@wikipedia
Synonym: Pore Compressibility = CPHI
A measure of formation porosity change due to reservoir pressure variation:
c_\phi = \frac{1}{\phi} \frac{\partial \phi}{\partial p} |
There is a statistical correlation between initial formation compressibility and formation porosity which can be picked by various compressibility-porosity models.
Pore compressibility stays constant for small pressure variations but in a wide range of pressure variations the dependence on ambient pressure can not be neglected and should be tabulated from laboratory core tests or estimated from compressibility-pressure correlations.
The typical values are:
cϕ = 0.5 ÷ 1.5 GPa-1
but may go higher for poorly consolidated rocks.
In many practical cases the pore compressibility can be considered as poorly dependent on reservoir pressure variation: .
In this case porosity dependence on reservoir pressure can be simulated as:
\phi(p) = \phi_i \cdot \left[ 1 + c_\phi \, (p-p_i) + 0.5 \, c^2_\phi \, (p-p_i)^2 \right] |
But in case the reservoir pressure is changing substantially one may need to account for the effect it takes on pore compressibility (see Pore compressibility @model) and then reservoir pressure - porosity model is going to take the following form:
\phi(p) = \phi_i \cdot \exp \left[ \int_{p_i}^p c_\phi\, dp \right] |
Petroleum Industry / Upstream / Subsurface E&P Disciplines / Petrophysics / Geomechanical Rock Modelling
[Compressibility][ initial pore compressibility ]
[ Pore compressibility @model ]