Advances in Understanding the Wettability of the Viking Formation

Abstract

Abstract This paper presents a comprehensive laboratory protocol to evaluate and characterize the in-situ rock and fluid samples from the Viking Formation in the Western Canadian Sedimentary Basin (WCSB). The experiments are performed in four stages. In stage 1, we conduct Scanning Electron Microscopy (SEM), Energy-dispersive X-ray Spectroscopy (EDS) and X-ray Diffraction (XRD) techniques on the dry end-pieces of the plugs for pore-scale visualization and compositional analysis. In stage 2, we measure the contact angle (CA) of the equilibrated oil and brine droplets on the surface of the rock samples in the presence of air, and that of the equilibrated oil droplets on oil-saturated rock samples immersed in brine and DIW (deionized water). In stage 3, we perform co-current spontaneous imbibition experiments on a set of twin plugs to compare the rate of brine and oil uptake by capillary suction. In stage 4, we conduct counter-current imbibition experiments on oil-saturated plugs to evaluate oil recovery by DIW and brine. Co-current spontaneous imbibition results show excess brine uptake compared with oil during the early times (first 120 hours). The XRD results show the presence of 11.66 wt. % pore-filling clay minerals (10 wt.% kaolinite and 1.66 wt. % illite) in the selected rock samples. These clay minerals are dispersed in the pore structure of the selected rock samples, as observed in the SEM images taken from these samples. Therefore, it can be concluded that water adsorption by pore-filling clay minerals is the main reason for the excess brine uptake compared with oil at the early times. Although brine imbibes faster and more than oil at the early times, the final imbibed volume of oil is higher than brine, which indicates the presence of small hydrophobic pores with more affinity towards oil than brine. The CA of the equilibrated oil droplet on the surface of the oil-saturated reservoir rock immersed in brine is 114.0°, while that in DIW is 70.43°, indicating that DIW enhances the water-wetness of the reservoir rock by 43.6°. The results of the counter-current imbibition experiments on the oil-saturated plugs show that oil recovery by DIW is 33% of the initial oil volume in the plug, which is 5% more oil than that by the reservoir brine, primarily due to more significant osmotic potential.