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Fractured karstic carbonate reservoirs have obvious multi-scale characteristics and severe heterogeneity due to the development of abundant karst caves and fractures with different scales. Darcy and non-Darcy flows coexist due to this property. Therefore, selecting the appropriate flow equations for different regions in the numerical simulation of fluid flows, particularly two-phase and multiphase flows, is a critical topic. This paper compares and analyses the displacement distance differences of waterfront travel using the Darcy, Forchheimer and Barree–Conway equations, as well as analyzes the influence of the Forchheimer constant, fluid viscosity, flow rate and absolute permeability on inertia action based on the Buckley–Leverett theory. The results show that the Forchheimer number/Reynolds number of water/oil two-phase flow is not a constant value and varies with water saturation, making it difficult to determine whether the inertial action should be considered solely based on these values; the influence of inertial action can be measured well by comparing the difference between the displacement distances of the waterflood front, and the quantitative standard is given for the selection of the flow equation of different regions by calculating the allowable error of the displacement distance of the waterflood front. The magnitude of the inertial effect is affected by the physical properties of the fluid and reservoir medium and the fluid velocity. The smaller the difference in the viscosity of the oil/water fluid, the smaller the inertial effect is. This technique was used a preliminary attempt to analyze the fractured karstic carbonate reservoirs at Tarim, and the results confirmed the validity of the method described in this article. [ABSTRACT FROM AUTHOR]

Using abandoned gas wells as geothermal resources for energy production is an effective way to extract geothermal energy from geological formations. These abandoned wells have the potential to significantly contribute in the rising global demand for energy without requiring the land disruption resulting from deep drilling or digging, processes necessary for energy extraction from geological formations via more traditional methods. In this paper, a method to extract geothermal energy from abandoned gas wells is proposed. The method offers an efficient, economical, and environmentally-conscious way to generate electricity. A mathematical model of a thermal and hydraulic coupling process is constructed, and a 3D numerical model is generated to study the process of geothermal energy extraction by retrofitting an abandoned gas reservoir into a geothermal reservoir. Using the model, heat extraction and fluid flow are analyzed over a period of 50 years. The heat production, electricity generation, and thermal recovery over the lifetime of the reservoir indicate that a commercially viable geothermal dual well system can produce geothermal energy effectively. Dual-well systems contain at least one injection well and one production well. They are composed of a two-way flow system in which the fluid flows into the reservoir via an injection well and returns from the production well having absorbed thermal energy from the surrounding rocks. Sensitivity analysis of the main parameters controlling the average outlet temperature of the fluid from the sedimentary geothermal system reveals that abandoned gas wells are a suitable source of geothermal energy. This energy can be harvested via a method whose use of reservoir fluids differs from that of the traditional method of closed-loop circulation via a borehole heat exchanger. Here, it is demonstrated that abandoned oil and gas fields can be repurposed to be geothermal energy sources that provide low-cost electricity and are economically sustainable. [ABSTRACT FROM AUTHOR]

In this paper we propose a modified multiscale finite element method for nonlinear flow simulations in heterogeneous porous media. The main idea of the method is to use the global fine scale solution to determine the boundary conditions of the multiscale basis functions. When solving the time-dependent problems, the equations of standard MsFEM need to be solved many times for different pressure profiles. Then, we propose an adaptive criterion to determine if the basis functions need to be updated. The accuracy and the robustness of the modified MsFEM are shown through several examples. In the first two examples, we consider single phase flow in consideration of pressure sensitivity and unsaturated flow, and then compare the results solved by the finite element method. The results show that the multiscale method is accurate and robust, while using significantly less CPU time than finite element method. Then, we use the modified MsFEM to compute two phase flow in low permeability reservoirs. The results show that the greater the staring pressure gradient is, the greater the pressure drop is, and the greater the staring pressure gradient is, the smaller the swept area is. All the results indicate that modified the MsFEM offers a promising path towards direct simulation of nonl-linear flows in porous media. [ABSTRACT FROM AUTHOR]

