The purpose of this study is to test an upscaling technique, applied to naturally fractured reservoirs by adjusting fractured block components according to a small-scale fracture behavior using mini-models. The methodology is applied to six cases. For the first two cases, the flow is controlled by...

The purpose of this study is to test an upscaling technique, applied to naturally fractured reservoirs by adjusting fractured block components according to a small-scale fracture behavior using mini-models. The methodology is applied to six cases. For the first two cases, the flow is controlled by thin, high-permeability facies and tectonic fractures (nearly vertical); for the next two cases, the flow is controlled by touching vugs (nearly horizontal) and tectonic fractures and, for the last two cases, the flow is controlled only by touching vugs. Two types of background matrix were tested: those having significant petrophysical features of carbonate reservoirs (separate vugs and textural features) and a homogeneous matrix to validate the fracture upscaling and isolate the matrix heterogeneities effects. A fine-grid cell size of 0.8×0.8×0.4 m3 is used as a reference for the upscaling method. All fractured grid blocks in coarser cell size were adjusted to calibrate the fracture direction according to our fine-grid fracture behavior, combined with a well-index adjustment. It was possible to adjust reservoir output parameters (field average and well pressure, oil recovery factor, etc.) and reduce flow simulation time from days to a few seconds. This approach is useful for carrying meso-scale heterogeneities from different sources into a macro-scale grid-cell size, especially when being applied near wells in order to improve the accuracy of well productivity from fractures

Fechado