Permeability (earth sciences)

Permeability in fluid mechanics and the earth sciences (commonly symbolized as κ, or k) is a measure of the ability of a porous material (often, a rock or unconsolidated material) to allow fluids to pass through it.

Units

The SI unit for permeability is m². A traditional unit for permeability is the darcy (D), or more commonly the millidarcy (mD) (1 darcy $\backslash approx$10⁻¹²m²). The unit of cm² is also sometimes used (1 m² = 10⁴ cm²).

Applications

The concept of permeability is of importance in determining the flow characteristics of hydrocarbons in oil and gas reservoirs, and of groundwater in aquifers.

For a rock to be considered as an exploitable hydrocarbon reservoir without stimulation, its permeability must be greater than approximately 100 mD (depending on the nature of the hydrocarbon - gas reservoirs with lower permeabilities are still exploitable because of the lower viscosity of gas with respect to oil). Rocks with permeabilities significantly lower than 100 mD can form efficient seals (see petroleum geology). Unconsolidated sands may have permeabilities of over 5000 mD.

The concept has also many practical applications outside of geology, for example in chemical engineering (e.g., filtration).

Description

Permeability is part of the proportionality constant in Darcy's law which relates discharge (flow rate) and fluid physical properties (e.g. viscosity), to a pressure gradient applied to the porous media:

:$v\; =\; \backslash frac\; \{\backslash kappa\}\{\backslash mu\}\; \backslash frac\{\backslash Delta\; P\}\{\backslash Delta\; x\}$ Therefore: : $\backslash kappa\; =\; v\; \backslash frac\{\backslash mu\; \backslash Delta\; x\}\{\backslash Delta\; P\}$

where: :$v$ is the superficial fluid flow velocity through the medium (i.e., the average velocity calculated as if the fluid were the only phase present in the porous medium) (m/s) :$\backslash kappa$ is the permeability of a medium (m²) :$\backslash mu$ is the dynamic viscosity of the fluid (Pa s) :$\backslash Delta\; P$ is the applied pressure difference (Pa) :$\backslash Delta\; x$ is the thickness of the bed of the porous medium (m)

In naturally occurring materials, permeability values range over many orders of magnitude (see table below for an example of this range).

Relation to hydraulic conductivity

The proportionality constant specifically for the flow of water through a porous media is called the hydraulic conductivity; permeability is a portion of this, and is a property of the porous media only, not the fluid. Given the value of hydraulic conductivity for a subsurface system, k, the permeability can be calculated as:

:$\backslash kappa\; =\; k\; \backslash frac\; \{\backslash mu\}\; \{\backslash rho\; g\}$

:where

κ is the permeability, m²

k is the hydraulic conductivity, m/s

μ is the dynamic viscosity, kg/(m-s)

ρ is the density of the fluid, kg/m³

g is the acceleration due to gravity, m/s².

Determination

Permeability is typically determined in the lab by application of Darcy's law under steady state conditions or, more generally, by application of various solutions to the diffusion equation for unsteady flow conditions.

Permeability needs to be measured, either directly (using Darcy's law) or through estimation using empirically derived formulas. However, for some simple models of porous media, permeability can be calculated (e.g., random close packing of identical spheres).

Permeability model based on conduit flow

Based on Hagen–Poiseuille equation for viscous flow in a pipe, permeability can be expressed as: :$\{\backslash kappa\}\_\{I\}=C\; \backslash cdot\; d^2$ where: :$\{\backslash kappa\}\_\{I\}$ is the intrinsic permeability [length²] :$C$ is a dimensionless constant that is related to the configuration of the flow-paths :$d$ is the average, or effective pore diameter [length].

Intrinsic and absolute permeability

The terms intrinsic permeability and absolute permeability states that the permeability value in question is an intensive property (not a spatial average of a heterogeneous block of material), that it is a function of the material structure only (and not of the fluid), and explicitly distinguishes the value from that of relative permeability.