The existence of a TPG can generate a relatively high pressure gradient in the process of fluid flow in porous media in low-permeable reservoirs, and neglecting the QPGTs in the governing equations, by assuming a small pressure gradient for such a problem, can cause a significant error in predicting the formation pressure. Based on these concerns, in consideration of the QPGT, a moving boundary model of radial flow in low-permeable reservoirs with the TPG for the case of a constant flow rate at the inner boundary is constructed. Due to strong nonlinearity of the mathematical model, a numerical method is presented: the system of partial differential equations for the moving boundary problem is first transformed equivalently into a closed system of partial differential equations with fixed boundary conditions by a spatial coordinate transformation method; and then a stable, fully implicit finite difference method is used to obtain its numerical solution. Numerical result analysis shows that the mathematical models of radial flow in low-permeable reservoirs with TPG must take the QPGT into account in their governing equations, which is more important than those of Darcy’s flow; the sensitive effects of the QPGT for the radial flow model do not change with an increase of the dimensionless TPG. [ABSTRACT FROM AUTHOR]

This study presents droplet dynamics in a rough capillary channel. Prior studies investigating the effect of roughness on fluid flow have mainly considered a continuous phase whose behavior is different from a discontinuous phase, i.e., an oil slug. To explore the dynamic behavior of droplet motion across a rough channel, a direct numerical simulation of in a three-dimensional channel is performed. Three models have been considered: model A had a rough surface only on the bottom walls, model B on both the bottom and top walls, and model C on all walls. The results show that in contrast with common observations, roughness promotes droplet mobility in comparison with smooth walls. The presence of roughness results to an additional energy required to move the droplet, and the degree of confinement increases with the roughness; thus, the difficult of mobilization increases with the increase in roughness. Different roughness parameter effects have been investigated. The results have shown that the critical pressure increases with the increase in the pillar's height and decreases with the pillars spacing. The offset leads to a decrease in flow resistance for larger contact angles. We noted also that it is more difficult to mobilize a discontinuous phase in a neutral-wet surface condition. Furthermore, discontinuous pillars in the lateral direction led to much higher resistance. Through our comprehensive numerical study, we provide valuable insights into the impact of roughness in capillary channels. These findings can be used as guidelines for designing droplet flow on complex and rough surfaces, such as microfluidic devices, and hold significant relevance in the optimization of droplet control strategies in enhanced oil recovery methods. [ABSTRACT FROM AUTHOR]

Summary: Hydraulic‐fracturing treatments have become an essential technology for the development of deep hot dry rocks (HDRs). The deep rock formation often contains natural fractures (NFs) at micro and macroscales. In the presence of the NF, the hydraulic‐fracturing process may form a complex fracture network caused by the interaction between hydraulic fractures and NF. In this study, analysis of carbon dioxide (CO2)‐based enhanced geothermal system (EGS) and water‐based EGS in complex fracture network was performed based on the thermo‐hydro‐mechanical (THM) coupling method, with various rock constitutive models. The complexity of the fracture geometry influences the fluid flow path and heat transfer efficiency of the thermal reservoir. Compared with CO2‐based EGS, water‐based EGS had an earlier thermal breakthrough with a rapid decline in production temperature. CO2 can easily gain heat rising its temperature thus reducing the effect of a premature thermal breakthrough. Both CO2‐based EGS and water‐based EGS are affected by in‐situ stress; the increase in stress ratio improved the fracture permeability but resulted in an early cold thermal breakthrough. When the same injection rate is applied to water‐based EGS and CO2‐based EGS, water‐based EGS displayed higher injection pressure buildup. Water‐based EGS had higher reservoir deformation area than CO2‐based EGS, and thermoelastic constitutive model for water‐based EGS showed larger deformed area ratio than thermo‐poroelastic rock model. Furthermore, higher values of rock modulus accelerated the reservoir deformation for water‐based EGS. This study established a novel discussion investigating the performance of CO2‐based EGS and water‐based EGS in a complex fractured reservoir. The findings from this study will help in deepening the understanding of the mechanisms involved when using CO2 or water as a working fluid in EGS. [ABSTRACT FROM AUTHOR]

