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Santos, Javier E. (The University of Texas at Austin) | Prodanovic, Masa (The University of Texas at Austin) | Landry, Christopher J. (The University of Texas at Austin) | Jo, Honggeun (The University of Texas at Austin)
Abstract Hydraulic fracturing techniques aim to create high conductivity channels through low permeability rocks, enhancing hydrocarbon flow to the wellbore. However, characterizing the reduction of mobility in fractures as a result of surface heterogeneities, has received limited attention. In this work, we study the effect of the heterogeneity in composition and roughness in flow through hydraulically induced fractures. Since analytical solutions are restricted to simple domains, a 3D direct simulation approach was selected. To assess these effects, domains exhibiting geometrical mineral arrangements, and self-affine fractures were created to carry out drainage and imbibition simulations. The relations of different wetting/non-wetting patterns and surface roughness, with interfacial areas, capillary pressure, and residual fluid saturation were quantified. We show that there is an effective mineral feature size related to the fracture dimensions that modifies the capillary pressure behavior. Similarly, the correlation range of the surface apertures determines the effect of the shape of a non-wetting front. Correspondingly, we found that for increasingly rough surfaces, there is a linear relation between the residual non-wetting saturation and capillary pressure with the aperture distribution. Thus, the shape, mineral size ratio, and surface roughness can have a significant effect on flow patterns. The results of this work can be used to improve macroscopic simulations, having a priori knowledge of the microscopic characteristics. 1. Introduction Open fractures in subsurface formations represent preferential channels for fluid flow. At the field scale, these geological elements are described using dual porosity/permeability continuum models (Bear, 1993). Fracture apertures and lengths span multiple orders of magnitude (Brown & Scholz, 1985; Gale et al., 2007), and while these models can work for larger scales, they are not applicable for characterizing flow at the pore scale. Such fractures, often partially lined with mineral cements, can have a large impact on flow in unconventional reservoirs (Gale et al., 2014). These features increase the complexity of the flow paths, yielding in errors when utilizing conventional solutions, by not accounting for different mineralogy (Iglauer et al., 2015) or phase trapping (Tokan-Lawal et al., 2014). However, presently we do not have enough pore scale studies to fully understand how flow processes act with the different heterogeneities present in natural fractures. The present work focuses on correlating different mineral arrangements, fracture aperture, and surface roughness for imbibition and drainage experiments.
Microfiuidics and nanofiuidics have been used in the oil and gas industry for pore-scale research experiments and as application-specific tools (such as lab-on-a-chip PVT analyzers). The former technology constructs pore and pore-network proxies on compact lab-on-a-chip devices. Such proxies are then used to investigate the impact of specifically tuned geometric and/or material variable(s) on fluid transport via direct observation with microscopy. This paper reviews micro/nanofluidics findings by the authors and other geoscience and general porous-media researchers. Findings are related to the impacts of pore size, surface chemistry (wettability), fluid type and composition, and surface texture (roughness) on fluid transport variables, such as effective viscosity, imbibition, capillary trapping, adsorption, and diffusive processes. For example, the authors’ microfluidic findings include a critical surface roughness value beyond which capillary trapping during drainage increases drastically due to changes in subporescale flow regimes. The authors’ nanofluidic findings include that the fluid polarity and surface chemistry of a silica nanoconfinement can lead to additional contactline friction that causes significant deviations from the continuum Washburn equation for imbibition; these effects can potentially be incorporated in the quantitative analysis through an increased effective viscosity. Finally, this review highlights practical approaches for using labon-a-chip devices and their associated pore-scale findings as diagnostic tools to augment petrophysical laboratory measurements and guide field-scale pilot operations.
