Porosity from Density Log

Calculate formation porosity from bulk density (RHOB) measurements using the classic density-porosity relationship. Essential for petrophysical evaluation and reservoir characterization using wireline density logs.

Petrophysics Density Log Porosity Wireline

Input Parameters

Measured Density

g/cm³
From density log measurement

Matrix Density

g/cm³
Pure mineral grain density

Fluid Density

g/cm³
Pore fluid density

Results

Theory & References

Density-Porosity Equation

φ = (ρma - ρb) / (ρma - ρfl)

Where:

  • φ = porosity (fraction)
  • ρb = bulk density from log (g/cm³)
  • ρma = matrix (grain) density (g/cm³)
  • ρfl = pore fluid density (g/cm³)

Physical Basis:

The bulk density measured by the density log is a volumetric average of the matrix and fluid densities weighted by their respective volumes. Lower bulk density indicates higher porosity.

Typical Matrix Densities

  • Sandstone (Quartz): 2.65 g/cm³
  • Limestone (Calcite): 2.71 g/cm³
  • Dolomite: 2.87 g/cm³
  • Anhydrite: 2.98 g/cm³
  • Salt (Halite): 2.16 g/cm³
  • Coal: 1.30-1.80 g/cm³

Important Considerations:

  • Mixed lithology requires weighted average matrix density
  • Heavy minerals (pyrite, siderite) increase matrix density
  • Clay content affects apparent porosity
  • Gas zones may show unrealistically high porosity

Applications & Limitations

Best Applications:

  • Clean sandstone and carbonate reservoirs
  • Water-saturated or oil-saturated zones
  • Quality control for other porosity logs
  • Lithology identification when combined with neutron log

Limitations:

  • Gas effect: Low gas density causes porosity overestimation
  • Shale/clay: Bound water increases apparent porosity
  • Caverns/vugs: Measured density may not represent matrix
  • Invasion: Mud filtrate alters fluid density near borehole