Reservoir simulation of variable bubblepoint processes such as water or gas injection into black oil reservoirs often requires extrapolation of reservoir fluid properties to pressures above original bubblepoint pressure. This has been known for over twenty years; however, to date, no rational and consistent procedure for these extrapolations has been proposed.
We propose a scheme to extrapolate solution gas-oil ratios and the corresponding oil formation volume factors, oil viscosities, and oil densities, which preserves the correct relationship of these properties to pressure. The procedure is based on empirical observation that the relationship between solution gas-oil ratio and oil formation volume factor is linear and that oil viscosity and oil density have a linear relationship in the pressure range of interest. A material balance equation is used to connect the quantities and properties of the surface fluids, oil formation volume factor, and solution gas-oil ratio to the density of the reservoir oil. Thus, the four properties can be extrapolated together in an empirically and theoretically based process.
A similar scheme is used to extrapolate the properties of the solution gas, forcing the correct shapes of gas z-factor, gas formation volume factor, and gas density as functions of pressure. Gas viscosity, as usual, is calculated with a correlation.
After extrapolation, the consistencies of these oil and gas properties are checked by ensuring that total compressibility remains positive throughout the range of extrapolated pressure. Thus, a rational procedure based on known empirical and theoretical relationships among these fluid properties is now available for use in preparing fluid properties for reservoir simulation when the possibility of variable bubblepoints exists.
The application of these relationships to quickly extrapolate values of these seven fluid properties is demonstrated using an interactive graphical spreadsheet.
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