The purpose of this study is to develop an upscaling technique, applied to naturally fractured carbonate reservoirs, adjusting fracture blocks components and well indices according to our small scale fracture behavior using mini-models. Two significant petrophysical features of carbonate reservoirs were applied over a background matrix, defined by low permeability but with separate vugs (SV) randomly distributed with high porosity and permeability: (1) tectonic fractures (nearly vertical) and (2) touching vugs (nearly horizontal), were defined as large scale fractures, with high permeability and low porosity. These features are combined and tested in three cases, with the same background matrix. In the first case, the flow is controlled by high permeability thin facies and tectonic fractures; in the second case, the flow is controlled by touching vugs and tectonic fractures and in the third case the flow is controlled only by touching vugs. A fine grid cell size of 0.8x0.8x0.4 meters is used as reference for the upscaling method. All fracture grid blocks in coarser cell size (3×3×2 meters) were adjusted in order to calibrate the fracture direction according to our fine grid fracture behavior, combined with a well index adjustment. In order to isolate the matrix heterogeneities effects, the same fracture calibration procedure is applied to a homogeneous matrix using the same fracture network in order to validate the fracture upscaling. It was possible to adjust all reservoir parameters (field average and well pressure, oil recovery factor, etc.) and reduce the flow simulation time from days to a few seconds. With this methodology we can transfer small scale heterogeneities from different sources to a coarser scale without losing information.

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