Use of Imaging Techniques to Quantify Fluid-Rock Interaction and Petrophysical Properties in Low Permeability Hydrocarbon Reservoirs
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2018-11-01
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Abstract
Low permeability (‘tight’) reservoirs have become a viable source of hydrocarbons in North America because of horizontal drilling and multi-stage hydraulic fracturing. While commercial production continues for these unconventional resources, recovery of the available hydrocarbons (particularly liquids) remains low. This is due impart to the lack of understanding of the basic reservoir properties. Without advancing characterization methods for petrophysical and geomechanical properties, we can expect these inefficiencies in resource development to persist. This thesis begins to address this lapse in knowledge by using imaging techniques to quantify fluid-rock interaction and characterize petrophysical properties. In tight reservoirs, most of the hydrocarbon resource resides within the matrix nanopore structure. However, conventional characterization methods are not usually performed at this scale. Ultra-small-angle neutron scattering is employed to probe geological samples for determining the connected and unconnected porosity, including porosity at the nanoscale. This information can be used in tandem with 2D scanning electron microscope (SEM) images to populate pore network models which in turn are used to derive petrophysical properties. An important contribution of this thesis is the development of techniques to enable the imaging and quantification of wettability at the micro- and nanoscale. While imaging of rock nanopore pore structure is now routine, imaging of fluid-rock interaction at this scale, which is necessary for quantifying multi-phase fluid distribution and flow, is not. Using an environmental SEM, three approaches are employed: 1) condensation and evaporation, 2) cryogenic, and 3) micro-injection. Using a parametrized Young-Laplace model, contact angles (advancing/receding) and spontaneous imbibition rates are calculated. Fluid distributions in preserved core are determined. Macro- and micro-contact angles for the same sample are compared, revealing that contact angle variance in a small sample is large, even within sites a few millimetres apart. This suggests that macro-scale measurements do not appropriately capture the heterogeneity of low-permeability samples. Finally, using a combination of X-ray, SEM, and cathodoluminescence, a variety of rock petrophysical properties are determined from drill cuttings. Custom written software using advanced image processing techniques is used to automatically measure mineralogical composition, cementation, and porosity.
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Deglint, H. J. (2018). Use of Imaging Techniques to Quantify Fluid-Rock Interaction and Petrophysical Properties in Low Permeability Hydrocarbon Reservoirs (Doctoral thesis, University of Calgary, Calgary, Canada). Retrieved from https://prism.ucalgary.ca. doi:10.11575/PRISM/33240