petrophysics · porosity
Effective Porosity
φe = φt − (Vcl × φclay)
click formula to derive ↑
Inputs
fraction
fraction
fraction
Description
Effective porosity subtracts the clay-bound water volume from total porosity to yield the pore space available to moveable formation fluids. It is the porosity value used in the Archie Sw equation (with effective-porosity Archie constants) and in net pay calculations that are based on producible fluid volumes.
Variables
| Symbol | Unit | Description |
|---|---|---|
| φe | fraction | Effective Porosity |
| φt | fraction | Total porosity including clay-bound water pore space, from neutron-density crossplot or NMR. This is the starting point before removing the clay-water volume. |
| Vcl | fraction | Volume fraction of clay from GR or spectral log. Drives the clay-bound water correction. |
| φclay | fraction | Porosity (water content) of the pure shale end-member — typically 0.30–0.40 for smectite (Gulf Coast Tertiary), 0.05–0.15 for illite (older rocks). Read from the density log at the shale baseline. |
Assumptions
- Clay-bound water content scales linearly with Vcl — true for dispersed clay but less accurate for laminated shale-sand
- φclay is uniform across the interval and representative of the clay mineralogy in the pay zone
Limitations
- φe can be negative in highly shaly intervals where Vcl × φclay > φt — clamp to zero; the zone is non-pay
- Not appropriate for laminated shale-sand where effective porosity in the sand laminae should be computed directly from the sand layer density, not from a whole-rock shale correction
Use Cases
- → Archie Sw in shaly sands (effective porosity system): Use φe as the porosity input to sw_archie when working in the effective porosity framework — Archie constants (a, m, n) must also be calibrated to effective porosity.
- → Net pay cutoff application: Apply φe ≥ 0.06 fraction as a net-pay porosity cutoff alongside Vcl ≤ 0.30 and Sw ≤ 0.65 to flag the producible reservoir interval.
- → NMR CBW validation: Compare Vcl×φclay (log-based CBW estimate) against the NMR clay-bound water volume (BVI measured at 3 ms T2 cutoff); large discrepancies indicate φclay calibration error.
Related Calculations
Region Notes
Permian Basin
Wolfcamp/Spraberry: φclay ≈ 0.25–0.35 typical for illite-smectite mix; CBW correction reduces φt by 3–6 pu in productive benches with Vcl 0.15–0.25.
Gulf of Mexico
Young smectite-rich shales: φclay ≈ 0.35–0.45; the clay-bound water correction is large and must be validated against NMR where available, especially at depths < 3000 m TVD.
Haynesville
Mature gas shale: φclay 0.10–0.20 (illite-dominated after diagenetic conversion from smectite); φe is often only 2–5% despite total porosity of 8–12%.
Eagle Ford
Mixed carbonate-clay matrix: φclay ≈ 0.15–0.25 for the clay component; however kerogen occupies pore space not accounted for by this formula — use TOC-corrected total porosity as input.
Global
Always validate φclay against an independent NMR CBW or core mercury injection measurement before applying across a field; the choice of φclay can shift φe by 3–6 pu for typical Vcl values.
References
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