Mostaghimi, Peyman (MUTRIS Research Group, School of Petroleum Engineering, The University of New South Wales) | Armstrong, Ryan T. (MUTRIS Research Group, School of Petroleum Engineering, The University of New South Wales) | Gerami, Alireza (MUTRIS Research Group, School of Petroleum Engineering, The University of New South Wales) | Hu, Yibing (MUTRIS Research Group, School of Petroleum Engineering, The University of New South Wales) | Jing, Yu (MUTRIS Research Group, School of Petroleum Engineering, The University of New South Wales) | Kamali, Fetemeh (MUTRIS Research Group, School of Petroleum Engineering, The University of New South Wales) | Liu, Min (MUTRIS Research Group, School of Petroleum Engineering, The University of New South Wales) | Liu, Zhishang (MUTRIS Research Group, School of Petroleum Engineering, The University of New South Wales) | Lu, Xiao (MUTRIS Research Group, School of Petroleum Engineering, The University of New South Wales) | Ramandi, Hamed L. (MUTRIS Research Group, School of Petroleum Engineering, The University of New South Wales) | Zamani, Ali (MUTRIS Research Group, School of Petroleum Engineering, The University of New South Wales) | Zhang, Yulai (MUTRIS Research Group, School of Petroleum Engineering, The University of New South Wales)
Abstract Coal seam gas is an unconventional resource for natural gas that is becoming popular due to its environmental benefit and abundance. This paper reviews recent developments on the pore-scale characterisation of coal from coal seam gas reserviors. The development of micro-computed tomography (micro-CT) imaging has enabled for the 3D characterization of the fracture system in coals. This provides detailed insights into understanding flow in these unconventional reservoirs. A novel image calibration method in which the skeleton of the fracture system is obtained from micro-CT imaging while the fracture apertures are measured from scanning electron microscopy (SEM) is described. We also show the application of micro-CT imaging for studying diffusion processes in ultralow permeability matrices and discuss the incorporation of the data into calculations of gas production from unconventional reservoirs. The extraction of statistical information from micro-CT images to reconstruct coal cleat system are also demonstrated. This technique allows for preserving the key attributes of the cleat system while the generated fracture network is not limited in terms of size nor resolution. The developments of microfluidic methods for understanding the complex displacement mechanisms in coal seams are also described. These low-cost experimental methods can provide unique information about the displacement mechanisms occurring during gas production from coal seam reservoirs. Variation of coal contact angle with pressure is analysed and results demonstrate important wettability processes that occur in coal seams. We describe numerical methods for prediction of petrophysical properties from micro-CT images of coal and discuss the associated limitations when dealing with coal samples. The paper concludes by addressing the challenges faced when characterising coal at the micro-scale and approaches for population of coal data into reservoir simulators for relaible prediction of reservoir behaviour during gas production as well as CO2 sequestration in coalbeds.
Natural fractures in unconventional reservoirs are characteristically filled or lined with mineral cement. Despite the significance of natural fractures for stimulation and production, the effect of cement linings on fracture fluid flow is poorly understood. In this work, we focus on correlating permeability with geometric tortuosity of both pore (fracture) space and individual fluid phases for fractured Torridonian Sandstone, an outcrop analog for tight sandstone reservoirs. The input geometries for simulation are binarized, high-resolution microtomography images at two different resolutions. We use a combination of lattice-Boltzmann simulation and the level-set-method-based progressive-quasistatic (LSMPQS) algorithm to characterize the capillary dominated displacement properties (capillary pressure-saturation and relative permeability-saturation relationships) of the natural, partially cemented fractures within. We also use image analysis to characterize the connectivity and tortuosity of the pore space, as well as individual fluid phases at different saturations.
The partially cemented fractures of the Torridonian Sandstone are found to be very constricted, with many crystals bridging across the fracture but keeping large portions open to flow. The adjacent matrix, however, is almost completely cemented. We compare the tortuosity distribution in the Torridonian Sandstone with those in other porous media. We find that the fractures have considerably narrower tortuosity distribution when compared to other porous materials. Despite their cement lining, these fractures provide the most direct path across the material. In addition, we find that tortuosity in both consolidated porous media and partially cemented fractures increases with an increase in the amount of carbonate or quartz overgrowth cement. When analyzing tortuosity of different fluid phases, we find very weak correlation between fluid phase tortuosity and relative permeability. Relative permeability correlations and capillary pressure curves found here can be used in reservoir simulators to model recovery of hydrocarbons in fractured tight reservoirs.
Tokan-Lawal, Adenike (University of Texas at Austin) | Prodanovic, Masa (University of Texas at Austin) | Landry, Christopher J. (University of Texas at Austin) | Eichhubl, Peter (University of Texas at Austin)
Summary Natural fractures provide preferential pathways for fluid migration, and their effect is especially high in rocks with low matrix permeability. These fractures are usually lined or completely filled with mineral cement. The presence of cement can hinder the connectivity between residual fracture pores, thereby reducing fracture permeability. In order to better understand fluid transport in the Niobrara Formation, we studied the influence of cementation on flow in the fracture. We acquired the fracture geometry from x-ray microtomography (CT) scans, capturing the small-scale roughness of the mineral-lined fractures. The permeability and tortuosity of the fracture profile were determined from simulations of fluid flow through these geometries with impermeable fracture walls. We used a combination of the level-set-method-based progressive-quasistatic algorithm (LSMPQS software), and Lattice Boltzmann simulation to characterize the capillary-dominated displacement properties and the relative permeability of the naturally cemented fractures. Finally, we numerically investigated the effect of increasing cement layer thickness on the fracture permeability as well as the tortuosity of the pore space and the capillary pressure-water saturation (Pc-Sw) relationship. Pore space tortuosity and capillary pressure as a function of water saturation both increase with the numerically simulated increase in thickness of the fracture cement layer. Even when there are no cement contact points or bridges in the original fracture volume, numerical fracture cementation creates unevenly distributed apertures and cement contact points. This in turns causes the wetting and non-wetting fluids to impede each other, with no consistent trends in relative permeability with increasing saturation.