Abstract

The objective of this work is to improve determination of two-phase and three-phase relative permeabilities by the use of saturation imaging techniques. The first part of the paper reports on steady-state and unsteady-state relative permeability experiments performed on restored-state carbonate reservoir cores. The aim was to study how relative permeability test methodology impacts relative permeability curves. hysteresis and residual oil saturations in these intermediate-wet cores. Refined oil was used.

Significant hysteresis was observed in both the unsteady-state water and oil relative permeabilities. The characteristics of the unsteady-state water relative permeabilities imply that viscous instabilities were present during the waterflood Centrifuge capillary pressure-wettability tests performed on companion core plugs both before and after the relative permeability tests showed good agreement with the unsteady-state results. but indicated change towards less oil-wetness during the steady-state tests. The main conclusion of this work is that extensive flushing of a restored-state core with refined oil may lead to a non representative relative permeability data and should therefore be avoided.

The second part of the paper presents a summary of results obtained from three-phase unsteady-state flow in water-wet sandstone (Berea and Clashach) cores. In-situ saturation measurements show that the water relative permeability is dependent on water saturation alone. and that there is no change in water relative permeability due to three-phase flow. The waterflood residual oil saturation was found reduced in the presence of a gas phase, and may depend on the phase (oil or gas) injected prior to waterflooding.

Introduction

It is often recommended that laboratory relative permeability experiments for reservoir performance predictions should be conducted under simulated reservoir conditions. In such experiments, it is expected to use formation brine and crude oil as the fluid phases and preferably native state reservoir core as the porous medium. In the industry. however, relative permeability tests are often conducted at ambient laboratory conditions using synthetic brine and refined oil. This use of laboratory condition and refined oil is a common practice because it is relatively less complicated and least expensive method.

An extensive documentation of various experimental methods used to acquire relative permeability data has been presented by Honarpour et al. The two most commonly used techniques in the laboratory to obtain relative permeability data are the steady-state and the unsteady-state in which a JBN-method or its derivative is used to calculate the relative permeabilities. in this work, intermediate-wet carbonate cores have been tested for both steady-state and unsteady-state waterfloods and oilfloods. The choice of test method best suited for the acquisition of relative permeability data becomes complicated when the porous medium is not strongly water- or strongly oil-wet.

Purpose. The purpose of this paper is twofold. One is to obtain information on how relative permeability test methodology (steady-state versus unsteady-state) impacts relative permeability curves. Emphasis has been on evaluating relative permeability hysteresis and residual saturations obtained in two-phase oil- and waterfloods in intermediate-wet cores.

The other purpose is to summarize the results of unsteady- state three-phase flow studies performed on water-wet Berea and Clashach sandstone cores. The work is directed to improve three-phase relative permeability determination by using in-situ fluid saturation measurements.

P. 643

This content is only available via PDF.
You can access this article if you purchase or spend a download.