UNCERTAINTY IN WELL TEST AND CORE PERMEABILITY ANALYSIS

Reservoir permeability is one of the important parameters derived from well test analysis. Small-scale permeability measurements in wells are usually made using core plugs, or more recently, probe permeameter measurements. Upscaling of these measurements for comparisons with permeability derived well tests (DST &/or Pressure Build-Up) can be completed by statistical averaging methods. Well Test permeability is often compared with one of the core plug averages: arithmetic, geometric and harmonic. A question that often arises is which average does the well test-derived permeability represent and over what region is this average valid? A second important question is how should the data sets be reconciled when there are discrepancies?

In practice, the permeability derived from well tests is often assumed to be equivalent to the arithmetic (in a layered reservoir) or geometric (in a randomly distributed permeability field) average of the plug measures. These averages are known to be members of a more general power-average solution. This pragmatic approach (which may include an assumption on the near-well geology) is often flawed due to a number of reasons, which will be expanded in this study. The assessment of in-situ, reservoir permeability requires an understanding of both core (plug and probe) and well test measurements – in terms of their volume scale of investigation, measurement mechanism, interpretation and integration.

This study will compare core and well test measurements in B.R. Field (carbonate reservoir) which is in South East of Turkey. An evaluation of well test data and associated core plug data sets from a single field will be resulting from the interpretation of small (core) and reservoir (well test) scale permeability data. The techniques to be used are traditional uspscaling combined with the use of the Lorenz Plot to identify the dominant flowing interval. Carbonates are very heterogeneous and this exercise will be instructive in understanding the heterogeneity for the guidance of reservoir models in such a system.

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