Rock Compressibility Calculator
Calculate formation (pore volume) compressibility using Hall and Newman correlations based on porosity and lithology type.
Input Parameters
Hall (1953): cf = f(porosity); Newman (1973): lithology-specific correlations
Hall cf
--
1/psi × 106
Newman cf
--
1/psi × 106
Average cf
--
1/psi × 106
Typical Range
3 - 10 × 10-6 1/psi for consolidated sandstone
Compressibility vs Porosity
How this was calculated
Hall (1953): cf = 1.782 / phi^0.438 (in microsips, i.e., 10^-6 1/psi). General correlation for consolidated rocks.
Newman (1973) - Sandstone: cf = a / (1 + c*phi)^b, with lithology-specific constants.
Newman (1973) - Limestone: Different constants for carbonate rocks, generally lower compressibility.
Note: Formation compressibility decreases with increasing porosity for consolidated rocks. Unconsolidated sands have much higher compressibility.
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Book a free strategy call →Understanding Rock Compressibility
Rock (formation) compressibility, also called pore volume compressibility (cf), quantifies how much the pore volume of a rock changes per unit change in pressure. It is a critical parameter in material balance calculations and reservoir simulation, particularly for undersaturated oil reservoirs where rock and fluid expansion are the primary drive mechanisms above the bubble point.
Hall (1953) published one of the earliest correlations relating formation compressibility to porosity, showing an inverse relationship: lower porosity rocks tend to have higher compressibility per unit pore volume. Newman (1973) expanded this work with lithology-specific correlations for sandstone, limestone, and unconsolidated sands. Typical values range from 3-10 microsips for consolidated sandstone and can exceed 50 microsips for unconsolidated formations. This calculator implements both correlations. All calculations run in your browser. Built by Groundwork Analytics.