In this paper, a multi-relaxation-time lattice Boltzmann (LB) model for nanoscale liquid flow is established to investigate the liquid flow characteristics in nanoporous media. The slip length and effective viscosity obtained by molecular dynamics (MD) simulations are adopted to account for the nanoscale effect. First, the LB model for water flow in nanopores is built and water flow characteristics in nanoporous media are investigated. The fluid-solid interaction force shows significant influence on water flow in nanoporous media. The water flux through nanoporous media increases with the decrease of fluid-solid interaction force. In hydrophobic nanoporous media, the nanoscale effect can decrease the gap between water flow resistance in large pores and that in small pores, making the velocity distribution more uniform. In addition, the end effect caused by the bending of streamlines can induce significant additional flow resistance. Neglecting the end effect can greatly overestimate water flow ability. The pore structure also has significant influence on water flow in nanoporous media. With the increase of specific interfacial length, the nanoscale effect increases. Finally, the LB model for oil (octane) flow in quartz nanopores is also established by incorporating the MD simulation results. Oil flow simulation in quartz nanoporous media shows that the conclusions obtained for water flow are also applicable for oil flow. [ABSTRACT FROM AUTHOR]

Conditions of release of trapped droplets in constricted channels are of great significance in various domains, including microfluidic development and enhanced oil recovery. In our previous studies, a detailed and quantitative analysis of the threshold pressure needed to release a droplet from a constricted channel has been performed. However, droplets may exist in real applications as long droplets, which may exhibit different behavior than finite droplets. Therefore, in this study, direct numerical simulations, combining the fluid flow equations and the phase-field method, have been conducted on three-dimensional constrained channels to investigate discrepancies in release conditions of finite droplets and long droplets. The results have shown that for a finite droplet, the maximum pressure increases with the increase in the contact angle, whereas for a long droplet, the maximum pressure is almost the same both in the water-wet and neutral-wet conditions. Effects of droplet size on the release pressure have also been studied. For the finite droplet and at the water-wet condition (θ = 45°), the minimum release pressure increases linearly with the droplet length, while for the long droplet at similar conditions, the minimum release pressure does not change much as the length of the droplet increases. Furthermore, the release pressure decreases with the increased tapering angle. [ABSTRACT FROM AUTHOR]

The purpose of this investigation was to document and understand the tribo-corrosive wear of AISI 316 (UNS S31600) stainless steel under high-speed jet impingement by a sand–liquid, two-phase flow. Wear was determined by weight-loss, the surfaces were characterized, and electrochemical measurements were also performed. Two different types of sands, silica sand and sea sand, were used in the experiments to investigate the effects of working time and chloride ions (from the sea sand). The cumulative weight-losses of the specimens increase with time. Upon the effect of particle size on weight-loss, it is found that the weight loss caused by the smallest particles, over a three hour time increment, decreases more slowly than that from other-sized particles. In addition, the weight-losses of the specimens increase with decreasing impact angle. Erosion from flowing sea sand caused more weight-loss than from flowing silica sand. From electrochemical measurements, the specimen impinged at a moderate angle (60°) shows the best corrosion resistance. The specimens subjected to flowing sea sand had worse corrosion resistance than those subjected to flowing silica sand. The specimen impinged by short time represents a passivation process on the anodic polarization behavior, but the passivation disappears on the specimen impinged by long time. [ABSTRACT FROM AUTHOR]

