Oil well performance is measured by the assessment of its Inflow Performance & Outflow Performance Relationships (IPR & OPR).
Since 1968, Vogel equation has been used extensively for analyzing the IPR of flowing oil wells under solution gas drive. However, the Vogel curve was originally developed for vertical wells and may not be applicable to horizontal wells due to the fact that the flow into a horizontal well, with overlying gas cap, is different than flow into a vertical well. In addition, current used inflow performance relationship models for horizontal wells are impractical in nature, mainly developed for homogeneous reservoirs, and not suitable for multi-layered systems with different permeability. Thus, there is a need for new practical IPR model that considers the effects of reservoir heterogeneity on IPR curves for horizontal wells producing from two-phase reservoirs overlaid by gas cap.
This study investigates the effects of reservoir heterogeneity on IPR curves for horizontal wells drilled in heterogeneous reservoirs. To achieve the desired objective, commercial simulator Eclipse, is utilized to develop IPR's for horizontal wells producing from solution gas drive reservoirs. Firstly, a simulation model is developed where a base case is considered with typical rock, fluid and reservoir properties using black oil model. Dimensionless IPR curves are generated by obtaining a set of points relating flowing bottom-hole pressures to oil production rates. The effects of several reservoir and fluid properties such as bubblepoint pressure, oil gravity, residual oil saturation, critical gas saturation, initial water saturation, porosity and absolute permeabilities on the calculated curves are investigated. Reservoir heterogeneity is included in the simulation model by introducing the concept of semi-variogram function. Finally, an attempt is made to converge the results into one simple model in order to get a new empirical IPR correlation for horizontal wells producing from heterogeneous solution gas drive reservoirs suitable for systems with different reservoir permeability. The new empirical IPR model was then compared to the published correlations and found to have a small and acceptable average absolute error of less than 2%.
