The Effect of Interfacial Tension Upon Gas-Oil Relative Permeability Measurements: Interpretation Using Pore-Scale Models
Authors: McDougall S.R. , Salino P.A. , Sorbie K.S. 
Published: December 2007

The effects of interfacial tension (IFT) upon gas-oil relative permeabilities are of considerable interest in the reservoir engineering of gas flooding processes. Several papers have presented experimental data on this matter, although there is some conflict among the findings of different authors. This paper describes the development and implementation of an unsteady-state pore-scale process simulator, which has been utilised to interpret a number of related laboratory gas-oil displacements performed at different values of interfacial tension. The experimental work was carried out at this laboratory and the range of IFTs considered covered almost three orders of magnitude - from 9.76mN/m down to 0.019mN/m. However, more importantly, all of the experimental data was available to the authors including the oil/gas viscosity ratio, M (= oil/ gas), as a function of IFT. This proved to be essential in the modelling and interpretation of the experimental results and it has rarely been reported by previous experimentalists.

Both constant rate and constant pressure drop simulations were carried out, using pore-scale models that had been suitably anchored to the experimental samples. The resulting production data were analysed using a modified JBN technique and the calculated relative permeabilities were found to exhibit the same IFT sensitivities as the experimental datasets - viz. a marked increase in the gas curve and very little change in the oil curve with decreasing IFT. This behaviour is subsequently explained by considering both the viscous/capillary force balance and the viscosity ratio operating during each displacement. These vary considerably over the experimental range considered, with different displacements effectively lying in different flow regimes. In addition, results demonstrate that it is extremely difficult to predict a priori the directional trend exhibited by relative permeability curves with varying IFT, unless all of the experimental quantities are reported. The fact that both capillary number and viscosity ratio play a role in determining the phase distributions during a displacement means that such trends can only be properly understood in light of appropriately-scaled network simulations that incorporate the underlying pore-scale physics.

Introduction

Variations in gas-oil relative permeability as a function of interfacial tension (IFT) are of particular importance in the area of compositional simulation, where oil and gas compositions can vary significantly both spatially and temporally. This is especially significant in the context of volatile oil and gas condensate reservoirs, where phase compositions do not generally pass through the critical point and miscibility is consequently avoided. At present, many standard compositional simulators utilise a model first proposed by Coats, which employs simple linear interpolation to modify the relative permeability curves at different values of IFT. The interpolated relative permeabilities take the form:

(1)

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