An innovative methodology of estimating core scale relative permeability and upscaling to reservoir scale for predicting oil recovery for porous fractured carbonate reservoirs by waterflooding

Abstract

Carbonate reservoirs are well known for their heterogeneity where natural fractures play a significant role in the transportation of hydrocarbon. The prediction of production potential in these reservoirs is dependent on representative relative permeability data; this is highly effected by flow discontinuity due the presence of fractures. In this thesis an innovative methodology of estimating relative permeability and upscaling it to the reservoir scale is presented. First, core scale relative permeability is established by integrating laboratory and numerical analysis on three different types of carbonate samples: fractured marble, porous matrix and porous-fractured matrix. The numerical analysis accounts for the fracture aperture distribution which is estimated from the roughness of two fracture surfaces by using optical interferometry and μ-CT. Secondly, the core scale permeability is up-scaled to the reservoir sub-domain scale via an intermediate glass bead model domain. The subsurface fracture map of Arab-D reservoir is established by using an innovative methodology. A section of the Arab-D is divided into a number of subdomains. Small and medium fractures are discretized along with the matrix and permeability tensor for each subdomain and estimated. Next, each sub-domain is further discretized into glass bead model domain along with the long fractures ≥ 50m and fine scale simulation is carried out to upscale relative permeability to subdomain scale. Finally the subdomain scale relative permeability along with the permeability tensors are used to evaluate oil recovery of Arab-D reservoir by using waterflooding.

From the results of this study, it was evident that Corey’s power law fails to optimize relative permeability curves. Limiting cubic fit, on the other hand, has shown to optimize the relative permeability curve and closely represents the laboratory measured relative permeability data. The relative permeability of the porous fracture system was shown to be a strong function of the overall fracture aperture; the wider the aperture the greater the degree of phase interference, therefore a higher relative permeability was achieved. The results also show that the residual water saturation was much greater for the porous fractured system when compared to non-porous fractured system with near zero matrix permeability. This is due to the fact that fluid is mainly moving through the fractures using a path of least resistance, creating an un-swept matrix. Results of the water flood study have shown that fracture orientation has a significant bearing on the sweep efficiency; fractures, when aligned with the flow direction, results in a smaller swept matrix area resulting in low oil recovery.