Category: Production From Two-Phase Reservoirs

Vogel’s correlation, normalizing qo by qo,max, is frequently not in close accordance with field data. Fetkovich (1973) suggested a normalization with , and in a flow equation of the form the relationship becomes Equation (3-63) requires the determination of two unknowns, the absolute open flow potential, qo,max, and the exponent n. Both of them are characteristic of a specific well and… Continue reading Fetkovich’s Approximation

If the reservoir pressure is above the bubble point and yet the flowing bottomhole pressure is below, a generalized inflow performance can be written. The following approach enables generation of an IPR that has a straight portion for pwf ≥ pb, and follows the Vogel equation for pwf < pb adapted to the straightforward logic found in Standing (1971). This can be… Continue reading Generalized Vogel Inflow Performance

Vogel (1968) introduced an empirical relationship for qo based on a number of history-matching simulations. The relationship, normalized for the absolute open flow potential, qo,max is where, for pseudosteady state, where ko is the effective permeability to oil that might be estimated from a pressure buildup test. Therefore, The convenience of the Vogel correlation is that it allows the use of… Continue reading Oil Inflow Performance for a Two-Phase Reservoir

Although a rigorous treatment of two-phase flow in a reservoir is outside the scope. It is necessary to understand the impact of competing phases on the flow of a fluid through the porous medium. If there are two or three fluids flowing at the same time in a porous medium, the absolute reservoir permeability, k, is… Continue reading Two-Phase Flow in a Reservoir

When water is produced, the liquid flow properties are generally taken to be averages of the oil and water properties. If there is no slip between the oil and water phases, the liquid density is the volume fraction-weighted average of the oil and water densities. The volume fraction-weighted averages will be used to estimate liquid… Continue reading Accounting for the Presence of Water

Oil viscosity can be estimated with the correlations of Beggs and Robinson (1975) and Vasquez and Beggs (1980). The “dead” oil viscosity is where The oil viscosity at any other pressure below the bubble point is where If the stock tank oil viscosity is known, this value can be used for μod. For pressures above the… Continue reading Oil Viscosity

This subsection presents the most widely used property correlations for two-phase oilfield hydrocarbon systems. The downhole volumetric flow rate of oil is related to the surface rate through the formation volume factor, Bo: Here ql is the actual liquid flow rate at some location in the well or reservoir. The downhole gas rate depends on the solution gas–oil… Continue reading Property Correlations for Two-Phase Systems

General Properties of Saturated Oil The bubble-point pressure is the important variable in characterizing saturated oil. At pressures above the bubble point, oil behaves like a liquid; below the bubble point, gas comes out of solution, becoming free gas coexisting with oil. The formation volume factor, Bo, measured in res bbl/STB, for oil above the bubble-point… Continue reading Properties of Saturated Oil

The performance relationships presented were for single-phase oil wells and, while gas may come out of solution after oil enters the wellbore, the use of those relationships does not consider free gas to be present in the reservoir. Expansion of oil itself as a means of recovery is a highly inefficient mechanism because of the oil’s… Continue reading Introduction