Hydraulic fracturing is widely used to stimulate unconventional reservoirs, but a systematic and comprehensive investigation into the hydraulic fracturing process is rare. In this work, a discrete element-lattice Boltzmann method is implemented to simulate the hydro-mechanical behavior in a hydraulic fracturing process. Different influential factors, including injection rates, fluid viscosity, in-situ stress states, heterogeneity of rock strengths, and formation permeability, are considered and their impacts on the initiation and propagation of hydraulic fractures are evaluated. All factors have a significant impact on fracture initiation pressure. A higher injection rate, higher viscosity, and larger in-situ stress increase the initiation pressure, while a higher formation permeability and higher heterogeneity decrease the initiation pressure. Injection rates and heterogeneity degrees have significant impacts on the complexity of generated fractures. Fluid viscosity, in-situ stress states, and formation permeability do not change the geometrical complexity significantly. Hydraulic fractures are usually tensile fractures, but many tensile fractures also have shear displacement. Shear fractures are possible and the shear displacement can be significant under certain conditions, such as a high injection rate, and a high heterogeneity degree.

Lower-viscosity fluids are commonly believed to be able to create more complex fractures in hydraulic fracturing, however, the mechanism remains stubbornly unclear. We use a new grain-scale model with accurate coupling of hydrodynamic forces to simulate the propagation of fluid-driven fracturing. The results clarify that fracturing fluid with a lower viscosity does not always create more complex fractures. The heterogeneity in the rock exerts the principal control on systematic evolution of fracture complexity. In homogeneous rock, low viscosity fluids result in low breakdown pressure, but viscosity exerts little influence on fracture complexity. However, in heterogeneous rock, lower viscosity can lead to more complex network of fracturing. A regime map shows the dependence of fracture complexity on the degree of rock heterogeneity where low viscosity fracturing fluid more readily permeates weak defects and creates complex fracture networks.

The stochastic discrete fracture network (SDFN) model is a practical approach to model complex fracture systems in the subsurface. However, it is impossible to validate the correctness and quality of an SDFN model because the comprehensive subsurface structure is never known. We utilize a pixel-based fracture detection algorithm to digitize 80 published outcrop maps of different scales at different locations. The key fracture properties, including fracture lengths, orientations, intensities, topological structures, clusters and flow are then analyzed. Our findings provide significant justifications for statistical distributions used in SDFN modellings. In addition, the shortcomings of current SDFN models are discussed. We find that fracture lengths follow multiple (instead of single) power-law distributions with varying exponents. Large fractures tend to have large exponents, possibly because of a small coalescence probability. Most small-scale natural fracture networks have scattered orientations, corresponding to a small κ value (κ<3) in a von Mises–Fisher distribution. Large fracture systems collected in this research usually have more concentrated orientations with large κ values. Fracture intensities are spatially clustered at all scales. A fractal spatial density distribution, which introduces clustered fracture positions, can better capture the spatial clustering than a uniform distribution. Natural fracture networks usually have a significant proportion of T-type nodes, which is unavailable in conventional SDFN models. Thus a rule-based algorithm to mimic the fracture growth and form T-type nodes is necessary. Most outcrop maps show good topological connectivity. However, sealing patterns and stress impact must be considered to evaluate the hydraulic connectivity of fracture networks.

We have studied wettability effects on multiphase displacements in heterogeneous porous media by experiments on microfluidic chips. The developed experimental and analysis methods link pore-scale physics and macroscopic consequences. By varying fluid properties with a wide range of wettability, we find a non-monotonic wettability effect on displacement efficiency on heterogeneous structures, in contrast to a monotonic one on homogeneous matrix. For the flow on heterogeneous porous media, there is a critical wettability for the best displacement efficiency. Pore-scale mechanisms are identified to elucidate these behaviors: the cooperative pore filling in an intermediate water-wet condition cause the maximum displacement efficiency; the corner flow under a strong water-wet condition and Haines events under a strong oil-wet condition will decrease displacement efficiency. Our findings shed unique insights on how the interaction between fluid wettability and structure heterogeneity affects fluid displacement in porous media.

