Relative permeability is one of the most important input function for reservoir modeling, production forecasting, and enhanced oil recovery calculations. The routine experimental methods to measure relative permeability are not adequate for very tight formations because of the long duration of experimental time and non-uniform saturation distribution in the core. The steady-state and unsteady-state measurements are the two common methods to measure relative permeability in conventional reservoir cores. In this paper, to measure water and oil relative permeability in unconventional core plugs from the Middle Bakken, we adopted a hybrid technique by Ramakrishnan and Cappiello (1991) which was designed to measure the non-wetting phase relative permeability in water-wet cores. Specifically, first we measured the relative permeability end-points for oil and water phases. Second, we used numerical modeling to calculate the entire relative permeability curves while honoring the measured end-point values.
Relative permeability endpoints of water and oil at residual saturations were measured in one preserved and one cleaned Middle Bakken cores to establish credibility of the method. Then, these relative permeability endpoints were used as input to a numerical model of the Buckley-Leverett equation which included capillary end effects, to determine saturation distribution in both cores. Via history matching we obtained the relative permeability curve exponents.
In this paper, we present the details of the experimental procedure and the data relevant to the Middle Bakken cores. We observed that the preserved oil-wet Bakken core imbibed the displacing synthetic brine solution which is contrary to the established wettability concept. We believe that the brine imbibition resulted from salinity contrast and chemical osmosis mass transfer across the inlet surface of the core.
Hydrocarbon reservoirs are typically saturated with two or more fluids. Several approaches are used to measure relative permeability of different fluids. These are classified under two categories: steady state (SS) and unsteady-state (USS) methods. In the steady-state method, a fixed ratio of fluids is forced through the test sample until saturation and pressure equilibria are established (Honarpour, 1986). When both the pressure drop across the core and the effluent volumetric ratios are stabilized, the saturations of the two fluids (gas-oil or oil-water) in the core are then determined by weighing the core or by performing mass-balance calculation for each phase (Dandekar, 2013). Then Darcy law is used to calculate the relative permeability data for each phase.
