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Digital Rock in Heavy Oil
 
 Figure 1 Network-based multi-phase flow simulation (left) provides direct calculation of
 relative permeabilities and capillary pressures (right).
 
 Figure 2 Carbonate core (left) and features extracted from it (right).
 
 Figure 3 Medical X-ray CT scanner.

Digital rock technology obtains properties from high resolution images that show differences in the morphology and composition of rock. InnoTech Alberta combines X-ray scanning and digital imaging to provide insight into reservoirs on the pore scale. Unrestricted by the laboratory environment, this expertise challenges traditional testing by understanding pore spaces and their connectivity in 3D images. The primary goal is to supply the services of special core analysis (SCAL) through detailed images of cores rather than through actual core floods. Specifically, relative permeability and capillary pressure are predicted from fluid flow simulations based on high resolution 3D images of media. The standard analysis consists of network-based simulation of multi-phase fluid flow in the pore spaces and spatial averaging of the results to obtain macroscopic properties (Figure 1).

Digital rock examination allows the screening of multiple recovery scenarios involving changes to a reservoir that may affect production. The promise, ultimately, is for rapid, non-invasive characterization under a wide range of conditions. Extrapolation of conditions not attainable in a laboratory environment adds great value. InnoTech, with its heavy oil expertise and reputation for complex experimental capabilities, is working to extend the analysis to include behaviour in enhanced oil recovery (EOR) processes including the transport of heat, solvents, and chemicals.

Bitumen carbonate reservoirs lend themselves particularly well to investigation by digital rock technology, which provides new opportunities for evaluation and development of recovery processes. The growth in demand for these difficult, but lucrative, formations is well served by this capability as these types of reservoirs are often hard to analyze using other means. InnoTech has the ability to characterize morphology, providing distributions of pore sizes and 3D renderings of the pore structure using a specially developed segmentation process designed for carbonates (Figure 2).

InnoTech has access to four distinct methods of imaging with a range of resolutions. A whole core image in a medical scanner (Figure 3) is typically the first step in the process. The resulting series of slices is assembled to highlight the makeup of the rock. These data are then used to select plugs for closer examination with higher resolution imaging sources.

The options for higher resolution include micro X-ray CT with resolution down to a few microns, sufficient to view the pore space in typical reservoir sands; synchrotron CT, which allows us to see smaller pores and fluid interactions; and finally, Scanning Electron Microscopy (SEM). Combined with Focussed Ion Beam (FIB) milling, a sequence of SEM scans can be assembled into an extremely high resolution 3D image suitable for shales (Figure 4). These spatial imaging methods are supported by X-ray
Diffraction (XRD) analysis of mineral composition and Nuclear Magnetic Resonance (NMR)
analysis of pore size distributions (Figure 5).

   
 Figure 4 FIB-SEM image of a very tight shale sample.  Figure 5 NMR Pore size distribution (left) and synchrotron image (right) of a shale plug.

 

InnoTech leverages its established expertise in laboratory studies of heavy oil processes to add a novel dimension to digital rock – pore scale experimentation. Traditional etched glass micromodels , designed for visual observation of fluid-fluid interactions, are complemented by dynamic experiments in real media with full 3D imaging (Figure 6).

On the numerical side, current development includes the extraction of geomechanical properties by simulating discrete particle-particle interactions (Figure 7), using models of granular media obtained from imaging.

   
 Figure 6 Observing oil-water interactions in a 2D micromodel (left) and a laboratory sand pack, via synchrotron  imaging (right).  Figure 7 Simulated compaction of a packing of sand grains.

 

This is all part of an ongoing internal capability development program. The goal is to develop a complete package of pore scale investigative capabilities for heavy oil and EOR, analogous to our conventional laboratory scale facilities.

 

Put our expertise to work for you

Mike London
Senior Research Engineer
647.221.0984
mike.london@innotechalberta.ca

Shauna Cameron
Imaging Specialist
780.450.4601
shauna.cameron@innotechalberta.ca