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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Reservoir Characterization—Recent Advances
Optimum reservoir recovery and profitability result from guidance by an effective reservoir management plan. Success in developing the most appropriate reservoir management plan requires knowledge and consideration of (1) the reservoir system, including rocks, fluids, and rock-fluid interactions, as well as wellbores and associated equipment and surface facilities; (2) the technologies available to describe, analyze, and exploit the reservoir; and (3) the business environment under which the plan will be developed and implemented. Reservoir management plans de-optimize with time as technology and the business environment change or as new reservoir information becomes available. Reservoir characterization is the process of creating an interdisciplinary high-resolution geoscience model that incorporates, integrates, and reconciles various types of geological and engineering information from pore to basin scale. The reservoir data are then conceptually and quantitatively modeled and compared to the historical production data and fluid flow distribution patterns within and beyond the limits of the reservoir to match well production histories and predict their behavior. The goals of reservoir characterization are to simultaneously (1) maintain high displacement efficiency, (2) optimize high sweep efficiency, (3) provide reliable reservoir performance predictions, and (4) reduce risk and maximize profits. Notice that in addition to the technical concepts that we normally associate with "characterization," maximizing profits is an essential element of this process. Papers from the Fourth International Reservoir Characterization Technical Conference (1997), sponsored by the U.S. Department of Energy, this publication is a unique compilation of 27 papers covering every aspect of reservoir characterization and has been a popular AAPG publication since that time. Using an interdisciplinary approach, the papers address qualitative information as well as integrated quantified data and culminate in a fully integrated study.