Natural fractures can provide preferred flow pathways in otherwise low‐permeability reservoirs. In deep subsurface reservoirs including tight oil and gas reservoirs, as well as in hydrothermal systems, fractures are frequently lined or completely filled with mineral cement that reduces or occludes fracture porosity and permeability. Fracture cement linings potentially reduce flow connectivity between the fracture and host rock and increase fracture wall roughness, which constricts flow. We combined image‐based fracture space characterization, mercury injection capillary pressure and permeability experiments, and numerical simulations to evaluate the influence of fracture‐lining cement on single‐phase and multiphase flows along a natural fracture from the Travis Peak Formation, a tight gas reservoir sandstone in East Texas. Using X‐ray computed microtomographic image analysis, we characterized fracture geometry and the connectivity and geometric tortuosity of the fracture pore space. Combining level set method‐based progressive quasistatic and lattice Boltzmann simulations, we assessed the capillary‐dominated displacement properties and the (relative) permeability of a cement‐lined fracture. Published empirical correlations between aperture and permeability for barren fractures provide permeability estimates that vary among each other, and differ from our results, vary by several orders of magnitude. Compared to barren fractures, cement increases the geometric tortuosity, aperture variation of the pore space, and capillary pressure while reducing the single‐phase permeability by up to 2 orders of magnitude. For multiphase displacement, relative permeability and fluid entrapment geometry resemble those of porous media and differ from those characteristic of barren fractures.

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Diagenetic changes (e.g. cementation, compaction) in tight gas sandstones (TGSS) often disconnect the original, inter-granular pore space and further create microporosity within the original grains (e.g. by dissolution) or by filling the inter-granular porosity with clay. A petrophysically rigorous fundamental model of TGSS that accounts for microporosity would make the evaluation, development and stimulation of tight gas sandstone development more robust. The reduced connectivity of matrix pores has a profound effect on transport properties such as absolute and relative permeability, resistivity and capillary pressure - saturation relationships. To address this, we construct networks that incorporate both inter-granular (primary) porosity and microporosity, and use a network model to estimate flow properties. We present algorithms to geometrically match pore throat networks from two separate length scales that can be extracted directly from 3D rock images, or be constructed to match the relevant measured properties. Microporosity and its spatial distribution have a profound effect on the relative permeability curve. When inter-granular network is disconnected (but the microporous region is not), we provide capillary pressure - saturation curves in cases thus far unresolved with any other type of modeling. The results from model media reasonably match published experimental data. While we are motivated by TGSS, with suitable characterization the model is applicable to other reservoirs with dominant microporosity component (shale, carbonates).

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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.