Spontaneous countercurrent imbibition and forced displacement characteristics of low-permeability, siliceous shale rocks

Abstract

Enhanced oil production from naturally-fractured low-permeability reservoirs is challenging. Spontaneous countercurrent imbibition in such reservoirs is an important oil recovery mechanism and has been widely studied in the oil and gas industry. Nevertheless, complicated rock properties such as low permeability, wettability, and other factors controlling flow mechanisms make it difficult to understand the flow characteristics and to generalize expected recovery. Spontaneous countercurrent imbibition and forced displacement tests were completed using siliceous shale core plugs that have low permeability, relatively high porosity, and intermediate to oil-wet surfaces. Four brine formulations were examined: carbonated synthetic brine, acidic (pH of 3), neutral, and alkaline (pH of 12). The siliceous shale core used in this study is an intermediate to oil-wet rock as gauged from the oil recovery by spontaneous imbibition in the neutral pH brine. With pH-controlled synthetic brine, the final oil recovery increases; especially using high pH brine. This suggests that the wettability shifts to a condition of greater water-wetness and the residual oil saturation decreases by exposing the system to a high pH brine. In the simulation study, it is inferred that the oil recovery characteristics change by changing the capillary pressure characteristics and the interfacial tension.