Changes in crude oil wetting of carbonate rock when treated with various surfactants was evaluated using the Washburn method by the sorption of crude oil into packed rock powders. This method served to circumvent the difficulties of direct contact angle measurements on rock-chips where the low interfacial tension between the crude oil and surfactant leads to the spreading and eventual escape of the oil droplet without being attached to the rock chip. Four surfactants were used in the study including an anionic alfa olefin sulfonate, a cationic quaternary ammonium salt, an amphoteric surfactant and a nanosurfactant. Rock powders from a carbonate rock with a mesh size between 80 and 100 were coated with the tested surfactant solutions and compacted in a sample holder for the sorption experiments. Crude oil was raised to the bottom of the powder pack and allowed to rise into the powder by capillarity. A sensitive balance was used to measure the mass of crude oil imbibing into the powder until imbibition ceased. A plot of the square of oil mass against time enabled calculation of the contact angle using the modified Washburn equation. Earlier, a sorption experiment using n-hexane was used to deduce the rock constant for the grain packing, which was necessary for calculation of the crude oil contact angle. The contact angle results demonstrated the surfactant solution's efficiency in altering the crude-oil wetting behavior. An increasing washburn contact angle through coating indicates that the carbonate rock is rendered less oil-wet, which implies better oil displacement. At ambient temperatures, the nanosurfactant gave the highest contact angle implying the least oil-wetting; in second place was the amphoteric surfactant. The anionic surfactant had little effect on oil-wetting while the cationic surfactant decreased oil-wetting to a lesser extent. At higher temperatures, the nanosurfactant maintained its superior effectiveness followed by the cationic and amphoteric surfactants. The anionic surfactant saw little change. The use of sorption to obtain contact angle of crude oil for rock surfaces treated with surfactants eliminates the difficulties associated with direct contact angle measurements for low and ultra-low surfactant solutions where attachment an oil-droplet is almost impossible. With the Washburn method rapid evaluation of surfactants ability to change rocks wettability can be made to better guide further evaluations of such processes. As the washburn method measures contact angle between solids and a liquid surrounded by air, the contact angles obtained are not to be interpreted directly as those obtained in a liquid-liquid environment.

The extreme heterogeneity of carbonate in the form of fracture corridors and super-permeability thief zones challenges the efficient sweep of oil in both secondary and tertiary recovery operations. In such reservoirs, conformance control is crucial to ensure injected water and any enhanced oil recovery (EOR) chemicals optimally contact the remaining oil with minimal throughput. Gel-based conformance control has been successfully applied on both sandstone and carbonate reservoirs. In-depth conformance control in high temperature reservoirs is still a challenge, due to severe gel syneresis and the associated significant reduction in gelation time. In this work, a laboratory study was conducted on a polymer/chromium gel system for a high-temperature carbonate reservoir to evaluate the gelant formulation potential for diversion and recovery improvement. We perform four oil displacement experiments on carbonate core samples to demonstrate oil recovery improvement by gel treatment. In these tests, the gel solution was injected into specially prepared heterogeneous carbonate composite core samples, in which different configurations of high permeability channels were created. Gel treatment was conducted after waterflooding and was followed by chase waterflooding while monitoring oil production. Oil recovery improvement by gel treatment was 18% of original oil in core (OOIC) in the composite core with high permeability channels extending midway through the composite while the improvement was 38% OOIC in the composite core with channels extending all the way through the composite. This indicates that the high permeability channels were effectively blocked and bypassed oil was successfully mobilized after gel treatment. This laboratory study provides more insight into the mechanisms of oil-recovery improvement by gel treatment. Moreover, it clearly demonstrates the oil-recovery potential of in-depth gel systems in heterogeneous reservoir applications at high temperatures.