Dual Porosity
Naturally fractured reservoirs often have 2 porosities, a matrix porosity and a fracture porosity. This is what is known as a dual porosity reservoir. The fracture network (left side of Fig. 1) usually consists of shear and extensional fractures and needs to be simplified in the model as a series of matrix blocks surrounded by fractures (right hand side). As the model looks like a stacked series of sugar cubes it is also called a sugar cube model. Often the volume of hydrocarbons stored in the fractures is lower than in the matrix (porosity) and the fracture permeability is higher although there is a range of possibilities presented by Ron Nelson (Fig. 2).
Fig. 1. Warren and Root (1963) model of fractured reservoirs as a dual porosity system.
Nelson’s classification
This is very valuable way to describe your reservoir as it may dictate the economic decisions required to best dest develop your reservoir (Fig. 2) However, it may not be immediately obvious which of the types you are dealing with. Also, more than 1 type may be present within the same field i.e., well data may suggest some spatial and vertical variation.
Type I: Fractures provide the essential porosity and permeability.
Type II: Fractures provide essential permeability
Type III: Fractures provide permeability assist in already (matrix) producible reservoir. Matrix provides most storage.
Type IV: Fractures provides no additional permeability and porosity and are often flow barriers.
Fig. 2. Nelson’s classification of naturally fractured reservoirs based upon matrix and fracture contribution to permeability and porosity.
The static description of the fracture network is critical in Type I reservoirs as the fractures provide essential porosity and permeability. From Type I to III, recovery factor is less influenced by the fracture network and more by the inherent rock and fluid properties.
Key Takeaways
Fractured reservoirs are often described as Dual Porosity reservoirs, where there are 2 porosities - matrix and fractures
Nelson’s classification provides a range of possibilities based upon the relative percentage of porosity and permeability in the matrix and fractures.
For Types 1 and II, recovery factor is more dependant upon geometry of the fracture network whereas types III and IV have RFs more dependant upon the inherent rock and fluid properties.