Formation wettability is a critical parameter when designing enhanced oil recovery (EOR) for field applications both in conventional and unconventional reservoirs. In this study, we focused on one unconventional resource only—the Bakken. Specifically, we conducted laboratory experiments in five clean Middle Bakken cores having different initial fluid saturations to determine (1) where the fluids reside within the pores, and (2) the effect of aging on wettability change.
The experimental protocol included measuring porosity and permeability of five clean Middle Bakken cores. We saturated three cores with Bakken oil only, aged the cores at 180°F and 2,500 psi pressure for four weeks, and stored them in crude oil for one year at ambient laboratory conditions. Next, we used synthetic brine to produce oil from the aged cores by spontaneous imbibition in Amott cell; then, we produced additional oil with high-speed centrifuge.
For the remaining two cores, we saturated them with synthetic brine, displaced the brine with crude oil using centrifuge, and stored the cores in crude oil at ambient laboratory conditions for four months; then, we measured oil production from the cores by imbibition in Amott cell. For all the cores, we conducted NMR measurements after each fluid saturation/desaturation experiment to determine the effect of aging time and temperature on the core wettability and fluid distribution in the pores.
The experimental results indicated that Bakken crude, in absence of formation brine, did not alter the wettability of cores to oil-wet. NMR measurements indicated that brine resides in smaller pores and as a brine film on grains regardless of aging time, and the core fluids redistributed with time indicating a strong rock-fluid interaction. Finally, the analysis of oil production indicated the preponderance of chemical osmosis over imbibition as the mechanism of oil displacement.