. i For this, brine and supercritical CO2 (scCO2) were injected through the carbonate cores to obtain the changes in pressure drop across the cores with time. The results show that under high salinity conditions, the pressure drop in Edward white and yellow carbonate cores were 2 MPa and 0.3 MPa respectively, while in the case of low salinity, 1.5 and 0.2 MPa of pressure drop was observed in the selected cores. A high pressure drop within the core, termed as differential pressure (DP), was observed using 10 MPa injection pressure, while a low DP trend was recorded for the 8 MPa of injection pressure. An increment in DP across the cores with consecutive injection cycles of brine and CO2 clearly indicates pores clogging due to the reactive nature of the selected carbonate samples. The changes are also attributed to hysteresis effect, formation changes, migration of fines, and acidic chemical reactions between carbonates and brine/CO2. During the core flooding experiments, the pre- and post-flooded carbonate cores were analyzed to understand the role of geochemical reactions and subsequent alteration in petrophysical properties of the used carbonates due to CO2-brine-rock interactions. These changes occurred during geochemical interactions were observed using advance image analysis techniques such as X-ray diffraction (XRD), Field emission scanning electron microscope (FeSEM), Transmission electron microscope (TEM) and Energy dispersive X-ray (EDX). Comparison of both pre- and post-flooded carbonate cores report the clear changes occurred in the formation rock during the course of flooding. A decreasing trend observed in both the parameters at the end of cyclic CO2 brine flooding was likely due to the dissolution and precipitation of carbonate minerals. The obtained XRD images before and after the flooding show a slight variation in characteristic peaks in diffractograms. The FESEM images show the dissolution and precipitation of the carbonate minerals after the flooding experiments. The EDX provides the quantitative information about mineral compositions of the carbonate cores and fortifies dissolution and precipitation processes occurring during the flooding. Furthermore, TEM images provide pore size variation, which was found to increase at the end of the flooding experiments confirming dissolution of minerals. The observed rings in the selected area diffraction pattern (SAED) of TEM images of both the cores indicate crystalline nature of formation materials. These results provide a better understanding of alterations in petrophysical properties of receiving formations expected during the geosequestration of CO2 in filed. A numerical framework is also developed for finding out the effect of injection pressure and flux rate on CO2 sequestration and its subsequent movement towards the caprock through the saline aquifers. The characteristic deep saline formations having dimensions of 200×100 m2 is considered here for CO2 injection in supercritical form. The study domain represents a typical deep saline aquifer at a depth of 800-1000 m for observing the migration of CO2 under in-situ ii reservoir conditions. The impact of injection pressure on the movement of CO2 is observed in the selected domain for 8, 10, and 15 MPa along with its distribution with time. Likewise, two continuous injection fluxes of 40 and 100 mol/(m2s) of CO2 are considered to see their impacts on pressure distribution within the receiving reservoir. The scCO2 was allowed to inject at the bottom of the study domains, which formed a separate immiscible phase pool. The less-dense CO2 moves upward due to buoyancy force and pressure gradient before accumulating beneath the caprock of the considered subsurface formation. The multiphase flow of CO2 from its pure phase pool is simulated using a mass conservation equation and solute transport in porous media, which is solved numerically using the COMSOL simulator. The results show that CO2 distribution due to diffusion and dispersion is more when injected with pressure 8-10 MPa as compared to high injection pressure of 15 MPa. A high concentration of CO2 is observed at two different observation points when it was injected with flux rate of 100 mol/(m2s). The injected CO2 moving quickly in upward direction beneath the caprock emphasizes structural trapping as the dominant mechanism in permeable formations like carbonates. However, the migration front of CO2 leaves behind a trail of residual and dissolved CO2 asserting simultaneous dissolution and residual trapping in the considered domain. Intermittent release patterns may be adopted for increasing the dissolved CO2 using more than one release locations. Possible risks due to CO2 leakage, specifically associated with formation fracturing is finally evaluated using a series of simulation runs. Roles of CO2 injection at different flow rates were considered for analyzing its temporal evolution in saline formations. The theory of double effective stress is used here for calculating the formation rock fracture pressure. The one dimensional diffusivity equation is solved numerically for obtaining the pressure profile within the study domain. The fracture pressure and pressure profile are calculated for different flow rates of 20, 28, 32, 36 and 40 kg/s for the carbonates formation. With an increase in flow rate, the simulation results show that the injected CO2 enhances the formation pressure first abruptly and then gradually with time of progression. The pressure of the formation is simulated in order to estimate the time of fracturing. The injection of CO2 is recommended to stop once the formation pressure reaches near to the calculated fracture pressure to avoid any leakage of CO2 from the storage zone. The findings of this research work can be utilized for implementing CO2 geo-sequestration projects into saline aquifers.