In this study, a non-destructive X-ray imaging system integrated with a core-flooding setup was used to study spontaneous imbibition in a reservoir shale sample. We performed three imbibition tests with brine, surfactant/brine, and oil and mapped the resulting pore fluid occupancy. We used a nano-CT scanner with the resolutions of 63.4 and 32.2 nm. We obtained porosity from segmented images and computed permeability in the 3D representations of the medium. To perform the first spontaneous imbibition test, small quantities of brine containing 25 wt.% was introduced to the shale sample containing oil. This was followed by the injection of brine, containing 0.1 wt.% of an anionic surfactant (ES-65A) (second imbibition). And finally we added a small amount of decalin with 7.5 wt.% iodooctane to investigate a potential imbibition by oil. At the end of each step the core sample was scanned with 63.4 nm resolution. The images were filtered, segmented, and analyzed. In order to distinguish each phase properly and improve the accuracy of the segmentation and quantification steps, the filtered results were compared with FIB/SEM images of the same shale sample. The pore fluid occupancy and pore size distribution were also characterized. We found that the sample consists of mainly interparticle pores with mixed wettability and oil-wet pores in organic matter. The spontaneous imbibition experiments showed that both oil and brine imbibe spontaneously into the large pores, while brine did not imbibe into the most of the small pores as they stayed strongly oil wet. Spontaneous imbibition of oil experiment demonstrated that about 22% of brine was trapped due to capillary trapping caused by oil imbibition. This might be one possible reason for fracturing fluid loss during oil production process from shale oil reservoirs.

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