Permeability to gases

Sometimes permeability to gases can be somewhat different that those for liquids in the same media. One difference is attributable to "slippage" of gas at the interface with the solid when the gas mean free path is comparable to the pore size (about 0.01 to 0.1 μm at standard temperature and pressure). See also Knudsen diffusion and constrictivity. For example, measurement of permeability through sandstones and shales yielded values from 9.0x10⁻¹⁹ m² to 2.4x10⁻¹² m² for water and between 1.7x10⁻¹⁷ m² to 2.6x10⁻¹² m² for nitrogen gas.

Tensor permeability

To model permeability in anisotropic media, a permeability tensor is needed. Pressure can be applied in three directions, and for each direction, permeability can be measured (via Darcy's law in 3D) in three directions, thus leading to a 3 by 3 tensor. The tensor is realized using a 3 by 3 matrix being both symmetric and positive definite (SPD matrix):

The tensor is symmetric by the Onsager reciprocal relations.

The tensor is positive definite as the component of the flow parallel to the pressure drop is always in the same direction as the pressure drop.

The permeability tensor is always diagonalizable (being both symmetric and positive definite). The eigenvectors will yield the principal directions of flow, meaning the directions where flow is parallel to the pressure drop, and the eigenvalues representing the principal permeabilities.

Ranges of common intrinsic permeabilities

These values do not depend on the fluid properties; see the table derived from the same source for values of hydraulic conductivity, which are specific to the material through which the fluid is flowing. {| border="1" width="600" | bgcolor="#FAEBD7" | Permeability | bgcolor="#FAEBD7" colspan="4" align="center" | Pervious | bgcolor="#FAEBD7" colspan="4" align="center" | Semi-Pervious | bgcolor="#FAEBD7" colspan="5" align="center" | Impervious |- | bgcolor="#FAEBD7" | Unconsolidated Sand & Gravel | colspan="2" align="center" | Well Sorted Gravel | colspan="3" align="center" | Well Sorted Sand or Sand & Gravel | colspan="4" align="center" | Very Fine Sand, Silt, Loess, Loam | colspan="4" | |- | bgcolor="#FAEBD7" | Unconsolidated Clay & Organic | colspan="4" | | colspan="2" align="center" | Peat | colspan="3" align="center" | Layered Clay | colspan="4" align="center" | Unweathered Clay |- | bgcolor="#FAEBD7" | Consolidated Rocks | colspan="4" align="center" | Highly Fractured Rocks | colspan="3" align="center" | Oil Reservoir Rocks | colspan="2" align="center" | Fresh Sandstone | colspan="2" align="center" | Fresh Limestone, Dolomite | colspan="2" align="center" | Fresh Granite |- | bgcolor="#FAEBD7" | κ (cm²) | 0.001 | 0.0001 | 10⁻⁵ | 10⁻⁶ | 10⁻⁷ | 10⁻⁸ | 10⁻⁹ | 10⁻¹⁰ | 10⁻¹¹ | 10⁻¹² | 10⁻¹³ | 10⁻¹⁴ | 10⁻¹⁵ |- | bgcolor="#FAEBD7" | κ (millidarcy) | 10⁺⁸ | 10⁺⁷ | 10⁺⁶ | 10⁺⁵ | 10,000 | 1,000 | 100 | 10 | 1 | 0.1 | 0.01 | 0.001 | 0.0001 |} Source: modified from Bear, 1972

See also

Hydraulic conductivity

Hydrogeology

Permeation

Petroleum geology

Relative permeability

Klinkenberg correction

Electrical resistivity measurement of concrete

Footnotes

References

Bear, Jacob, 1972. Dynamics of Fluids in Porous Media, Dover. — ISBN 0-486-65675-6

Wang, H. F., 2000. Theory of Linear Poroelasticity with Applications to Geomechanics and Hydrogeology, Princeton University Press. ISBN 0691037469

External links

Graphical depiction of different flow rates through materials of differing permeability

Web-based porosity and permeability calculator given flow characteristics

Florida Method of Test For Concrete Resistivity as an Electrical Indicator of its Permeability

Category:Aquifers Category:Hydrology Category:Soil mechanics Category:Petroleum Category:Porous media