Rock yielding may well take place during hydraulic fracturing in deep reservoirs. The prevailing models based on the linear elastic fracture mechanics (LEFM) are incapable of describing the evolution process of hydraulic fractures accurately. In this paper, a hydro-elasto-plastic model is proposed to investigate the hydraulic fracture propagation in deep reservoirs. The Drucker–Prager plasticity model, Darcy's law, cubic law and cohesive zone model are employed to describe the plastic deformation, matrix flow, fracture flow and evolution of hydraulic fractures, respectively. Combining the embedded discrete fracture model (EDFM), extended finite element method (XFEM) and finite volume method, a hybrid numerical scheme is presented to carry out simulations. A dual-layer iterative procedure is developed based on the fixed-stress split method, Picard iterative method and Newton–Raphson iterative method. The iterative procedure is used to deal with the coupling between nonlinear deformation with fracture extension and fluid flow. The proposed model is verified against analytical solutions and other numerical simulation results. A series of numerical cases are performed to investigate the influences of rock plasticity, internal friction angle, dilatancy angle and permeability on hydraulic fracture propagation. Finally, the proposed model is extended to simulate multiple hydraulic fracture propagation. The result shows that plastic deformation can enhance the stress-shadowing effect. [ABSTRACT FROM AUTHOR]

Due to the low permeability of tight reservoirs, throats play a significant role in controlling fluid flow. Although many studies have been conducted to investigate fluid flow in throats in the microscale domain, comparatively fewer works have been devoted to study the effect of adsorption boundary layer (ABL) in throats based on the digital rock method. By considering an ABL, we investigate its effects on fluid flow. We build digital rock model based on computed tomography technology. Then, microscopic pore structures are extracted with watershed segmentation and pore geometries are meshed through Delaunay triangulation approach. Finally, using the meshed digital simulation model and finite element method, we investigate the effects of viscosity and thickness of ABL on microscale flow. Our results demonstrate that viscosity and thickness of ABL are major factors that significantly hinder fluid flow in throats. [ABSTRACT FROM AUTHOR]

• The presence of solid beds in turbulent pipe flows results in secondary fluid motions which impacts particle transport dynamics. • Streamwise vorticity due to corners in the cross-sectional plane of pipes is increased as the pipe bed height increases. • Particles are influenced by the secondary flows, with particles in a half-pipe less likely to concentrate near the upper walls. • The secondary flows also modify the deposition and resuspension rates of particles, particularly near the corners of the bed. Turbulent particle-laden flows in pipes can result in particle deposition leading to the formation of solid beds. The presence of such beds modifies the flow field, resulting in secondary motions in the plane of the pipe cross-section, which in turn impact particle transport. In this work turbulent pipe flows with equal mass flow rates and solid beds of height H b = 0 (full pipe), 0.5 R (three-quarter pipe), and R (half pipe) are predicted using direct numerical simulation, with the beds represented simplistically as flat surfaces. The particulate phase is one-way coupled to the flow at a volume fraction of 10−3 and particle motion is solved for using a Lagrangian point-particle approach. The Reynolds numbers computed based on bulk velocity and equivalent pipe diameter for the full, ¾ and, ½ pipes are 5,300, 5,909 and 7,494, respectively. The same particle size is used in all the simulations and their respective Stokes numbers, based on the shear timescale, are 0.5, 1.2 and 1.9, respectively. The results for flows with beds show that the fluid flow exhibits secondary vortices and an increase in the mean streamwise vorticity caused by corners in the cross-sectional plane of the pipes, with their intensity near the upper curved wall increasing with H b. However, the upper vortices remain relative weak compared to those in lower regions of the pipes. The increase in mean streamwise vorticity in the half pipe is larger than that in the three-quarter pipe near the upper curved wall, while similar near the flat pipe floor due to the resistance of the curved wall to secondary motions. The movement of the particles in the cross-sectional plane is consistent with that of the secondary flows, but with slightly lower velocities. In regions near the wall away from the pipe corners, particle concentration in the half pipe is lower than in the three-quarter pipe, most likely due to its thinner boundary layer. This is reversed for concentration maxima near the pipe corners because of the magnitude of the secondary flows. Finally, the secondary flow changes the deposition or resuspension rate of the particles, particularly near the pipe corners, but these are always less than equivalent rates in the full pipe flow, which is likely caused by the magnitude of the wall unit. [Display omitted] [ABSTRACT FROM AUTHOR]