This contribution presents an early-time solution for permeability evaluation in pulse-decay tests. A nonlinear governing equation for gas transport in the sample is derived with consideration of the pressure dependence of gas compressibility and slippage effect, and the early-time solution is obtained through the integral balance analysis. The permeability coefficient can be determined by the proposed solution through the pressure transients within the early-time stage of the tests, i.e. before the upstream pressure pulse penetrates through the core sample and reaches the downstream side. To validate the proposed solution, measurements were performed on a core sample of the Cretaceous Eagle Ford shale, Texas, USA, under different pore and confining pressures. Helium was used as the test fluid to minimize the Joule-Thomson effect and adsorption. The experimental results show that the permeability coefficients obtained from this new solution agree well with those from the late-time solution, and prove our solution an accurate and efficient way for permeability evaluation. The present approach provides a good supplement for the pulse-decay method and suitable for measurements of ultra-low-permeability rocks.

T-type intersections are commonly observed in natural fracture networks. Their impacts on the connectivity and flow results in complex fracture networks are rarely investigated. In this work, we implement the discrete fracture network method to construct complex fracture networks, denoted as original fracture networks. By implementing the rule-based fracture growth algorithm, we generate the corresponding kinematic fracture networks with a substantial proportion of T-type intersections. The connectivity and flow results of both the single-phase and two-phase flow simulations in these two types of fracture networks are systematically investigated. The results show that kinematic fracture networks tend to connect more fractures with fewer intersections and yield better connectivity than the original ones. Most kinematic fracture networks have larger permeability in the single-phase flow simulation and higher cumulative gas production in the two-phase flow simulation than original fracture networks under the same boundary conditions. The proportions of permeability and production enhancement are 68\% and 77\%, respectively. Flow results, like the permeability and production, have strong positive correlations with the connectivity of the fracture networks, but they are nonequivalent and strongly impacted by the number of inlets and outlets.

Spontaneous imbibition of the injected fluid into the pore space of a tight oil reservoir and replacing the crude oil therein has been considered as one of the possible mechanisms in increasing oil recovery. Such deeply buried reservoir rocks is usually under high-pressure and high-temperature conditions. Besides, their interior complex porous structures are usually characterized as pore bodies and slit-shaped pore throats. As a result, an accurate description of the spontaneous imbibition behavior driven by capillary force in the real pore space under reservoir conditions is crucial to understand the process and uncover the controlling mechanisms. An improved multi-component pseudo-potential lattice Boltzmann method was developed to simulate the spontaneous imbibition behavior in a representative 3D pore space extracted from a tight sandstone reservoir rock. Comparison of the spontaneous imbibition behavior under ambient condition and reservoir condition showed that the latter case exhibited two times faster of the imbibition. Moreover, a snap-off of the oil droplet phenomenon was observed in the pore bodies surrounded by slit-shaped pore throats. The snap-off oil droplets stuck in the pore bodies and accounted for 9.47 % of the pore volume. These results indicated the importance of investigating the spontaneous imbibition in a real porous structure and under actual reservoir condition. The proposed pore-scale simulation method provides a useful tool in understanding the complex spontaneous imbibition pattern and the resulted enhanced oil recovery.

The pore network is an approximate representation of the void space of porous materials such as rocks and soil via pores (corresponding to large cavities) and throats (narrow constrictions). During extraction of networks from real void space, ambiguous definitions of pores and throats may cause significant errors in predictions of single/multi-phase transport properties. Meanwhile, the pore-throat segmentation needs to exclude non-physical parameters as much as possible. In this work, we propose a pore-throat segmentation method based on local hydraulic resistance equivalence between the real space and the pore-throat geometry. The pore-throat boundary is locally determined at the position where the pore network preserves the hydraulic resistance of the real space most. This local segmentation method ensures better equivalency between extracted pore-network and real pore space without any impirical and non-physical parameters. After validations of accuracy and reliability by standard benchmarks, this method is appled to real porous materials including spherical pack, sandpack, sandstone, and carbonate. The absolute permeability and relative permeability predicted by the new pore-network model (PNM) agree well with the experimental data and the direct simulation results. The proposed method improves the accuracy of PNM predictions significantly with only slight increases of computational costs. This local pore-throat segementation method may enhance capability of PNM and extend PNM to more complicated cases.