Porosity and Permeability

A reservoir will have a given amount of void space. If these voids are not connected, production will be limited. This “effective” porosity, in conjunction with permeability, dictates the ultimate quality of the reservoir. Porosity consists of primary and secondary forms. Primary porosity is formed when the sediment is originally deposited. Secondary porosity results from diagenesis by solution and replacement. Some clastic porosity forms from tectonic activity.

The primary porosity in sandstones is principally interparticle (between the grains). Though not true theoretically, as a general rule, the larger the grain size, the higher the porosity. This porosity will decrease during the formation of clays and alteration products after deposition. Compaction and cementation after deposition will also reduce the absolute porosity. Generally, porosity decreases as depth increases. However, cementation is the principal process leading to porosity loss in sandstones.

There are three types of pore communication within clastics:

1. Catenary porosity - pores that have communication with others via 2 or

more pore throats.

2. Cul-de-sac porosity - those that have communication via only 1 throat.

3. Closed pore communication.

Types 1 and 2 make up “effective porosity”. Darcy's law for permeability is only valid when 1 fluid phase is present. When more than one fluid is present (the norm in any reservoir) the term effective permeability is sometimes used, meaning one rock may have three permeability values; effective permeability for oil, water and gas.

Permeability can vary greatly depending on orientation (e.g. vertical permeability maybe far lower than horizontal permeability) for the same rock, especially if micas are abundant. Permeability may also be strongly influenced by cross-bedding and other sedimentary structures.