The previous neglect of shale oil multi-component characteristics and the nanpore wall properties of real shale result in an insufficient understanding of shale oil flow mechanisms in nanopores. Meanwhile, research on the flow regimes of shale oil remains lacking. In this study, molecular dynamics simulations are employed to investigate the flow of shale oil in hydroxylated quartz nanopores and rough kerogen nanopores. Simulation results show that the flow regime changed as the pressure gradient (∇ p) increased to a critical value (∇ p c). The velocity profile was parabolic when ∇ p < ∇ p c , but gradually became piston-like when ∇ p ≥ ∇ p c. Because increasing ∇ p leads the adsorbed molecules desorbing, aggregating in the pore center, and forming clusters that are not easy to shear. Increasing vertical force from pore wall causes fluid aggregation in the pore center as ∇ p increases. The ∇ p c in kerogen nanopores is larger than that in quartz nanopores due to the rough kerogen surface and sticky layers. Multi-component fluids have higher ∇ p c than single-component fluids in quartz nanopores. However, they have the same ∇ p c in kerogen nanopores due to the rough kerogen surface. This investigation can provide theoretical basis for high-efficient production of shale oil. [Display omitted] • The flow regime of multicomponent shale oil in rough nanochannels was studied by MD. • Critical pressure gradients exist for fluid flow regime transitions in nanopores. • Determined governing factors of velocity profile changing from parabola to piston. • Determined governing factors of critical pressure gradients. [ABSTRACT FROM AUTHOR]

Two-phase flow in fractured and karstified porous media subject to coupled hydro-mechanical conditions is an important issue for oil recovery in carbonate reservoirs. However, due to the co-existence of porous media flow, fracture flow and free flow, as well as their couplings with geomechanical deformation, modeling the behavior of fractured karst systems remains challenging. In this work, a novel coupled hydro-mechanical model for simulating the complex behavior of fractured and karstified porous media is developed. Two-phase Darcy's equation is used to describe fluid flow in both matrix and fractures, while the free flow in cavities is considered based on an assumption of phase instantaneous gravity segregation. A modified Barton-Bandis's constitutive model is used to mimic the nonlinear fracture deformation. The cavity deformation is solved based on the fluid pressure on the cavity boundaries. A mixed finite volume-finite element method and a fixed-stress iterative splitting method are adopted to numerically solve the coupled system of equations. The model is then applied to a series of 2D and 3D problems to unravel the impacts of fractures and cavities on two-phase flow and geomechanical deformation in fractured karst systems. The results indicate that cavities hinder water breakthrough due to storage effects, while water may quickly migrate through highly conductive fractures. Cavities tend to dominate the flow and mechanical processes even though fractures are present as well. Significant stress concentration is observed around cavities. Furthermore, the results of 3D cases imply that phase gravity segregation in cavities leads to lower water saturation in the area above cavities and delays water breakthrough. [ABSTRACT FROM AUTHOR]

In this study we propose a novel phase field based discrete fracture model (PFDFM) to simulate fluid flow in fractured porous media. The common discrete fracture models represent fractures by sharp topology in an explicit way, regardless of using conforming or non-conforming mesh. Inspired by the definition of crack phase field, the sharp fracture topology is treated as a diffusive one in the solution of fluid flow problems, and the integration of fluid flow equation over fractures can be transformed to the one over the matrix. The algorithm to determine the fracture phase field and finite element discretization have been described in detail. The performance of the proposed method is validated against the classic discrete fracture model on several numerical cases in both two and three dimensions. We further investigate the convergency behavior of the proposed method through sensitivity analysis to mesh resolution and fracture parameters. Numerical results are obtained, which demonstrates that the proposed method is accurate, convergent and quite promising for simulating fluid flow in fractured porous media. • A novel phase field based discrete fracture model is proposed for fracture flow. • The sharp fracture is represented by a diffusive topology with phase field. • Non-conforming mesh is used in comparison with classical discrete fracture model. • It is quite promising for solving coupled fluid flow and mechanics problems. [ABSTRACT FROM AUTHOR]

