Porosity Calculator
Calculate porosity from density, sonic, and neutron logs. Lithology presets for sandstone, limestone, and dolomite.
Lithology Preset
Log Readings & Matrix Parameters
DPHI = (ρma − ρb) / (ρma − ρf)
SPHI = (Δt − Δtma) / (Δtf − Δtma) × 1/Cp
φND = √((DPHI² + NPHI²) / 2)
Results
Density Porosity (DPHI)
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Sonic Porosity (SPHI)
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Neutron-Density (φND)
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Average (DPHI + SPHI)/2
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Lithology Comparison
| Lithology | ρma | Δtma | DPHI | SPHI | φND |
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How this was calculated
Density porosity: DPHI = (rhoma - rhob) / (rhoma - rhof). Based on the principle that bulk density is a linear mix of matrix and fluid densities.
Sonic porosity (Wyllie, 1956): SPHI = (dt - dtma) / (dtf - dtma) * (1/Cp). Wyllie time-average equation. Cp is the compaction correction factor (1.0 for consolidated formations).
Neutron-Density crossplot: phiND = sqrt((DPHI^2 + NPHI^2) / 2). Combines both measurements to reduce lithology effects and gas effects.
Standard matrix values: Sandstone: rhoma=2.65, dtma=55.5. Limestone: rhoma=2.71, dtma=47.5. Dolomite: rhoma=2.87, dtma=43.5.
Fluid values: Fresh water: rhof=1.0, dtf=189. Salt water: rhof=1.1, dtf=185. Oil: rhof=0.85, dtf=230.
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Book a free strategy call →Understanding Porosity from Well Logs
Porosity is the most fundamental reservoir property, representing the fraction of rock volume available to store fluids. Accurate porosity determination from well logs is critical for volumetric reserves estimation, completion design, and reservoir simulation. Multiple log-derived porosity methods exist because no single measurement is universally reliable across all lithologies and fluid types.
Density porosity uses the bulk density measurement from a gamma-gamma density tool. It is generally the most reliable porosity indicator in clean formations but requires accurate knowledge of matrix density (lithology) and fluid density. Gas in the pore space causes the density tool to overestimate porosity because gas has much lower density than liquid.
Sonic porosity (Wyllie time-average equation) uses the compressional wave travel time. It is less affected by borehole conditions than the density tool but can be influenced by fractures, vugs, and unconsolidated formations. The compaction correction factor (Cp) adjusts for under-compacted shales in young formations.
The neutron-density crossplot combination is the industry standard for porosity determination because it partially cancels lithology effects and provides a gas indicator (density-neutron separation). When DPHI and NPHI are plotted together, their crossover pattern indicates gas effect, and the RMS average provides a more robust porosity estimate.
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