The use of single porosity models to simulate fracture flow is a challenge for simulation engineers. The main challenge remains in the speed at which water advances in the fracture system with little production from the producers that intersect the fractures. In single porosity modeling, water has to displace the oil ahead of the flood front to reach a producer. Due to the high matrix to fracture storage ratio, this usually results in over-prediction of the produced oil volume prior to water breakthrough. One typical solution to this problem is the use of local grid refinement, where an engineer will represent the fracture or fracture corridor with a "thinner" line of cells.
Another alternative solution is to modify the relative permeability curves of oil and water, to slow the oil movement and speed up the water movement in these cells. Paul van Lingen et al (2001) presented a technique that relies on modifying the relative permeability curves to produce "pseudo relative permeability" curves for the grid blocks containing fractures, without the need for grid modification. This method reflects a considerable advancement in the modeling of fracture system behavior in single porosity systems. It allowed to model faster breakthrough times and higher water production rates after breakthrough.
This paper describes a modified pseudo relative permeability correlation, which is based on the van Lingen et al method, that improves the water breakthrough time and water cut predictions, especially in the low to medium fracture-to-matrix permeability contrast cases. The new method restricts the pseudo curves to the widely known straight line curves that are typically used to represent fracture flow in dual porosity modeling. The modified correlation was numerically tested with various permeability contrast cases and was compared to a dual porosity model. The method is currently being used for modeling a large Middle East oil reservoir.