In practical development of unconventional reservoirs, fracture networks are a highly conductive transport media for subsurface fluid flow. Therefore, it is crucial to clearly determine the fracture properties used in production forecast. However, it is different to calibrate the properties of fracture networks because it is an inverse problem with multi-patterns and high-complexity of fracture distribution and inherent defect of multiplicity of solution. In this paper, in order to solve the problem, the complex fracture model is divided into two sub-systems, namely "Pattern A" and "Pattern B." In addition, the generation method is grouped into two categories. Firstly, we construct each sub-system based on the probability density function of the fracture properties. Secondly, we recombine the sub-systems into an integral complex fracture system. Based on the generation mechanism, the estimation of the complex fracture from dynamic performance and observation data can be solved as an inverse problem. In this study, the Bayesian formulation is used to quantify the uncertainty of fracture properties. To minimize observation data misfit immediately as it occurs, we optimize the updated properties by a simultaneous perturbation stochastic algorithm which requires only two measurements of the loss function. In numerical experiments, we firstly visualize that small-scale fractures significantly contribute to the flow simulation. Then, we demonstrate the suitability and effectiveness of the Bayesian formulation for calibrating the complex fracture model in the following simulation. [ABSTRACT FROM AUTHOR]

• A model of incipient karst formation in realistic fracture networks is proposed. • Two distinctive dissolution behaviors are related to two types of flow organization. • If flow is normal to persistent fractures, the positive feedback loop is periodically interrupted. • Relation between karst models based on dissolution and generic growth kinetics is discussed. Karst features in limestone aquifers often exhibit highly heterogeneous patterns, which are strongly governed by structural complexities such as the spatial distribution and organization of fractures in natural carbonate rocks. However, until now, little is known about the impact of structural complexity on karstification processes. In this paper, we use numerical models to investigate how structural heterogeneity affects the generation of incipient karst in natural fractured systems. We develop a numerical model which couples the processes of fluid flow, mass transport and dissolution kinetics that govern the growth of fracture aperture, based on discrete fracture networks. We apply the model to simulate conduit evolution in a natural joint network that displays a distinctive topological pattern. A wide range of hydraulic gradient and initial fracture aperture is considered. Our results show that the network topology may generate a significant impact on dissolution pattern depending on how flow is organized within the discrete network. If a channelized structure occurs in the flow network, the dissolution pattern depends highly on the initial hydrogeological settings, while if the flow network consists of branched segments, a similar dissolution pattern emerges for a broad range of initial hydrogeological settings. When the flow direction is normal to the persisting fracture orientation, intermittent interruptions to the positive feedback process between flow and dissolution occur. Therefore, the breakthrough is delayed. We discuss the link between our results of dissolution modeling in fracture networks to previous modelling efforts in the context of single rough fractures and fracture network formed by orthogonal fracture sets. [ABSTRACT FROM AUTHOR]

