Shape Factor Estimation and WAG Simulation in Naturally Fractured Reservoirs
Research output: Thesis › Master's Thesis › Research
Naturally fractured reservoirs contain a signicant part of the world's remaining oil reserves. A common approach for their simulation is dual porosity modelling. The most signicant part in this model is the shape factor that describes the movement of fluids between fracture and matrix domain. Despite decade-long research there is no consensus in the scientic community how the shape factor can be calculated. This thesis uses a single porosity model to estimate the shape factor of a dual porosity model with the same size. Geological data from Salzburg are used for this thesis. All other necessary input parameters are also given and the way is described how they were obtained. Subsequently, the single porosity and the dual porosity model are presented in detail. It is shown that recovery depends strongly on the driving mechanisms that are taken into account for the simulation. Also relevant is the wettability of the investigated rocks. The injection of gas after water leads to a much higher ultimate recovery than only the injection of water alone. However, ultimate recovery does not depend on wettability. If a correction factor of 1.87 is applied to the equation of Gilman & Kazemi (1973), recovery curves of the single porosity and the dual porosity model are nearly identical for the oil wet case . Additionally, an algorithm is described that estimates ultimate recovery as a function of the percentage of fractures filled. It is shown that lling of fractures as described in this thesis does only have a small in uence on oil recovery. Only the flow rate in the first months of oil production is aected slightly.
|Award date||30 Oct 2015|
|State||Published - 2015|