Application of Lévy Random Fractal Simulation Techniques in Modeling Reservoir Mechanisms in the Kuparuk River Field, North Slope, Alaska

Abstract

Summary Incorporating a suitable level of heterogeneity into reservoir simulations is necessary for accurate prediction of production rates and final recoveries. Spatial correlation of petrophysical properties, particularly permeability extrema, exerts a profound influence on flow underlying reservoir displacement and depletion processes. Common modeling techniques are founded on Gaussian assumptions for statistical distributions. Such Gaussian-based approaches can inadequately model the permeability extrema that can dominate reservoir performance. However, optimal reservoir management strategies at the Kuparuk River Field require that significant efforts be made to correctly model reservoir behavior. This study utilizes a new method, Lévy fractal simulation, for interpolating permeability at a former gas injection area now being targeted for oil production. The main producing interval is a diagenetically and mineralogically complex clastic unit. The diagenetic complexity causes difficulties in the lateral modeling of large changes in petrophysical properties observed in near-vertical wells, particularly permeability. Prior efforts at modeling the movement of gas, at typical interwell scales, have met with limited success. In this study, the Lévy technique employs automatic calibration with log and core data for the interwell interpolation of the spatially complex reservoir properties. The Lévy fractal simulations preserve the sharp jumps in reservoir properties observed at stratigraphic boundaries and within reservoir subzones. The spatially correlated petrophysical properties are consistent with geologic experience. A fine-scale permeability model incorporating well conditioning data was built using the Lévy fractal interpolation technique. This model encompassed not only the gas injection area but drillsite patterns immediately adjacent. The model preserves the geometry of the reservoir units so that truncation and onlap relationships are preserved. The permeability extrema in the model are characterized by lateral continuities extending over many grid-blocks away from control locations. Porosity was modeled using sequential Gaussian simulation in which well porosity logs were used as the primary conditioning data, and the modeled permeability used as secondary conditioning data. The fine-scale model was then used as input in an upscaled dynamic simulator built to test reservoir mechanisms. The model was also useful for prognosing porosity and permeability at proposed well locations. Early drilling results indicate that substantial quantities of producible oil remain in the former gas injection area.