Solving Navier-Stokes equations for pore-scale porous media flows (PSPMFs) based on imaging data has attracted increasing attention in the community of porous media flows due to a variety of application needs. However, the existing numerical approach is laborious, complex, and error-prone utilizing an ad-hoc coalition of software packages. The multidisciplinary tasks of image processing, computational fluid modeling, and high performance computing together with their integration is overwhelming. We present a unique and powerful computational platform, for PSPMFs with physical and computational advantages. This systematic method is featured with (1) unified mesoscopic modeling, (2) GPU (Graphic Processing Units) parallel computing, and (3) pore-structure upscaling. The multidisciplinary tasks are innovatively integrated into one computational setup thus no software coalition is needed. We use lattice Boltzmann method (LBM) to solve the level-set equation and NS equations successively, thus image segmentation and computational fluid dynamics are seamlessly connected avoiding extra grid and mesh generation or data transfer. The unified LBM modeling enables high efficient GPU parallelism for scalable acceleration. Meanwhile, a new pore-structure upscaling scheme is developed and integrated into downscale the fine grid mesh in the premise of ensuring accuracy. Two application studies demonstrate the reliability, feasibility, and efficiency of this method for PSPMFs. It is believed to be the first-ever integrated and accelerated computational package for studying PSPMFs and it is sustainable. We will introduce more physical models such as interfacial dynamics for multiphase flows, fluid–structure interaction for deformable pore structure, non-Newtonian effects, etc. in the near future. Meanwhile, parallelism based on multiple GPU cards for further acceleration is being investigated. [ABSTRACT FROM AUTHOR]

Fracture penetration or deflection may occur when the hydraulic fracture approaches weak interface in multi-layered formation. However, the intrinsic mechanism of fracture propagation pattern remains unclear. A model was presented to investigate hydraulic fracture propagation in multi-layered formation via the phase field method. The interface is explicitly represented by a weak thin layer. Fluid flow in the fractured media was modeled by using the indicator function of phase field. The iterative algorithm was described and validated against the benchmark cases. Simulation results show that the evolution of injection pressure is more complex when the fracture deflects than that when the fracture penetrates the interface. The fracture is prone to penetrate the softer layer the perforated layer while deflects to the interface if the adjacent layer is stiffer. Decreasing the modulus ratio of interface to layers promotes the fracture deflecting to the interface, while increasing the stress ratio contributes to the fracture penetrating the interface. The stacking mode of layers greatly affects the fracture propagation morphology in three or more layered formations. Rock heterogeneity doesn't alter the fracture propagation pattern as a whole, but it affects the local fracture morphology. The results provide a cloud chart of the relationship between fracture propagation pattern and controlling factors for the potential of field application. [ABSTRACT FROM AUTHOR]

Because the fractures in fractured reservoirs have a significant effect on the flow behavior of fluid, the production performance of the fractured reservoirs contains important information of the distribution of fractures. That is the basic principle of applying the production information for the inversion of fractures. It is the first step to link the distribution information of fractures with the production information to establish inversion objective function on the basis of Bayesian theory. And the geometric parameters of fractures such as midpoint coordinate ( x 0 , y 0 ) , azimuth α and extension length L which directly determine the distribution of fractures and then affect the flow behavior are chosen as inversion parameters and some production data are chosen as inversion indexes. Secondly, in order to reconcile the demand of reflecting the flow effect of individual fractures and the use of mature simulators, equivalent continuous medium model whose equivalent permeability tensor is a crucial parameter reflecting the flow behavior of fractured porous media is applied for calculating the numerical simulation of the fractured reservoirs. Finally, SPSA algorithm is adopted to minimize the inversion objective function and then update the distribution of fractures to obtain the optimal results. Theoretical cases verify that the inversion method is effective to identify fractures while the number of identified fractures is limited because of the multi-solution of the inverse problem. [ABSTRACT FROM AUTHOR]

