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Oil reservoirs have hydrophobic surfaces, wherein surface-active chemical components from the oil phase deposit onto the surface of the rock matrix and render it hydrophobic. This pore-scale property drastically impacts the Darcy-scale (macro-scale) flow functions, including P c and K r, in porous media. However, quantitative measurement of CO2 in oil-wet formations via capillary trapping remains a prime challenge despite extensive lab research. This is primarily due to inconsistent existing experimental data sets in the literature. Moreover, substantial insecurities yet exist in relations of foreseeing the wettability of the CO2-rock at reservoir conditions–which are detrimental for CO2 trapping. Thus, we used the robust Nuclear Magnetic Resonance (NMR) T 1-T 2 2D Map to image the fluid configuration and measured T 2 to systematically quantify Wettability Indices (WIs) using the United States Bureau of Mines (USBM) scale in an oil-wet San Saba to predict carbon capture and storage capacity (CCS) and containment integrity. The T 1/T 2 ratio was used to measure the microscopic wettability subsequent to each flooding mechanism, and the P c-S w and K r-S w characteristic curves subsequent to drainage/imbibition cyclic water saturations were measured as well. Comparison of the results was made with analogous water-wet core results, and general consistency was found. The NMR T 2 response was also correlated to physical properties, Pore Size Distributions (PSDs), and a 12% residual CO2 trapping was measured which is significantly lower than that in an analogous water-wet sandstone. Importantly, the NMR T 2 distribution measurements demonstrated that water was displaced from small pores by CO2 flooding, whereas in the water-wet analogue rocks, capillary trapping occurs in the large pores. This work thus provides a comprehensive data set on the effect of pore-scale properties on Darcy flow functions which ultimately aid and advance industrial-scale implementation of CGS and EOR project schemes in oil-wet reservoirs.

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Stearic acid is an example of a carboxylic compound naturally present in geological formations (deep saline aquifers and depleted hydrocarbon reservoirs), which renders the rock hydrophobic (CO2-wet) over a geological time scale. Such hydrophobic surfaces are detrimental to residual CO2 trapping. There is, however, a lack of comprehensive dataset about how traces of these organic molecules affect the rock′s CO2 wettability and residual CO2 trapping. We, thus, used in situ NMR T 1–T 2 2D images to visualize fluid configurations in the pore network and used T 1/T 2 ratios to assess the microscopic wettability of the rock to pore space fluids subsequent to each process step. The T 2 relaxation time was measured to demonstrate displacement processes and evaluate the trapping behavior at the pore scale, which is closely correlated to reservoir-scale flow functions. The trapping in the CO2-wet sample (14%) was significantly lower than that of the analogous water-wet sample (18%). This reduction in CO2 trapping is due to surface macroscopic flow layers acting as conduits allowing slow desaturation of CO2. Importantly, in the CO2-wet sample, trapping predominately occurred in meso- and micropores, whereas trapping in the analogous water-wet rock primarily occurred in macropores. This work thus provides a comprehensive dataset on the impact of organic acids on residual trapping at the pore scale, which ultimately helps to advance industrial-scale implementation of CGS and EOR project schemes in carbonate reservoirs.

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