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Permeability

(Definition, classification and the factors affecting the magnitude of permeability)

Permeability is easiness with which fluid can move through porous rock. High permeability means numerous channels for oil and gas migration. A reservoir rock must have the ability to allow petroleum fluids to flow through its interconnected pores. This rock property is termed permeability. The permeability of a rock depends on the effective porosity. Therefore, permeability is affected by the rock grain size, grain shape, grain size distribution (sorting), grain packing and the degree of consolidation and cementation. Permeability is affected by the type of clay present, especially where fresh water is present.

French engineer Henry Darcy developed a fluid flow equation that since has become one of the standard mathematical tools of the petroleum engineer. One Darcy is a relatively high permeability and the permeability of most reservoir rock is less than one Darcy. The common measure of rock permeability is in millidarcies (mD) or um in SI units.

The term absolute permeability is used if the porous rock is 100% saturated with a single fluid (phase), such as water, oil or gas. When two or more fluids are present in the rock, the permeability of the rock to the flowing fluid is called effective permeability.

Because fluids interfere with each other during their movement through the pore channels in the rock, the sum of effective permeability will always be less than the absolute permeability. The ratio of effective permeability of one phase during multiphase flow to the absolute permeability is the relative permeability to that phase.

Classification of permeability

Petroleum reservoirs can have primary permeability, which is also known as the matrix permeability and secondary permeability. Matrix permeability originated at the time of deposition and lithification (hardening) of sedimentary rocks. As with secondary (induced) porosity, secondary permeability resulted from the alteration of the rock matrix by: compaction, cementation, fracturing and solution. Whereas, compaction and cementation generally reduce the primary permeability; fracturing and solution tend to increase. In some reservoir rocks, particularly low-porosity carbonates, secondary permeability provides the main conduit for fluid migration.

Factors affecting the magnitude of permeability

Permeability of petroleum reservoir rocks may range from 0.1 to 1000 or more millidarcies. The quality of a reservoir as determined by permeability in mD, may be judged as:

• K < 1 = poor

• 1< K = fair

• 10 < K < = moderate

• 50 < K < 250 = good

• K > 250 = very good

Reservoirs having permeability below 1 mD are considered "tight". Such low permeability values are generally found in limestone matrices and also in tight gas sands of western United States.

The factors affecting the magnitude of permeability in sediments are:

1. shape and size of sand grains: if the rock is composed of large and flat grains uniformly arranged with the longest dimension horizontally- its horizontal permeability (kH) will be very high, whereas, the vertical permeability (kv) will be medium-to-large. If the rock is composed mostly of large and uniformly rounded grains, its permeability will be considerably high and of the same magnitude in both directions. Permeability of reservoir rocks is generally lower, especially in the vertical direction, if the sand grains are small and of irregular shape. Most petroleum reservoirs are in this category. Reservoirs with directional permeability are called anisotropic. Anisotrophy greatly affects fluid flow characteristics. The difference in permeability measured parallel and vertical to the bedding plane is a consequence of the origin of that sediment. Subsequent compaction of the sediment increases the ordering of the sand grains so that they generally lie in the same direction;

2. cementation: of both permeability and porosity sedimentary rocks are influenced by the extent of cementation and the location of the cementing material within the pore space;

3. fracturing and solution: in sandstones, fracturing is not important cause of secondary permeability, except where sandstones are interbedded with shales, limestones and dolomites.

Capillary pressure

Capillary pressure is the difference in pressure between two immiscible fluids across a curved interface at equilibrium. Curvature of the interface is the consequence of preferential wetting of the capillary walls by one of the phases.