• Coupled porous media and free flow model of fluid flow in fractured karst reservoirs. • Analytical expression of connectivity for discrete fracture-cave networks. • Flow channeling dominated by network connectivity. • Permeability scaling with connectivity in a power law for connected systems. Fractured karst reservoirs play a significant role in hydrocarbon reserves and groundwater storage. They often exhibit complex multiscale heterogeneities involving pores, fractures and caves, whose length scales range from microns to tens or hundreds of meters. Thus, the study of fractured karst reservoirs is faced with a significant unresolved challenge in quantitatively characterizing the geometrical connectivity and hydraulic conductivity as well as their interrelationships in such strongly heterogeneous, multicomponent systems. In this paper, we propose an analytical formulation to characterize the connectivity of discrete fracture-cave networks building upon the excluded area concept of the percolation theory. By implementing a state-of-the-art computational model solving coupled Navier-Stokes (free flow) and Darcy (porous media flow) equations, we numerically derive the permeability of a fractured and karstified porous media, such that the relationship between the connectivity and permeability is further explored. The high-fidelity numerical model also permits us to elucidate the process of flow channelization within the fracture-cave network. The results show that the fracture-cave network connectivity correlates to the permeability via a power law scaling for connected systems. Significant flow channeling occurs around the percolation threshold where the flow is dominated by a limited number of preferential pathways. Caves play a crucial role in the flow due to the fact that caves could globally enhance the network connectivity and locally serve as hotspots for high fluid velocity. Finally, a semi-analytical permeability model for fractured karst reservoirs is developed. The results of our research and insights obtained have important implications for understanding the subsurface fluid flow in fractured karst reservoirs. [ABSTRACT FROM AUTHOR]

• An improved thermo-hydro-mechanical coupling model is developed. • Effects of shear dilation and thermal stress on heat extraction are investigated. • Effects of fracture properties and deviatoric stress on THM processes are studied. • Practically useful guidelines for developing sustainable EGSs are proposed. Shear dilation of fractures has been recognized as a main mechanism of permeability enhancement by hydraulic stimulation in Enhanced Geothermal Systems (EGSs); however, the interactive role of fracture shear dilation and thermo-hydro-mechanical (THM) coupling processes in long-term heat extraction performance of EGSs remains unclear. In this study, we develop a novel THM coupling model based on the discrete fracture network approach, which can realistically capture important processes including hybrid normal-shear deformation of fractures, thermal expansion of rocks, fluid flow in both fractures and rocks, and heat convection/conduction as well as local thermal non-equilibrium effect and changes in physical parameters of fluid. We quantitatively investigate the effects of fracture network geometries and geomechanical boundary constraints on fracture shear dilatancy, and the resulting heat transfer characteristics of EGSs. Numerical results reveal that shear dilation of fractures can be triggered by transient pore pressurization and thermal stress under anisotropic in-situ stress condition, and would severely engender flow channeling as well as anisotropic heat transfer, which strongly impact the heat extraction performance. The production temperature tends to be overestimated while the thermal production rate may be underestimated, if the shear dilatational behavior is not incorporated. Increased in-situ stress ratio and injection/production pressure would magnify the effects of shear dilation, and lead to considerable enhancement of fracture permeability, eventually resulting in much earlier and quicker temperature drop. Excessive increase of fracture density and the location of injection-production wells parallel to potential channelized flow paths, formed by intersected fractures preferentially oriented for shear sliding, tend to form short circulating flow paths and reduce the heat extraction performance. Our study demonstrates the importance of considering fracture shear dilation and fully-coupled THM behaviors when evaluating the long-term performance and efficiency of heat extraction in EGSs. [ABSTRACT FROM AUTHOR]

Water flooding is the most widely used method to enhance oil recovery. Simulating the influence of particle content on fluid flow in water flooding process can provide instructive significance for oilfield development. In this paper, a pore network model was established to simulate the transport process of particles in injected water and fallen particles from the reservoir. It was used to study the influence of particle blockage, deposition and migration on the clogged throats and changes of oil-water relative permeability curves. In the model, four parameters were set, fallen particle diameter, injected particle diameter, fallen particle number and injected particle number. Other parameters were fixed and only a variable was changed to explore the changeable rule of relative permeability curves. It can be generally noted that fallen particle changes have great influence on the relative permeability curves of oil phase and injected particle changes mainly affect the relative permeability curves of water phase. It is of great significance for oilfield development to study the influence of particle transportation on fluid seepage processes. • A pore network model containing particles was established. • A transport process of injected particles and fallen particles from the reservoir during water flooding was simulated. • The influence of particle blockage, deposition and migration on the clogged throats and oil-water relative permeability curves was studied. [ABSTRACT FROM AUTHOR]