Abstract

While permeability modeling follows a well-established approach in converting laboratory properties to subsurface conditions, ambiguity remains over the approach to be followed by laboratory-acquired capillary pressures (under ambient conditions, like most mercury injection capillary pressures (MICP) measurements). One approach (developed by the earlier work of Juhasz) recommends that capillary pressures be stress corrected (prior to modeling) according to a correlation. Another approach suggests the saturation-height model (SHM) be built with ambient measurements that when supplied with corrected properties (porosity and permeability) would generate in-situ saturations.

The effect of stress correction applied to porosity and permeability data (as part of routine core analysis (RCA) is not easily compared against the capillary pressure correction, potentially leading to inconsistencies.

The work presented here uses a recent methodology that aims at ensuring consistency between permeability and SHMs to provide guidance on the best approach to be followed in the process of building a SHM. The MICP or SHM carries an intrinsic permeability that can be compared to the permeability model. The results show that significant inconsistency can occur between the porosity-permeability data (a reliable, well-controlled and measurable property under stress) on one hand, and the MICP-/SHM-inferred permeability on the other.

The conclusion is that the most robust dataset for preparing the SHM is under the same conditions under which the MICP and capillary pressure (Pc) data have been acquired. When these data have been acquired under ambient conditions and the resulting model has stressed porosity and permeability as inputs, the SHM will predict the correct stressed entry pressures. The findings are validated against a dataset where the capillary pressures acquired under both ambient and stress conditions.

Introduction

Saturation-height models (SHM) combined with fundamental rock properties (porosity and permeability) are the basis for a realistic reservoir model. In contrast to porosity and (single-phase) permeability that are rock properties, SHMs are the result of fluid-rock interaction.

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