Petrological characterization and reactive transport simulation of a high-water-cut oil reservoir in the Southern Songliao Basin, Eastern China for CO2 sequestration
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CO2 geological sequestration (CGS) in depleted or high-water-cut oil reservoirs is a viable option for reducing anthropogenic CO2 emissions and enhancing oil recovery. The Upper Cretaceous Qingshankou Formation in the central Changling (fault) Depression, Songliao Basin, East China is the selected site for a pilot injection of the CO2 INJECTION project. The target reservoir depth is about 2400–2500 m. Lithologic features and diagenetic minerals of the reservoir and cap rocks have been investigated by optical microscopy, scanning electron microscopy (SEM), and X-ray diffraction (XRD). In the Qingshankou Formation, the reservoir rock is a typical arkose with moderately to good sorting, and very fine to fine grain sizes. Minerallogically it is dominated by quartz (19–31 vol.%), plagioclase (19–28 vol.%), and K-feldspar (2–26 vol.%). Calcite and ankerite constitute the most common diagenetic minerals. The lithology of the cap rock is mainly silty mudstone and composed of quartz (average of 12.9–27.0 wt.%), albite (14.2–35.5 wt.%), K-feldspar (1.3–2.7 wt.%), mixed-layer illite/smectite (24.9–68.8 wt.%), chlorite (3.15–14.7 wt.%) and some kaolinite. The main antigenic minerals in the CO2 INJECTION well are made up of albite (average of 29.7 wt.%), K-feldspar (average of 4.5 wt.%), calcite (average of 7.5 wt.%) and ankerite (average of 9.1 wt.%).To assess the long-term CO2 EOR-related fluid–rock interaction processes and evaluate the safety of CO2 geological storage in the Qingshankou Formation, reactive geochemical transport simulations using a simple 2D model were performed. The simulation results show that (1) the migration of free CO2 plume did not penetrate the low permeability cap rock after 800 years; (2) ankerite and dawsonite are the major sequestration minerals after CO2 injection, while albite, K-feldspar and calcite are the major dissolution minerals; (3) the sandstone permeability appears to have been reduced more significantly compared to porosity changes after CO2 injection; (4) 800 years after CO2 injection the amounts of CO2 trapped as residual free gas, dissolved gas and solid minerals are 10%, 74% and 16%, respectively; and (5) a dense carbonate crust is formed at the sandstone–mudstone boundary after CO2 injection, which can effectively retard the spread of CO2 into the cap rock. The results of our study provide basic geological information for CO2 trapping mechanisms in high-water-cut oil reservoirs, as well as a safety evaluation of CO2 geological storage resulting from massive injections of CO2 into reservoirs during EOR programs.
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