- A conventional reservoir is a subsurface formation with sufficient porosity and permeability that commercial quantities of hydrocarbons can be stored in and then produced from that formation. Porosity is that percentage of the gross or overall rock volume that is available to contain either liquids or gas. As an analogy, the porosity of a sponge is that portion of the sponge that absorbs water when it is submerged. As porosity of a reservoir can contain water, oil, or gas, the percentage of the pore space that is filled with hydrocarbons is very important. This is known as hydrocarbon saturation and is a percentage of the total porosity that contains oil or gas. Permeability is a measure of the ease which fluids or gases can move through a certain formation. Permeability is measured in units known as darcies, after Henry Darcy who first derived Darcy's Law, which is the mathematical description of flow of fluids through a porous medium. The larger the darcy value of a porous medium, the easier it is for fluids to flow through that interval. A well sorted sand, which means a quartz or carbonate sand that has a consistent grain size, will have an absolute permeability of approximately one darcy, which would be a very good reservoir. Now as well as absolute permeability, there's also something known as relative permeability. Every formation has a certain percentage of water in that formation along with any hydrocarbons that might be contained. Relative permeability refers to the permeability for a particular fluid to flow in that formation and is directly associated with the saturation of that fluid in the formation. A more in depth discussion of permeability is beyond the scope of this presentation.