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Rock physics provides the link between reservoir properties and the seismic
properties that can be observed with a geophysical survey. The reservoir
parameters of importance are lithology, porosity, permeability, pore fluid
types and saturations, temperature, reservoir effective stress, and pore
fluid pressure. The related bulk properties that most impact seismic wave
propagation are bulk density, and P- and S-wave velocities.
Bulk density is the easiest to understand and quantify. Density is the
simple volumetric average of all mineral (solid) and pore fluid (solid,
liquid, and gas) phases in the rocks. Density changes during reservoir
production are primarily the result of replacing the initial set of fluids
with another set.
Seismic velocity is always related to the ratio of elastic stiffness of the
fluid-bearing rocks to the bulk density of the rocks. The elastic
stiffness depends on the mineralogy, the stiffness of the pore space, and
the stiffness (incompressibility) Kf of the mixture of pore fluids in
the rock. This is most effectively quantified with the well-known
Gassmann's equation, which relates the bulk modulus of the saturated rock
Ksat to the dry rock bulk modulus Kdry, the mineral modulus
K0, the fluid incompressibility, and the porosity :
| |
(4) |
Important issues when doing fluid substitution:
- frequency: Gassmann's relation is most appropriate for very low
frequencies as used in surface seismic. At higher frequencies as used in
laboratory ultrasonic and sonic log measurements, fluid effects can give
rise to velocity dispersion. This has to be taken into account when using
velocity-porosity regressions obtained from such high frequency data. The
amount of velocity dispersion depends on the nature of the pore space
compressibility. It is enhanced in the presence of soft crack-like pore
space, and decreases at high effective pressures when most of the
crack-like porosity in closed.
- saturations and heterogeneity: the effective elastic stiffness of
the rock depends not only on the saturation (among other things), but also
on how the saturation is distributed within the pore space. A saturation
distribution that is homogeneous and uniform at the pore scale within each
grid block will give a different velocity than a heterogeneous saturation.
The two situations require different mixing rules to estimate the effective
seismic velocity. For the present exercise, the saturation was taken to be
homogeneous within each grid block, and an effective fluid
incompressibility (calculated as the Reuss or harmonic average of the
individual fluid incompressibilities) was used in Gassmann's equation.
The fluid densities and incompressibilities used in the modeling were
obtained from
PetroTools Version 2.3, the seismic rock properties software by PetroSoft.
Next: Velocity-porosity regression
Up: Geophysics-PE: Reservoir monitoring
Previous: Memory and Timing
Stanford Exploration Project
11/12/1997