A numerical feasibility study of CO2 foam for carbon utilization and storage in a depleted, high salinity, carbonate oil reservoir.

Carbon Capture, Utilization, and Storage (CCUS) offers a viable solution to reduce the carbon footprint in the petroleum industry, and foam injection presents a promising method to achieve this while simultaneously increasing oil recovery. In this work, we studied the feasibility of CO2 foam for co-optimizing enhanced oil recovery and CO2 storage in a high-salinity carbonate formation. The simulated hydrodynamic model is a depleted formation containing 30% residual oil, with three mechanisms for CO2 storage: solubility, residual, and mineralization trapping mechanisms. The results showed that after 20 years, oil recovery during foam injection was 2.7 times higher than CO2 injection, and the CO2 stored during foam flooding was 38% higher than CO2 injection. Notably, foam injection also increased CO2 storage capacity by 2.6 times, indicating the potential to store around 2 gigatons of CO2 in the simulated model. This was attributed to the ability of foam to significantly reduce gas mobility and thus form isolated bubbles through its Jamin effect. Residual trapping was the dominant trapping mechanism, contributing to over 70% of the total CO2 trapped, attributed to the reduction in the dissolution of CO2 in brine due to the high salinity of the aqueous medium. CO2 mineralization was also studied, showing the least trapping efficiency and the dissolution trend of all the carbonate minerals. This study illustrates a novel CO2 utilization and storage technique in which CO2 is concurrently sequestered while enhancing oil recovery in a depleted oil reservoir by injecting CO2 as foam. The relevance of this study lies in its potential to provide a dual benefit of reducing greenhouse gas emissions and boosting oil production, offering a sustainable approach for the petroleum industry.

Coreflooding data on nine sandstone cores to measure CO2 residual trapping.

This data article provides detailed explanation and data on CO2/water coreflooding experiments performed on nine sandstone rock cores. Refer to the research article "Predicting CO2 Residual Trapping Ability Based on Experimental Petrophysical Properties for Different Sandstone Types" [1] for data interpretation. The reader can expect to find experimental conditions including temperature, pressure, fluid pair types, as well as flow rates. Furthermore, the raw CT images and the processed three-dimensional (3D) voxel-level porosity, permeability, and CO2 saturation maps for each of the nine sandstone samples are also supplied.

Carbon dioxide/brine wettability of porous sandstone versus solid quartz: An experimental and theoretical investigation.

HYPOTHESIS: Wettability plays an important role in underground geological storage of carbon dioxide because the fluid flow and distribution mechanism within porous media is controlled by this phenomenon. CO2 pressure, temperature, brine composition, and mineral type have significant effects on wettability. Despite past research on this subject, the factors that control the wettability variation for CO2/water/minerals, particularly the effects of pores in the porous substrate on the contact angle at different pressures, temperatures, and salinities, as well as the physical processes involved are not fully understood. EXPERIMENTS: We measured the contact angle of deionised water and brine/CO2/porous sandstone samples at different pressures, temperatures, and salinities. Then, we compared the results with those of pure quartz. Finally, we developed a physical model to explain the observed phenomena. FINDINGS: The measured contact angle of sandstone was systematically greater than that of pure quartz because of the pores present in sandstone. Moreover, the effect of pressure and temperature on the contact angle of sandstone was similar to that of pure quartz. The results showed that the contact angle increases with increase in temperature and pressure and decreases with increase in salinity.

Residual trapping of supercritical CO2 in oil-wet sandstone.

Residual trapping, a key CO2 geo-storage mechanism during the first decades of a sequestration project, immobilizes micrometre sized CO2 bubbles in the pore network of the rock. This mechanism has been proven to work in clean sandstones and carbonates; however, this mechanism has not been proven for the economically most important storage sites into which CO2 will be initially injected at industrial scale, namely oil reservoirs. The key difference is that oil reservoirs are typically oil-wet or intermediate-wet, and it is clear that associated pore-scale capillary forces are different. And this difference in capillary forces clearly reduces the capillary trapping capacity (residual trapping) as we demonstrate here. For an oil-wet rock (water contact angle θ=130°) residual CO2 saturation SCO2,r (≈8%) was approximately halved when compared to a strongly water-wet rock (θ=0°; SCO2,r≈15%). Consequently, residual trapping is less efficient in oil-wet reservoirs.

Influence of temperature and pressure on quartz-water-CO2 contact angle and CO2-water interfacial tension.

We measured water-CO2 contact angles on a smooth quartz surface (RMS surface roughness ∼40 nm) as a function of pressure and temperature. The advancing water contact angle θ was 0° at 0.1 MPa CO2 pressure and all temperatures tested (296-343 K); θ increased significantly with increasing pressure and temperature (θ=35° at 296 K and θ=56° at 343 K at 20 MPa). A larger θ implies less structural and residual trapping and thus lower CO2 storage capacities at higher pressures and temperatures. Furthermore we did not identify any significant influence of CO2-water equilibration on θ. Moreover, we measured the CO2-water interfacial tension γ and found that γ strongly decreased with increasing pressure up to ∼10 MPa, and then decreased with a smaller slope with further increasing pressure. γ also increased with increasing temperature.