Investigating flow properties of partially cemented fractures in Travis Peak Formation using image‐based pore‐scale modeling

Abstract

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.

Mineral Precipitation in Fractures: Using the Level‐Set Method to Quantify the Role of Mineral Heterogeneity on Transport Properties

“…Because mineral reactions occur fastest along fluid-rock boundaries with the largest reactive surface area (Weeks & Gilmer, 2007), fluid-rock reactions can lead to heterogeneous surface alterations that are not captured using a 1-D alteration approach. This is particularly important during mineral precipitation, where mineral deposition can lead to nonuniformly distributed, and arbitrarily oriented, cements that extend across the fracture aperture (Ankit et al, 2015;Kling et al, 2017;Tokan-Lawal et al, 2015). Recent numerical studies have employed different immersed boundary methods, such as the level-set method, to represent surface alterations in the direction normal to the fracture surface (e.g., Li et al, 2010;Molins et al, 2017;Soulaine et al, 2017;Yu & Ladd, 2010).…”

Computationally Efficient Multiscale Neural Networks Applied to Fluid Flow in Complex 3D Porous Media

“…We contrast the machine learning approach with classical method such as the cubic law (Tokan-Lawal et al 2015). For these synthetically created fracture, the cubic law would return a permeability value that depends only on the aperture size, whereas LBM data reveals that the roughness could influence the permeability by a factor of 3.…”

“…Despite the fact that there are many published analytical solutions and computational algorithms to obtain the permeability in a faster manner, they do not work well in the presence of strong heterogeneities associated with important geometries such as fractures (Tokan-Lawal et al 2015). This is partly due to the fact that most of these proposed solutions are computed based on averaged properties of the solid structure, such as the porosity and the tortuosity of the sample (Carman 1939(Carman , 1997Kozeny 1927;Bear 1972).…”

Minimum divergence viscous flow simulation through finite difference and regularization techniques

“…In the absence of enough computational power to carry the dynamic two phase flow simulations, treating one phase at a time in images like the ones in Figure 15, as it was the only fluid present in pore space, has been a common method in literature to estimate relative permeability curves [44,74,89]. However, we emphasize that this approach is used here as a preliminary step towards using FDM for multiphase fluid flow simulation.…”