Feali, Mostafa (U Of New South Wales) | Pinczewski, Wolf Val (U. of New South Wales) | Cinar, Yildiray (U. of New South Wales) | Arn, Christoph (U. of New South Wales) | Arns, Ji-Youn (Australian National Univ.) | Francois, Nicolas (Australian National Univ.) | Turner, Michael (Digital Core Laboratories Pty Ltd) | Senden, Tim | Knackstedt, Mark
It is now widely acknowledged that continuous oil spreading films observed in two-dimensional glass micro-model studies for strongly water wet three-phase oil, water and gas systems are also present in real porous media and result in lower tertiary gas flood residual oil saturations than for corresponding negative spreading systems which do not display oil spreading behavior. However, it has not been possible to directly confirm the presence of spreading films in real porous media in threedimensions and little is understood of the distribution of the phases within the complex geometry and topology of actual porous
media for different spreading conditions. This paper describes a preliminary study using high resolution X-ray microtomography to image the distribution of oil, water and gas after tertiary gas flooding to recover waterflood residual oil for two set of fluids, one positive spreading and the other negative spreading, for strongly water wet conditions in Bentheimer sandstone.
We show that for strongly water-wet conditions and a positive spreading system the oil phase remains connected throughout the pore space and results in a low tertiary gas flood residual oil saturation. The residual oil saturation for the corresponding negative spreading system is significantly higher and this is shown to be related to the absence of oil films in this system. The presence of films for positive spreading systems and the absence of such films for negative spreading systems is further confirmed by the computation of the Eurler characteristic for each phase.
Dehghan Khalili, Ahmad (U Of New South Wales) | Arns, Christoph Hermann (University of New South Wales) | Arns, Jiyoun (U. of New South Wales) | Hussain, Furqan (U. of New South Wales) | Cinar, Yildiray (U. of New South Wales) | Pinczewski, Wolf Val (Australian National University) | Latham, Shane (Saudi Aramco) | Funk, James Joseph
High-resolution Xray-CT images are increasingly used to numerically derive petrophysical properties of interest at the pore scale, in particular effective permeability. Current micro Xray-CT facilities typically offer a resolution of a few microns per voxel resulting in a field of view of about 5 mm3 for a 20482 CCD. At this scale the resolution is normally sufficient to resolve pore space connectivity and transport properties. For samples exhibiting heterogeneity above the field of view of such a single high resolution tomogram with resolved pore space, a second low resolution tomogram can provide a larger scale porosity
map. The problem then reduces to rock-typing the low resolution Xray-CT image, deriving viable porosity-permeability transforms from the high resolution Xray-CT image(s) for all rock types present, and upscaling of the permeability field to derive a plug-scale permeability.
In this study we characterize spatially heterogeneity using overlapping registered Xray-CT images derived at different resolutions spanning orders of magnitude in length scales. A 38mm diameter carbonate core is studied in detail and imaged at low resolution - and at high resolution by taking four 5mm diameter subsets, one of which is imaged using full length helical scanning. Fine-scale permeability transforms are derived using direct porosity-permeability relationships, random sampling of the porosity-permeability scatter-plot as function of porosity, and structural correlations combined with stochastic simulation. A range of these methods are applied at the coarse scale. We compare various upscaling methods including renormalization theory with direct solutions using a Laplace solver and report error bounds.
We find that for the heterogeneous samples permeability typically increases with scale. Conventional methods using basic averaging techniques fail to provide truthful vertical permeability due to large permeability contrasts. The most accurate upscaling technique is employing Darcy's law. A key part of the study is the establishment of porosity transforms between highresolution and low-resolution images to arrive at a calibrated porosity map to constraint permeability estimates for the whole core.