There are several proven techniques, both laboratory and in-situ, for measuring residual saturations and porosity in reservoir materials. A common feature of these methods is that significant averaging is done to find the residual saturation or porosity values. Many laboratory techniques for measuring porosity and residual saturations are also destructive.
The purpose of this work is to demonstrate the feasibility and limitations of X-ray computerized tomography (CT) as a method for measuring residual oil saturations on a core sample. Many investigators have used CT for other types of oilfield laboratory experiments1–9. This method averages on the millimeter scale, and has minimal physical effects on the core. Porosity distribution measurements are also made and reported.
A large fraction of the world's oil reserves is in carbonate formations. By passed and residual oil in these formations represent a large target for improved oil recovery. Heterogeneous carbonate formations present many difficult questions. How much oil is left after primary recovery and after waterflooding? Where is the residual oil located? Is it in the rock matrix or in vugs that are not well connected to the primary flow paths? How can one determine the scale necessary to adequately describe heterogeneous cores and then model subsequent core flood experiments? This paper will show how CT can be used to address some of these questions.
The majority of this work involves the study of cores from the Fenn-Big Valley Field in Alberta, Canada and from the Taylor-Link Field in Pecos County, Texas (TX). Additional baseline porosity studies were performed on a San Andres dolomite sample taken from an outcrop near Carlsbad, New Mexico (NM) and from samples of Berea and Boise sandstones.
All CT data were obtained using a fourth generation medical CT-scanner. The scanner is a Deltascan 2020HR manufactured by Technicare Corporation. The scanner gantry has been rotated 90 ° so that the scan plane is horizontal. This enables the fluid displacements to be conducted in the vertical direction, minimizing gravity effects. The scanner gives a two millimeter thick, 512 × 512 pixel image across the scan plane. For the experiments presented here this gives a voxel size as small as 2 × 0.25 × 0.25 mm.
The majority of this work involves the study of two 4" diameter cores from heterogeneous carbonate formations. They were from the Fenn-Big Valley Field in Alberta, Canada and from the Taylor-Link Field in Pecos County, Texas, These cores were taken perpendicular to the bedding planes. Additional baseline porosity studies were performed with a 3" diameter outcrop of San Andres dolomite and 2" diameter samples of Berea and Boise sandstones. The San Andres outcrop sample was taken parallel to the bedding planes. The three carbonate cores and the Boise sandstone contained vugs that were visible to the eye. No macroscopic heterogeneities were observable in the Berea sandstone sample. The average porosity for each core is given below.
List of Average Porosity (Available In Full Paper)