Digital Rock Physics (DRP) has significantly evolved in the last few years and added invaluable contributions in improving core characterization and in providing high quality advanced SCAL measurements, emphasized through various studies (Al Mansoori et al., 2014 and Kalam et al., 2011).
This paper represents a unique DRP relative permeability SCAL study done on two plug samples from a carbonate reservoir in the Middle East. It outlines the DRP method used to determine the relative permeability curves including sub-sample selection, high resolution CT scanning (down to nano level), generation of the 3D rock models, and simulation of fluid flow displacements.
The paper will also discuss the power of pore scale imaging and how it helps in understanding macro property variations. The DRP results are comparable to the SCAL results of same formation of nearby fields and are currently being used for the Full Field simulation. The conclusions will be supported by a comparison with physical lab measurements that were done independently on samples of the same formation from the same well's core.
Such comparison will demonstrate the added value in using DRP, and will show the effectiveness of the technology in generating advanced SCAL data in a significantly shorter timeframe compared to conventional laboratory measurements.
Relative permeability (Kr) curves provide macroscopic description of the way in which two (or three) phases flow together locally in a porous medium (Honarpour et al., 1986 and 1995; Heaviside, 1991). Imbibition water-oil Kr data are critical in the evaluation and management of fields having natural water influx or having planned or actual water-flooding. However, high percentage of such laboratory measurements yields unrepresentative data that cannot be used in reservoir simulation models or as input for history matching of production profiles. In addition, the traditional laboratory evaluation methods may not be applicable to every testing condition or every type of reservoir rock and hence the continued development of laboratory methods is required to help characterize and understand challenging reservoir behaviors (Dernaika, 2010 and Serag et al., 2010).
Digital imaging technology has been extensively used in the petroleum industry to obtain fast and reliable core data from reservoir rock samples. The technology (Digital Rock Physics) has contributed reliably to reservoir core characterization through the application of Dual Energy X-ray CT Scanning (Walls and Armbruster, 2012 and Al-Owihan et al., 2014) and to the prediction of reservoir engineering quantities like capillary pressure and relative permeability through direct simulation into high resolution 3D images (Amabeoku et al., 2013, De Prisco et al., 2012, Mu et al., 2012 and Grader et al., 2010)
