Effect of Wettability on Scale-Up of Multiphase Flow From Core-Scale to Reservoir Fine-Grid Scale
Y. C. Chang, V. Mani, K. K. Mohanty, 1999. "Effect of Wettability on Scale-Up of Multiphase Flow From Core-Scale to Reservoir Fine-Grid Scale", Reservoir Characterization—Recent Advances, Richard A. Schatzinger, John F. Jordan
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Reservoir rocks modeled in typical field-scale simulation grids are inter-nally heterogeneous. The objective of this work is to study how rock wetta-bility affects the scale-up of multiphase flow properties from core-scale to fine-grid reservoir simulation scale (~10 ft × 10 ft × 5 ft; 3 m × 3 m × 1.5 m). Upscaling from fine-grid reservoir simulation scale to coarse-grid simulation scale is not addressed here. Heterogeneity is modeled as a correlated random field, parameterized in terms of its variance and two-point variogram. Variogram models of both finite (spherical) and infinite (fractal) correlation lengths are included as special cases. Local core-scale porosity, permeability, capillary pressure, relative permeability, and initial water saturation are assumed to be correlated. Water injection is simulated; effective flow properties and flow equations are calculated.
For strongly water-wet media, capillarity has a stabilizing/homogenizing effect on multiphase flow. For a permeability field with a small variance and a small correlation length, effective relative permeability can be described by capillary equilibrium models. At higher variance and moderate correlation length, the average flow can be described by a dynamic relative permeability. As the oil wettability increases, the capillary stabilizing effect decreases and deviation from this average flow increases. For fractal fields with large variance in permeability, effective relative permeability is not adequate in describing the flow.
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