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The transport of particles and fluids through multichannel microfluidic networks is influenced by details of the channels. Because channels have micro-scale textures and macro-scale geometries, this transport can differ from the case of ideally smooth channels. Surfaces of real channels have irregular boundary conditions to which streamlines adapt and with which particle interact. In low-Reynolds number flows, particles may experience inertial forces that result in trans-streamline movement and the reorganization of particle distributions. Such transport is intrinsically 3D and an accurate measurement must capture movement in all directions. To measure the effects of non-ideal surface textures on particle transport through complex networks, we developed an extended field-of-view 3D macroscope for high-resolution tracking across large volumes ($$25\,\hbox {mm} \times 25\,\hbox {mm} \times 2\,\hbox {mm}$$$25\text{mm}\times 25\text{mm}\times 2\text{mm}$) and investigated a model multichannel microfluidic network. A topographical profile of the microfluidic surfaces provided lattice Boltzmann simulations with a detailed feature map to precisely reconstruct the experimental environment. Particle distributions from simulations closely reproduced those observed experimentally and both measurements were sensitive to the effects of surface roughness. Under the conditions studied, inertial focusing organized large particles into an annular distribution that limited their transport throughout the network while small particles were transported uniformly to all regions.

Target subsurface reservoirs for emerging low‐carbon energy technologies and geologic carbon sequestration typically have low permeability and thus rely heavily on fluid transport through natural and induced fracture networks. Sustainable development of these systems requires deeper understanding of how geochemically mediated deformation impacts fracture microstructure and permeability evolution, particularly with respect to geochemical reactions between pore fluids and the host rock. In this work, a series of triaxial direct shear experiments was designed to evaluate how fractures generated at subsurface conditions respond to penetration of reactive fluids with a focus on the role of mineral precipitation. Calcite‐rich shale cores were directly sheared under 3.5 MPa confining pressure using BaCl₂‐rich solutions as a working fluid. Experiments were conducted within an X‐ray computed tomography (xCT) scanner to capture 4‐D evolution of fracture geometry and precipitate growth. Three shear tests evidenced nonuniform precipitation of barium carbonates (BaCO₃) along through‐going fractures, where the extent of precipitation increased with increasing calcite content. Precipitates were strongly localized within fracture networks due to mineral, geochemical, and structural heterogeneities and generally concentrated in smaller apertures where rock:water ratios were highest. The combination of elevated fluid saturation and reactive surface area created in freshly activated fractures drove near‐immediate mineral precipitation that led to an 80% permeability reduction and significant flow obstruction in the most reactive core. While most previous studies have focused on mixing‐induced precipitation, this work demonstrates that fluid–rock interactions can trigger precipitation‐induced permeability alterations that can initiate or mitigate risks associated with subsurface energy systems.

Fluid injection into rock formations can either produce complex branched hydraulic fractures, create simple planar fractures, or be dominated by porous diffusion. Currently, the optimum injection parameters to create branched fractures are unknown. We conducted repeatable hydraulic fracturing experiments using analog‐rock samples with controlled heterogeneity to quantify the fluid parameters that promote fracture branching. A large range of injection rates and fluid viscosities were used to investigate their effects on induced fracture patterns. Paired with a simple analytical model, our results identify the threshold at which fracture transitions from an isolated planar crack to branched cracks when closed natural fractures exist. These results demonstrate that this transition can be controlled by injection rate and fluid viscosity. In relation to the field practices, the present model predicts slickwater and lower viscosity fluid injections promote fracture branching, with the Marcellus shale used as an example.