Comparison of viscous and gravity dominated gas–oil relative permeabilities

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Unsteady and steady-state gasflood, centrifuge and gravity-drainage experiments are routinely carried out to determine relative permeabilities for cores taken from petroleum reservoirs. These laboratory studies are often interpreted by simple methods, e.g., JBN or Hagoort method, and give different oil relative permeability for the same core. The objective of this paper is to investigate the factors that affect these tests and determine the best use of the data in the field scale studies. In this study, it has been shown that neglecting capillary pressure can lead to significant errors in the relative permeability curves for both gasflood and centrifuge experiments. The residual oil saturation obtained from a centrifuge experiment is very low (∼1%) for a set of unconsolidated and friable cores from offshore, West Africa with spreading oil and shown to be insensitive to the permeability of the porous medium (in the range studied). A comparison between the relative permeabilities determined from centrifuge and gasflood experiments shows that the residual oil saturation is much higher and oil relative permeability is lower for gasflood tests. An empirical model has been proposed to estimate residual oil saturation as a function of a heterogeneity index and displacement rate for cores obtained perpendicular to the bedding plane. The normalized relative permeabilities obtained from the centrifuge and the gasflood experiment are essentially the same for these vertical cores. The normalized oil relative permeabilities for the two techniques are different for cores obtained parallel to the bedding plane, perhaps due to the effects of layering. The centrifuge relative permeability should be applicable to those parts of the reservoir where the flow is gravity dominated. The gasflood relative permeability can be applicable to viscous dominated regions of the reservoir as long as heterogeneities and flow rates are accounted for properly.