Calculate void space ratio and fluid flow capacity for rocks, soils, and porous materials using fundamental principles of geology and petroleum engineering.
Last updated: March 2026
φ = (Vᵥ / Vₜ) × 100
k = (Q·μ·L) / (A·ΔP)
Porosity is the percentage of a rock or soil's total volume that consists of void space (pores, fractures, and cavities). It quantifies how much fluid—whether water, oil, or gas—a porous material can store. Porosity is expressed as a percentage, ranging from near 0% in dense granite to over 50% in unconsolidated sediments. High porosity alone doesn't guarantee good fluid flow; the pores must be interconnected.
Permeability measures a porous material's ability to transmit fluids through its interconnected pore network. It's governed by Darcy's Law, which relates flow rate to pressure gradient, fluid viscosity, and the material's intrinsic permeability. Permeability is measured in darcys (D) or millidarcys (mD), where 1 darcy represents relatively high permeability. A sandstone might have 100-1000 mD, while tight shales may be below 0.001 mD.
These two properties are fundamental to petroleum engineering, groundwater hydrology, soil science, and civil engineering. A material can have high porosity but low permeability if pores are isolated (like pumice) or extremely small (like clay). Conversely, fractured rocks may have low porosity but high permeability through connected fracture networks. Understanding both properties is essential for predicting reservoir performance, groundwater movement, and contaminant transport.
Porosity Formula
φ = (Vᵥ / Vₜ) × 100
φ = porosity (%)
Vᵥ = void (pore) volume
Vₜ = total bulk volume
Darcy's Law (Permeability)
k = (Q·μ·L) / (A·ΔP)
k = permeability (Darcy)
Q = volumetric flow rate (cm³/s)
μ = fluid viscosity (cP)
L = sample length (cm)
A = cross-sectional area (cm²)
ΔP = pressure differential (atm)
⚠️ Unit System Requirement
This calculator uses the Darcy-CGS system. Ensure all inputs use the specified units (cm³/s, cP, cm, cm², atm) for permeability results in Darcy (D). Mixing unit systems will produce incorrect results.
Measure porosity
Obtain core sample, measure its bulk volume, then saturate with fluid and measure pore volume. Alternatively, use gas expansion (helium porosimetry) or nuclear magnetic resonance (NMR) logging.
Set up permeameter test
Place sample in permeameter apparatus. Apply known pressure differential across the sample length. Use fluid of known viscosity (often nitrogen gas or brine).
Measure flow rate
Allow flow to stabilize, then measure volumetric flow rate through the sample. Ensure laminar (non-turbulent) flow for Darcy's Law validity.
Calculate permeability
Apply Darcy's Law using measured flow rate, known sample dimensions, fluid viscosity, and applied pressure differential to calculate permeability in darcys.
💡 What is a Darcy?
One darcy is the permeability that allows 1 cm³/s of 1-centipoise fluid to flow through 1 cm² area under 1 atmosphere/cm pressure gradient. Most reservoir rocks are measured in millidarcys (mD): 1 D = 1000 mD.
A sandstone core sample is tested for porosity and permeability in a petroleum laboratory.
Porosity of 25% indicates good storage capacity, typical for reservoir-quality sandstone. One-quarter of the rock volume can store fluids.
Permeability of 1.333 D (1,333 mD) represents excellent flow capacity—this sandstone would be considered a high-quality petroleum reservoir rock. Values above 100 mD are considered good; above 1000 mD is excellent.
Yes. Pumice and clay both have high porosity (40-60%) but low permeability. Pumice has isolated pores that don't connect. Clay has tiny, poorly connected pores that restrict fluid flow despite high overall void space.
Sandstones: 10-30% porosity, 10-1000 mD. Carbonates: 5-25% porosity, highly variable permeability (1-10,000 mD). Shales: 5-15% porosity, <0.01 mD. Unconsolidated sands: 30-50% porosity, >1000 mD.
Larger, well-sorted grains typically give higher permeability because the flow pathways between grains are larger and more connected. Porosity depends more on packing and sorting than grain size. Poor sorting (mixed grain sizes) reduces both porosity and permeability.
Absolute permeability measures flow capacity when 100% saturated with a single fluid. Effective permeability measures flow when multiple fluid phases (oil, water, gas) are present. Effective permeability is always less than absolute permeability.
Different fluids (gas, water, oil) can give different results due to fluid-rock interactions. Gas permeability is often higher because gas doesn't interact with clay minerals. The Klinkenberg correction adjusts gas measurements to equivalent liquid permeability.
Fractures can dramatically increase permeability even in low-porosity rocks. A fractured granite with 1% porosity might have higher permeability than 30% porosity sandstone. Fracture permeability is highly directional (anisotropic).
1 Darcy = 1000 millidarcys (mD) = 9.87×10⁻¹³ m² = 0.987 μm². Engineers typically use darcys or millidarcys, while scientists prefer SI units (square meters or square micrometers).
Porosity generally decreases with depth due to compaction from overburden pressure and diagenetic cementation. Shallow sandstones might have 35% porosity; the same sandstone at 3 km depth might have only 15% porosity due to compaction and mineral precipitation.
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