TABLE OF CONTENTS Rock properties significantly influence the production of hydrocarbons from porous media. For example, oil production from unconsolidated sandstone reservoirs in the Gulf of Mexico depends on the relationship between permeability and fluid pressure. One way to approximate this effect in a flow model is to combine porosity-permeability models with porosity-fluid pressure relationships. This chapter describes the role of rock properties in reservoir flow modeling.
One of the most fundamental properties of rock that a reservoir flow model must include is porosity, which is the fraction of a porous medium that is void space. The bulk volume V B of a porous medium is the sum of pore volume V P and grain volume V G, thus
| (14.1) |  |
Porosity is the ratio of pore volume to bulk volume:
| (14.2) |  |
Dividing Eq. (14.1) by V B and using the definition of porosity expresses the grain volume in terms of porosity as
| (14.3) |  |
If the void space in a porous medium is connected and communicates with a wellbore, it is referred to as effective porosity. Void space that cannot communicate with the wellbore is considered ineffective porosity. The original porosity resulting from sediment deposition is called primary porosity. Secondary porosity is an incremental increase in primary porosity due to the chemical dissolution of reservoir rocks, especially carbonates. Primary and secondary porosity can be both effective and ineffective. Total porosity is a combination of ineffective porosity and effective (interconnected) porosity.
Porosity values depend on rock type, as shown...
