Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. A pressure drop vs. flow study, using a computer program that compares flow performance at various "nodes" along the flow path.
Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. Can be calculated from reservoir properties (reservoir pressure, permeability, skin) or can be a curve fitted to experimental data from the well.
Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. The theoretical maximum flow that a well could deliver with a zero back pressure at the middle of the perforations. The glossary is a living growing list of important E&P terms and require continual enhancements. If you would like to contribute to the glossary send an email to petrowiki(at)spe.org.
Reservoir inflow performance is the reservoir pressure-rate behavior of an individual well. Mathematical models describing the flow of fluids through porous and permeable media can be developed by combining physical relationships for the conservation of mass with an equation of motion and an equation of state. This leads to the diffusivity equations, which are used in the petroleum industry to describe the flow of fluids through porous media. The diffusivity equation can be written for any geometry, but radial flow geometry is the one of most interest to the petroleum engineer dealing with single well issues. The solution for a real gas is often presented in two forms: traditional pressure-squared form and general pseudopressure form.
When considering the performance of oil wells, it is often assumed that a well's performance can be estimated by the productivity index. However, Evinger and Muskat pointed out that, for multiphase flow, a curved relationship existed between flow rate and pressure and that the straight-line productivity index did not apply to multiphase flow. The constant productivity index concept is only appropriate for oil wells producing under single-phase flow conditions, pressures above the reservoir fluid's bubblepoint pressure. For reservoir pressures less than the bubblepoint pressure, the reservoir fluid exists as two phases, vapor and liquid, and techniques other than the productivity index must be applied to predict oilwell performance. There have been numerous empirical relationships proposed to predict oilwell performance under two-phase flow conditions.