Abstract

Pore fluids strongly influence the seismic properties of rocks. The densities, bulk moduli, velocities, and viscosities of common pore fluids are usually oversimplified in geophysics. We use a combination of thermodynamic relationships, empirical trends, and new and published data to examine the effects of pressure, temperature, and composition on these important seismic properties of hydrocarbon gases and oils and of brines. Estimates of in-situ conditions and pore fluid composition yield more accurate values of these fluid properties than are typically assumed. Simplified expressions are developed to facilitate the use of realistic fluid properties in rock models.Pore fluids have properties that vary substantially, but systematically, with composition, pressure, and temperature. Gas and oil density and modulus, as well as oil viscosity, increase with molecular weight and pressure, and decrease with temperature. Gas viscosity has a similar behavior, except at higher temperatures and lower pressures, where the viscosity will increase slightly with increasing temperature. Large amounts of gas can go into solution in lighter oils and substantially lower the modulus and viscosity. Brine modulus, density, and viscosities increase with increasing salt content and pressure. Brine is peculiar because the modulus reaches a maximum at a temperature from 40 to 80 degrees C. Far less gas can be absorbed by brines than by light oils. As a result, gas in solution in oils can drive their modulus so far below that of brines that seismic reflection bright spots may develop from the interface between oil saturated and brine saturated rocks.

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